NORMES DE FIABILITÉ DE LA NERC

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

AVRIL 2015

(VERSION ANGLAISE)

Original : 2015-01-30 HQCMÉ-13, Document 2

(En liasse)

S ta n d a rd BAL-001-0.1a — Re a l P owe r Ba la n c in g Co n tro l P e rfo rm a n c e

A. Introduction

1.

Title : Real Power Balancing Control Performance

2.

Number : BAL-001-0.1a

3.

Purpose : To maintain Interconnection steady-state frequency within defined limits by balancing real power demand and supply in real-time.

4.

Applicability :

4.1.

Balancing Authorities

5.

Effective Date:

B. Requirements

May 13, 2009

R1.

Each Balancing Authority shall operate such that, on a rolling 12-month basis, the average of the clock-minute averages of the Balancing Authority’s Area Control Error (ACE) divided by

10B (B is the clock-minute average of the Balancing Authority Area’s Frequency Bias) times the corresponding clock-minute averages of the Interconnection’s Frequency Error is less than a specific limit. This limit

ε

1

2

is a constant derived from a targeted frequency bound

(separately calculated for each Interconnection) that is reviewed and set as necessary by the

NERC Operating Committee.

AVG

Period



 









−

ACE i

10 B i







1

*

∆

F

1



 



The equation for ACE is:

≤∈

2

1 or

AVG

Period



 









−

ACE i

10 B i

∈

2

1







1

*

∆

F

1



 



≤

1

ACE = (NI

A

−

NI

S

)

−

10B (F

A

−

F

S

)

−

I

ME where:

•

NI

A

is the algebraic sum of actual flows on all tie lines.

•

NI

S

is the algebraic sum of scheduled flows on all tie lines.

•

B is the Frequency Bias Setting (MW/0.1 Hz) for the Balancing Authority. The constant factor 10 converts the frequency setting to MW/Hz.

•

F

A

is the actual frequency.

•

F

S

is the scheduled frequency. F

S

is normally 60 Hz but may be offset to effect manual time error corrections.

•

I

ME

is the meter error correction factor typically estimated from the difference between the integrated hourly average of the net tie line flows (NI

A

) and the hourly net interchange demand measurement (megawatt-hour). This term should normally be very small or zero.

R2.

Each Balancing Authority shall operate such that its average ACE for at least 90% of clockten-minute periods (6 non-overlapping periods per hour) during a calendar month is within a specific limit, referred to as L

10

.

AVG

10

− minute

( ACE i

)

≤

L

10

Adopted by the Régie de l'énergie (Decision D-2014-216): December 19, 2014 Page 1 of 7

S ta n d a rd BAL-001-0.1a — Re a l P owe r Ba la n c in g Co n tro l P e rfo rm a n c e where:

L

10

= 1 .

65

∈

10

(

−

10 B i

)(

−

10 B s

)

ε

10

is a constant derived from the targeted frequency bound. It is the targeted root-mean-square

(RMS) value of ten-minute average Frequency Error based on frequency performance over a given year. The bound,

ε

10

, is the same for every Balancing Authority Area within an

Interconnection, and B s

is the sum of the Frequency Bias Settings of the Balancing Authority

Areas in the respective Interconnection. For Balancing Authority Areas with variable bias, this is equal to the sum of the minimum Frequency Bias Settings.

R3.

Each Balancing Authority providing Overlap Regulation Service shall evaluate Requirement

R1 (i.e., Control Performance Standard 1 or CPS1) and Requirement R2 (i.e., Control

Performance Standard 2 or CPS2) using the characteristics of the combined ACE and combined Frequency Bias Settings.

R4.

Any Balancing Authority receiving Overlap Regulation Service shall not have its control performance evaluated (i.e. from a control performance perspective, the Balancing Authority has shifted all control requirements to the Balancing Authority providing Overlap Regulation

Service).

C. Measures

M1.

Each Balancing Authority shall achieve, as a minimum, Requirement 1 (CPS1) compliance of

100%.

CPS1 is calculated by converting a compliance ratio to a compliance percentage as follows:

CPS1 = (2 - CF) * 100%

The frequency-related compliance factor, CF, is a ratio of all one-minute compliance parameters accumulated over 12 months divided by the target frequency bound:

CF

=

CF

12

(

∈

1

− month

2

) where:

ε

1

is defined in Requirement R1.

The rating index CF

12-month

is derived from 12 months of data. The basic unit of data comes from one-minute averages of ACE, Frequency Error and Frequency Bias Settings.

A clock-minute average is the average of the reporting Balancing Authority’s valid measured variable (i.e., for ACE and for Frequency Error) for each sampling cycle during a given clockminute.

∑

ACE sampling cycles in clock minute

ACE n sampling cycles in clock minute =

−

10 B clock minute

10B

∆

F clock minute

=

∑ ∆

F sampling cycles in clock minute n sampling cycles in clock minute

The Balancing Authority’s clock-minute compliance factor (CF) becomes:



CF clock minute

=





−

ACE

10 B

 clock minute

*

∆

F clock minute





Normally, sixty (60) clock-minute averages of the reporting Balancing Authority’s ACE and of the respective Interconnection’s Frequency Error will be used to compute the respective hourly average compliance parameter.

CF clock hour

=

∑

CF clock minute n clock minute samples in hour

The reporting Balancing Authority shall be able to recalculate and store each of the respective clock-hour averages (CF clock-hour average-month) as well as the respective number of samples for each of the twenty-four (24) hours (one for each clock-hour, i.e., hour-ending (HE)

0100, HE 0200, ..., HE 2400).

CF clock hour average month

= days in

∑

[(CF clock

month

hour

)( n one minute samples in clock

∑

[ n one minute samples in clock days in month

hour

]

hour

)]

CF month

=

∑

day hours in

[(CF clock hour average month hours

∑

[

in day

)( n one minute samples in clock n one minute samples in clock hour averages

]

hour averages

)]

The 12-month compliance factor becomes:

CF

12 month

=

12 ∑ i

=

1

( CF month i

)( n ( one minute samples in month

)

− i

)] i

12 ∑

=

1

[ n

( one minute samples in month) i

]

In order to ensure that the average ACE and Frequency Deviation calculated for any oneminute interval is representative of that one-minute interval, it is necessary that at least 50% of both ACE and Frequency Deviation samples during that one-minute interval be present.

Should a sustained interruption in the recording of ACE or Frequency Deviation due to loss of telemetering or computer unavailability result in a one-minute interval not containing at least

50% of samples of both ACE and Frequency Deviation, that one-minute interval shall be excluded from the calculation of CPS1.

M2.

Each Balancing Authority shall achieve, as a minimum, Requirement R2 (CPS2) compliance of

90%. CPS2 relates to a bound on the ten-minute average of ACE. A compliance percentage is calculated as follows:

CPS 2

=





1

−

(

Total Periods

Violations month month

−

Unavailabl e Periods month

)



 * 100

The violations per month are a count of the number of periods that ACE clock-ten-minutes exceeded L

10

. ACE clock-ten-minutes is the sum of valid ACE samples within a clock-tenminute period divided by the number of valid samples.



Violation clock-ten-minutes

= 0 if

∑

ACE

≤

L

10 n samples in 10 minutes

= 1 if

∑

ACE

>

L

10 n samples in 10 minutes

Each Balancing Authority shall report the total number of violations and unavailable periods for the month. L

10

is defined in Requirement R2.

Since CPS2 requires that ACE be averaged over a discrete time period, the same factors that limit total periods per month will limit violations per month. The calculation of total periods per month and violations per month, therefore, must be discussed jointly.

A condition may arise which may impact the normal calculation of total periods per month and violations per month. This condition is a sustained interruption in the recording of ACE.

In order to ensure that the average ACE calculated for any ten-minute interval is representative of that ten-minute interval, it is necessary that at least half the ACE data samples are present for that interval. Should half or more of the ACE data be unavailable due to loss of telemetering or computer unavailability, that ten-minute interval shall be omitted from the calculation of CPS2.

D. Compliance

1.

Compliance Monitoring Process

1.1.

Compliance Monitoring Responsibility

Regional Reliability Organization.

1.2.

Compliance Monitoring Period and Reset Timeframe

One calendar month.

1.3.

Data Retention

The data that supports the calculation of CPS1 and CPS2 (Appendix 1-BAL-001-0) are to be retained in electronic form for at least a one-year period. If the CPS1 and CPS2 data for a Balancing Authority Area are undergoing a review to address a question that has been raised regarding the data, the data are to be saved beyond the normal retention period until the question is formally resolved. Each Balancing Authority shall retain for a rolling 12-month period the values of: one-minute average ACE (ACE i

), one-minute average Frequency Error, and, if using variable bias, one-minute average Frequency Bias.

1.4.

Additional Compliance Information

None.

2.

Levels of Non-Compliance – CPS1

2.1.

Level 1: The Balancing Authority Area’s value of CPS1 is less than 100% but greater than or equal to 95%.

2.2.




2.3.


2.4.

Level 4: The Balancing Authority Area’s value of CPS1 is less than 85%.

3.


3.1.


3.2.


3.3.


3.4.

Level 4:

E. Regional Differences

1.

The

The Balancing Authority Area’s value of CPS2 is less than 75%.

ERCOT Control Performance Standard 2 Waiver approved November 21, 2002.

F. Associated Documents

1.

Appendix 2



Interpretation of Requirement R1 (October 23, 2007).

Version History

Version

0

Date Action

February 8, 2005 BOT Approval

0 April 1, 2005 Effective Implementation Date

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

Change Tracking

New

New

Errata

0

0a

0a

0

0.1a

0.1a

July 24, 2007 Corrected R3 to reference M1 and M2 instead of R1 and R2

December 19, 2007 Added Appendix 2 – Interpretation of R1 approved by BOT on October 23, 2007

Errata

Revised

January 16, 2008 In Section A.2., Added “a” to end of standard number

In Section F, corrected automatic numbering from “2” to “1” and removed “approved” and added parenthesis to “(October 23, 2007)”

Errata

January 23, 2008 Reversed errata change from July 24, 2007 Errata

October 29, 2008 Board approved errata changes; updated version number to “0.1a”

Errata

May 13, 2009 Approved by FERC


CPS1 DATA

ε

1

ACE i

B i

F

S


F

A

Description

Appendix 1-BAL-001-0

CPS1 and CPS2 Data

Retention Requirements

Retain the value of

ε

1

used in CPS1 calculation. A constant derived from the targeted frequency bound. This number is the same for each

Balancing Authority Area in the

Interconnection.

The clock-minute average of ACE. Retain the 1-minute average values of ACE

(525,600 values).

The Frequency Bias of the Balancing Authority

Area.

The actual measured frequency.

Retain the value(s) of B i

used in the CPS1 calculation.

Retain the 1-minute average frequency values

(525,600 values).

Scheduled frequency for the Interconnection. Retain the 1-minute average frequency values

(525,600 values).

CPS2 DATA

V

ε

10

B i

B s

U

Description

Number of incidents per hour in which the absolute value of ACE clock-ten-minutes is greater than L

10

.

A constant derived from the frequency bound.

It is the same for each Balancing Authority

Area within an Interconnection.

Retention Requirements

Retain the values of V used in CPS2 calculation.

Retain the value of

ε calculation.

10

used in CPS2

The Frequency Bias of the Balancing Authority

Area.

Retain the value of B i

used in the CPS2 calculation.

The sum of Frequency Bias of the Balancing

Authority Areas in the respective

Interconnection. For systems with variable bias, this is equal to the sum of the minimum

Frequency Bias Setting.

Number of unavailable ten-minute periods per hour used in calculating CPS2.

Retain the value of B s

used in the CPS2 calculation. Retain the 1-minute minimum bias value (525,600 values).

Retain the number of 10-minute unavailable periods used in calculating CPS2 for the reporting period.



Appendix 2

Interpretation of Requirement 1

Request:

Does the WECC Automatic Time Error Control Procedure (WATEC) violate

Requirement 1 of BAL-001-0?

Interpretation:

Requirement 1 of BAL-001 — Real Power Balancing Control Performance, is the definition of the area control error (ACE) equation and the limits established for Control

Performance Standard 1 (CPS1).

BAL-001-0

R1.

Each Balancing Authority shall operate such that, on a rolling 12-month basis, the average of the clock-minute averages of the Balancing Authority’s Area Control Error (ACE) divided by 10B

(B is the clock-minute average of the Balancing Authority Area’s Frequency Bias) times the corresponding clock-minute averages of the Interconnection’s Frequency Error is less than a specific limit. This limit ε12 is a constant derived from a targeted frequency bound (separately calculated for each Interconnection) that is reviewed and set as necessary by the NERC

Operating Committee.



The WATEC procedural documents ask Balancing Authorities to maintain raw ACE for CPS reporting and to control via WATEC-adjusted ACE.



As long as Balancing Authorities use raw (unadjusted for WATEC) ACE for CPS reporting purposes, the use of WATEC for control is not in violation of BAL-001 Requirement 1.


Standard BAL-001-0.1a — Real Power Balancing Control Performance

Appendix QC-BAL-001-0.1a

Provisions specific to the standard BAL-001-0.1a 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: Real Power Balancing Control Performance

2.

Number: BAL-001-0.1a

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: December 19, 2014

5.2.

Adoption of the appendix by the Régie de l’énergie: December 19, 2014

5.3.

Effective date of the standard and its appendix in Québec: April 1, 2015

B. Requirements

No specific provision

C. Measures


D. Compliance

1.


1.1.

Compliance Monitoring Responsibility

The Régie de l’énergie is responsible, in Québec, for compliance monitoring with respect to the reliability standard and its appendix that it adopts.

1.2.



1.3.

Data Retention


1.4.



2.



3.





Adopted by the Régie de l’énergie (Decision D-2014-216): December 19, 2014 Page QC-1 of 2

Standard BAL-001-0.1a — Real Power Balancing Control Performance

Appendix QC-BAL-001-0.1a

Provisions specific to the standard BAL-001-0.1a applicable in Québec

F. Associated Documents


Appendix 1 – BAL-001-0


Appendix 2


Revision History

Revision

0

Adoption Date Action

December 19, 2014 New appendix

Change Tracking

New

Adopted by the Régie de l’énergie (Decision D-2014-216): December 19, 2014 Page QC-2 of 2

Standard BAL-002-1 — Disturbance Control Performance

A. Introduction

1.

Title: Disturbance Control Performance

2.

Number:

BAL-002-1

3.

Purpose:

The purpose of the Disturbance Control Standard (DCS) is to ensure the

Balancing Authority is able to utilize its Contingency Reserve to balance resources and demand and return Interconnection frequency within defined limits following a Reportable

Disturbance. Because generator failures are far more common than significant losses of load and because Contingency Reserve activation does not typically apply to the loss of load, the application of DCS is limited to the loss of supply and does not apply to the loss of load.

4.

Applicability:

4.1.

Balancing Authorities

4.2.

Reserve Sharing Groups (Balancing Authorities may meet the requirements of

Standard 002 through participation in a Reserve Sharing Group.)

4.3.

Regional Reliability Organizations

5.

(Proposed) Effective Date:

The first day of the first calendar quarter, one year after applicable regulatory approval; or in those jurisdictions where no regulatory approval is required, the first day of the first calendar quarter one year after Board of Trustees’ adoption.

B.

Requirements

R1.

Each Balancing Authority shall have access to and/or operate Contingency Reserve to respond to Disturbances. Contingency Reserve may be supplied from generation, controllable load resources, or coordinated adjustments to Interchange Schedules.

R1.1.

A Balancing Authority may elect to fulfill its Contingency Reserve obligations by participating as a member of a Reserve Sharing Group. In such cases, the Reserve

Sharing Group shall have the same responsibilities and obligations as each Balancing

Authority with respect to monitoring and meeting the requirements of Standard BAL-

002.

R2.

Each Regional Reliability Organization, sub-Regional Reliability Organization or Reserve

Sharing Group shall specify its Contingency Reserve policies, including:

R2.1.

The minimum reserve requirement for the group.

R2.2.

Its allocation among members.

R2.3.

The permissible mix of Operating Reserve – Spinning and Operating Reserve –

Supplemental that may be included in Contingency Reserve.

R2.4.

The procedure for applying Contingency Reserve in practice.

R2.5.

The limitations, if any, upon the amount of interruptible load that may be included.

R2.6.

The same portion of resource capacity (e.g. reserves from jointly owned generation) shall not be counted more than once as Contingency Reserve by multiple Balancing

Authorities.

R3.

Each Balancing Authority or Reserve Sharing Group shall activate sufficient Contingency

Reserve to comply with the DCS.

R3.1.

As a minimum, the Balancing Authority or Reserve Sharing Group shall carry at least enough Contingency Reserve to cover the most severe single contingency. All

Balancing Authorities and Reserve Sharing Groups shall review, no less frequently

Adopted by Board of Trustees: August 5, 2010

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

1

Standard BAL-002-1 — Disturbance Control Performance than annually, their probable contingencies to determine their prospective most severe single contingencies.

R4.

A Balancing Authority or Reserve Sharing Group shall meet the Disturbance Recovery

Criterion within the Disturbance Recovery Period for 100% of Reportable Disturbances. The

Disturbance Recovery Criterion is:

R4.1.

A Balancing Authority shall return its ACE to zero if its ACE just prior to the

Reportable Disturbance was positive or equal to zero. For negative initial ACE values just prior to the Disturbance, the Balancing Authority shall return ACE to its pre-

Disturbance value.

R4.2.

The default Disturbance Recovery Period is 15 minutes after the start of a Reportable

Disturbance.

R5.

Each Reserve Sharing Group shall comply with the DCS. A Reserve Sharing Group shall be considered in a Reportable Disturbance condition whenever a group member has experienced a Reportable Disturbance and calls for the activation of Contingency Reserves from one or more other group members. (If a group member has experienced a Reportable Disturbance but does not call for reserve activation from other members of the Reserve Sharing Group, then that member shall report as a single Balancing Authority.) Compliance may be demonstrated by either of the following two methods:

R5.1.

The Reserve Sharing Group reviews group ACE (or equivalent) and demonstrates compliance to the DCS. To be in compliance, the group ACE (or its equivalent) must meet the Disturbance Recovery Criterion after the schedule change(s) related to reserve sharing have been fully implemented, and within the Disturbance Recovery Period. or

R5.2.

The Reserve Sharing Group reviews each member’s ACE in response to the activation of reserves. To be in compliance, a member’s ACE (or its equivalent) must meet the

Disturbance Recovery Criterion after the schedule change(s) related to reserve sharing have been fully implemented, and within the Disturbance Recovery Period.

R6.

A Balancing Authority or Reserve Sharing Group shall fully restore its Contingency Reserves within the Contingency Reserve Restoration Period for its Interconnection.

R6.1.

The Contingency Reserve Restoration Period begins at the end of the Disturbance

Recovery Period.

R6.2.

The default Contingency Reserve Restoration Period is 90 minutes.

C.

Measures

M1.

A Balancing Authority or Reserve Sharing Group shall calculate and report compliance with the Disturbance Control Standard for all Disturbances greater than or equal to 80% of the magnitude of the Balancing Authority’s or of the Reserve Sharing Group’s most severe single contingency loss. Regions may, at their discretion, require a lower reporting threshold.

). Disturbance Control Standard is measured as the percentage recovery (R i

For loss of generation: if ACE then

A

< 0



2


R i

=

MW

Loss

− max( 0 ,

ACE

A

MW

Loss

−

ACE

M

)

* 100 % if ACE

A

> 0 then

R i

=

MW

Loss

− max( 0

MW

Loss

, −

ACE

M

)

* 100 % where:

• MW

LOSS

is the MW size of the Disturbance as measured at the beginning of the loss,

• ACE

• ACE

A

M

is the pre-disturbance ACE,

is the maximum algebraic value of ACE measured within the fifteen minutes following the Disturbance. A Balancing Authority or Reserve Sharing Group may, at its discretion, set ACE

M

= ACE

15 min

, and

The Balancing Authority or Reserve Sharing Group shall record the MW

LOSS

value as measured at the site of the loss to the extent possible. The value should not be measured as a change in ACE since governor response and AGC response may introduce error.

-80

-40

The Balancing Authority or Reserve Sharing Group shall base the value for ACE

A

on the average ACE over the period just prior to the start of the Disturbance (10 and 60 seconds prior and including at least 4 scans of ACE). In the illustration below, the horizontal line represents an averaging of ACE for 15 seconds prior to the start of the Disturbance with a result of ACE

A

ACE

= - 25 MW.

0

-30 -20 -10 0

The average percent recovery is the arithmetic average of all the calculated R excludable Disturbances. i

’s for Reportable

Disturbances during a given quarter. Average percent recovery is similarly calculated for

D.

Compliance

1.




3


Compliance with the DCS shall be measured on a percentage basis as set forth in the measures above.

Each Balancing Authority or Reserve Sharing Group shall submit one completed copy of DCS

Form, “NERC Control Performance Standard Survey – All Interconnections” to its Resources

Subcommittee Survey Contact no later than the 10th day following the end of the calendar quarter (i.e. April 10th, July 10th, October 10th, January 10th). The Regional Entity must submit a summary document reporting compliance with DCS to NERC no later than the 20 th day of the month following the end of the quarter.

1.1.

Compliance Enforcement Authority

Regional Entity.

1.2.


Compliance for DCS will be evaluated for each reporting period. Reset is one calendar quarter without a violation.

1.3.

Compliance Monitoring and Enforcement Processes:

Compliance Audits

Self-Certifications

Spot Checking

Compliance Violation Investigations

Self-Reporting

Complaints

1.4.

Data Retention

The data that support the calculation of DCS are to be retained in electronic form for at least a one-year period. If the DCS data for a Reserve Sharing Group and Balancing

Area are undergoing a review to address a question that has been raised regarding the data, the data are to be saved beyond the normal retention period until the question is formally resolved.

1.5.


Reportable Disturbances

– Reportable Disturbances are contingencies that are greater than or equal to 80% of the most severe single Contingency. A Regional Reliability

Organization, sub-Regional Reliability Organization or Reserve Sharing Group may optionally reduce the 80% threshold, provided that normal operating characteristics are not being considered or misrepresented as contingencies. Normal operating characteristics are excluded because DCS only measures the recovery from sudden, unanticipated losses of supply-side resources.

Simultaneous Contingencies

– Multiple Contingencies occurring within one minute or less of each other shall be treated as a single Contingency. If the combined magnitude of the multiple Contingencies exceeds the most severe single Contingency, the loss shall be reported, but excluded from compliance evaluation.

Multiple Contingencies within the Reportable Disturbance Period

– Additional

Contingencies that occur after one minute of the start of a Reportable Disturbance but before the end of the Disturbance Recovery Period can be excluded from evaluation.

The Balancing Authority or Reserve Sharing Group shall determine the DCS compliance of the initial Reportable Disturbance by performing a reasonable



4

Standard BAL-002-1 — Disturbance Control Performance estimation of the response that would have occurred had the second and subsequent contingencies not occurred.

Multiple Contingencies within the Contingency Reserve Restoration Period

–

Additional Reportable Disturbances that occur after the end of the Disturbance

Recovery Period but before the end of the Contingency Reserve Restoration Period shall be reported and included in the compliance evaluation. However, the Balancing

Authority or Reserve Sharing Group can request a waiver from the Resources

Subcommittee for the event if the contingency reserves were rendered inadequate by prior contingencies and a good faith effort to replace contingency reserve can be shown.

2.

Levels of Non-Compliance

Each Balancing Authority or Reserve Sharing Group not meeting the DCS during a given calendar quarter shall increase its Contingency Reserve obligation for the calendar quarter

(offset by one month) following the evaluation by the NERC or Compliance Monitor [e.g. for the first calendar quarter of the year, the penalty is applied for May, June, and July.] The increase shall be directly proportional to the non-compliance with the DCS in the preceding quarter. This adjustment is not compounded across quarters, and is an additional percentage of reserve needed beyond the most severe single Contingency. A Reserve Sharing Group may choose an allocation method for increasing its Contingency Reserve for the Reserve Sharing

Group provided that this increase is fully allocated.

A representative from each Balancing Authority or Reserve Sharing Group that was noncompliant in the calendar quarter most recently completed shall provide written documentation verifying that the Balancing Authority or Reserve Sharing Group will apply the appropriate DCS performance adjustment beginning the first day of the succeeding month, and will continue to apply it for three months. The written documentation shall accompany the quarterly Disturbance Control Standard Report when a Balancing Authority or Reserve

Sharing Group is non-compliant.

3.

Violation Severity Levels (no changes)

E.

Regional Differences

None identified.

Version History

Version

0

0

0

1

Date Action Change Tracking

April 1, 2005 Effective Date New

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

February 14,

2006

TBD

Revised graph on page 3, “10 min.” to

“Recovery time.” Removed fourth bullet.

Modified to address Order No. 693

Directives contained in paragraph 321.

Errata

Revised.



5


Appendix QC-BAL-002-1

Provisions specific to the standard BAL-002-1 applicable in Québec


A. Introduction

1.

Title: Disturbance Control Performance

2.

Number: BAL-002-1

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.

Compliance Enforcement Authority

The Régie de l’énergie is responsible, in Québec, for compliance enforcement with respect to the reliability standard and its appendix that it adopts.

The NERC remains responsible for compliance monitoring of the Regional Reliability

Organization.

1.2.



1.3.

Compliance Monitoring and Enforcement Processes


1.4.

Data Retention


1.5.



2.



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




3.

Violation Severity Levels

Requirement Lower Moderate High

R1 N/A N/A

Severe

The Balancing Authority did not operate Contingency Reserve to respond to a Disturbance.

The Balancing Authority did not have access to Contingency

Reserve to respond to a

Disturbance.

R1.1 N/A N/A N/A

R2

R2.1

The Regional Reliability

Organization, sub-Regional

Reliability Organization, or

Reserve Sharing Group has failed to specify 1 of the following sub-requirements.

N/A




Reserve Sharing Group has failed to specify 2 or 3 of the following sub-requirements.

N/A




Reserve Sharing Group has failed to specify 4 or 5 of the following sub-requirements.

N/A

The Balancing Authority has elected to fulfill its Contingency

Reserve obligations by participating as a member of a

Reserve Sharing Group and the

Reserve Sharing Group has not provided the same responsibilities and obligations as required of the responsible entity with respect to monitoring and meeting the requirements of Standard BAL-

002.




Reserve Sharing Group has failed to specify all 6 of the following sub-requirements.




Reserve Sharing Group has failed to specify the minimum reserve requirement for the group.





Requirement

R2.2 N/A

Lower

N/A

Moderate

N/A

High

R2.3

R2.4

R2.5

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

Severe




Reserve Sharing Group has failed to specify the allocation of reserves among members.




Reserve Sharing Group has failed to specify the permissible mix of Operating Reserve –

Spinning and Operating Reserve

– Supplemental that may be included in Contingency

Reserve.




Reserve Sharing Group has failed to provide the procedure for applying Contingency

Reserve in practice.




Reserve Sharing Group has failed to specify the limitations, if any, upon the amount of interruptible load that may be included.





Requirement

R2.6

R3

R3.1

N/A

Lower

N/A

Moderate

N/A

High Severe




Reserve Sharing Group has allowed the same portion of resource capacity (e.g., reserves from jointly owned generation) to be counted more than once as

Contingency Reserve by multiple Balancing Authorities.

The Balancing Authority or

Reserve Sharing Group’s average percent recovery per the

NERC DCS quarterly report was less than 100% but greater than or equal to 95%.

OR


Reserve Sharing Group failed to review its probable contingencies to determine its prospective most severe single contingencies annually as specified in R3.1.









NERC DCS quarterly report was less than 85%.

OR


Reserve Sharing Group failed to carry at least enough

Contingency Reserve to cover the most severe single contingency as specified in

R3.1.

N/A N/A N/A N/A





Requirement

R4

Lower Moderate High Severe


Reserve Sharing Group met the

Disturbance Recovery Criterion within the Disturbance

Recovery Period for more than

90% and less than 100% of

Reportable Disturbances.





80% and less than or equal to

90% of Reportable

Disturbances.






80% of Reportable

Disturbances.






70% of Reportable

Disturbances.

R4.1

R4.2

R5

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

The Reserve Sharing Group met the DCS requirement for more than 90% and less than 100% of

Reportable Disturbances.

The Reserve Sharing Group met the DCS requirements for more than 80% and less than or equal to 90% of Reportable

Disturbances.


Disturbances.


Disturbances.

R5.1

R5.2

R6

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A


Reserve Sharing Group failed to restore 5% or less of its contingency reserves during the

Contingency Reserve

Restoration Period.


Reserve Sharing Group failed to restore more than 5% up to (and including) 10% of its contingency reserves during the

Contingency Reserve

Restoration Period.


Reserve Sharing Group failed to restore more than 10% up to

(and including) 15% of its

Contingency Reserve during the

Contingency Reserve

Restoration Period.


Reserve Sharing Group failed to restore more than 15% of its

Contingency Reserves during the Contingency Reserve

Restoration Period.

R6.1

R6.2

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A








Revision Adoption Date Action

0 October 30, 2013 New appendix

Change Tracking

New


S ta n d a rd BAL-006-2 — In a d ve rte n t In te rc h a n g e

A.

Introduction

1.

Title: Inadvertent Interchange

2.

Number: BAL-006-2

3.

Purpose:

This standard defines a process for monitoring Balancing Authorities to ensure that, over the long term, Balancing Authority Areas do not excessively depend on other Balancing Authority

Areas in the Interconnection for meeting their demand or Interchange obligations.

4.

Applicability:

4.1.

Balancing Authorities.

5.

Effective Date: First day of first calendar quarter after applicable regulatory approval, or in those jurisdictions where no regulatory approval is required, first day of first calendar quarter after Board of Trustees adoption.

B.

Requirements

R1.

Each Balancing Authority shall calculate and record hourly Inadvertent Interchange.

( Violation Risk Factor: Lower )

R2.

Each Balancing Authority shall include all AC tie lines that connect to its Adjacent Balancing

Authority Areas in its Inadvertent Interchange account. The Balancing Authority shall take into account interchange served by jointly owned generators. ( Violation Risk Factor: Lower )

R3.

Each Balancing Authority shall ensure all of its Balancing Authority Area interconnection points are equipped with common megawatt-hour meters, with readings provided hourly to the control centers of Adjacent Balancing Authorities. ( Violation Risk Factor: Lower )

R4.

Adjacent Balancing Authority Areas shall operate to a common Net Interchange Schedule and

Actual Net Interchange value and shall record these hourly quantities, with like values but opposite sign. Each Balancing Authority shall compute its Inadvertent Interchange based on the following: ( Violation Risk Factor: Lower )

R4.1.

Each Balancing Authority, by the end of the next business day, shall agree with its

Adjacent Balancing Authorities to: ( Violation Risk Factor: Lower )

R4.1.1.

The hourly values of Net Interchange Schedule. ( Violation Risk Factor:

Lower )

R4.1.2.

The hourly integrated megawatt-hour values of Net Actual Interchange.


R4.2.

Each Balancing Authority shall use the agreed-to daily and monthly accounting data to compile its monthly accumulated Inadvertent Interchange for the On-Peak and Off-

Peak hours of the month. ( Violation Risk Factor: Lower )

R4.3.

A Balancing Authority shall make after-the-fact corrections to the agreed-to daily and monthly accounting data only as needed to reflect actual operating conditions (e.g. a meter being used for control was sending bad data). Changes or corrections based on non-reliability considerations shall not be reflected in the Balancing Authority’s

Inadvertent Interchange. After-the-fact corrections to scheduled or actual values will not be accepted without agreement of the Adjacent Balancing Authority(ies).


R5.

Adjacent Balancing Authorities that cannot mutually agree upon their respective Net Actual

Interchange or Net Scheduled Interchange quantities by the 15th calendar day of the following

Approved by the Board of Trustees: November 5, 2009


1

S ta n d a rd BAL-006-2 — In a d ve rte n t In te rc h a n g e month shall, for the purposes of dispute resolution, submit a report to their respective Regional

Reliability Organization Survey Contact. The report shall describe the nature and the cause of the dispute as well as a process for correcting the discrepancy. ( Violation Risk Factor: Lower )

C.

Measures

None specified.

D.

Compliance

1.


1.1.

Each Balancing Authority shall submit a monthly summary of Inadvertent Interchange.

These summaries shall not include any after-the-fact changes that were not agreed to by the Source Balancing Authority, Sink Balancing Authority and all Intermediate

Balancing Authority(ies).

1.2.

Inadvertent Interchange summaries shall include at least the previous accumulation, net accumulation for the month, and final net accumulation, for both the On-Peak and Off-

Peak periods.

1.3.

Each Balancing Authority shall submit its monthly summary report to its Regional

Reliability Organization Survey Contact by the 15th calendar day of the following month.

1.4.

Each Balancing Authority shall perform an Area Interchange Error (AIE) Survey as requested by the NERC Operating Committee to determine the Balancing Authority’s

Interchange error(s) due to equipment failures or improper scheduling operations, or improper AGC performance.

1.5.

Each Regional Reliability Organization shall prepare a monthly Inadvertent

Interchange summary to monitor the Balancing Authorities’ monthly Inadvertent

Interchange and all-time accumulated Inadvertent Interchange. Each Regional

Reliability Organization shall submit a monthly accounting to NERC by the 22nd day following the end of the month being summarized.



2


R#

R1.

2.


Lower VSL

N/A

R2.

R3.

N/A

N/A

R4. The Balancing Authority failed to record Actual Net Interchange values that are equal but opposite in sign to its Adjacent Balancing

Authorities.

R4.1. N/A

N/A

N/A

N/A

Moderate VSL

The Balancing Authority failed to compute Inadvertent Interchange.

N/A

N/A

High VSL

The Balancing Authority failed to include all AC tie lines that connect to its Adjacent Balancing

Authority Areas in its Inadvertent

Interchange account.

OR

Failed to take into account interchange served by jointly owned generators.

N/A

Severe VSL

Each Balancing Authority failed to calculate and record hourly

Inadvertent Interchange.

The Balancing Authority failed to include all AC tie lines that connect to its Adjacent Balancing

Authority Areas in its Inadvertent

Interchange account.

AND

Failed to take into account interchange served by jointly owned generators.

The Balancing Authority failed to ensure all of its Balancing

Authority Area interconnection points are equipped with common megawatt-hour meters, with readings provided hourly to the control centers of Adjacent


N/A The Balancing Authority failed to operate to a common Net

Interchange Schedule that is equal but opposite to its Adjacent


N/A The Balancing Authority, by the end of the next business day, failed to agree with its Adjacent

Balancing Authorities to the hourly values of Net Interchanged



3


R# Lower VSL Moderate VSL

R4.1.1. N/A

R4.1.2. N/A

R4.2. N/A

R4.3. N/A

N/A

N/A

N/A

N/A



N/A

N/A

N/A

N/A

High VSL Severe VSL

Schedule.

AND

The hourly integrated megawatthour values of Net Actual

Interchange.

The Balancing Authority, by the end of the next business day, failed to agree with its Adjacent

Balancing Authorities to the hourly values of Net Interchanged

Schedule.

The Balancing Authority, by the end of the next business day, failed to agree with its Adjacent

Balancing Authorities to the hourly integrated megawatt-hour values of

Net Actual Interchange.

The Balancing Authority failed to use the agreed-to daily and monthly accounting data to compile its monthly accumulated

Inadvertent Interchange for the On-

Peak and Off-Peak hours of the month.

The Balancing Authority failed to make after-the-fact corrections to the agreed-to daily and monthly accounting data to reflect actual operating conditions or changes or corrections based on non-reliability considerations were reflected in the

Balancing Authority’s Inadvertent

4


R# Lower VSL Moderate VSL

R5. Adjacent Balancing Authorities that could not mutually agree upon their respective Net Actual

Interchange or Net Scheduled

Interchange quantities, submitted a report to their respective Regional

Reliability Organizations Survey

Contact describing the nature and the cause of the dispute but failed to provide a process for correcting the discrepancy.

Adjacent Balancing Authorities that could not mutually agree upon their respective Net Actual

Interchange or Net Scheduled

Interchange quantities by the 15th calendar day of the following month, failed to submit a report to their respective Regional

Reliability Organizations Survey

Contact describing the nature and the cause of the dispute as well as a process for correcting the discrepancy.

N/A

High VSL Severe VSL

Interchange.

N/A



5


E.


1.

Inadvertent Interchange Accounting Waiver approved by the Operating Committee on March

25, 2004includes SPP effective May 1, 2006.

Version History

Version Date Action Change Tracking

0 April 1, 2005 Effective Date New

0

1

August 8, 2005

April 6, 2006

Removed “Proposed” from Effective Date Errata

Added following to “Effective Date:” This standard will expire for one year beyond the effective date or when replaced by a new version of BAL-006, whichever comes first.

Errata

2 Revision

2

2

November 5, 2009 Added approved VRFs and VSLs to document.

Removed MISO from list of entities with an

Inadvertent Interchange Accounting Waiver

(Project 2009-18).

November 5, 2009 Approved by the Board of Trustees

January 6, 2011 Approved by FERC



6

Standard BAL-006-2 — Inadvertent Interchange




A. Introduction

1.

Title: Inadvertent Interchange

2.

Number: BAL-006-2

3.


4.


5.

Effective Date:

5.1.


5.2.


5.3.


B. Requirements


C. Measures


D. Compliance

1.



2.








Change Tracking

New


Standard COM-001-1.1 — Telecommunications

A. Introduction

1.

Title: Telecommunications

2.

Number:

COM-001-1.1

3.

Purpose:

Each Reliability Coordinator, Transmission Operator and Balancing Authority needs adequate and reliable telecommunications facilities internally and with others for the exchange of Interconnection and operating information necessary to maintain reliability.

4.

Applicability

5.

4.1.

Transmission Operators.

4.2.


4.3.

Reliability Coordinators.

4.4.

NERCNet User Organizations.

Effective Date:

May 13, 2009

B. Requirements

R1.

Each Reliability Coordinator, Transmission Operator and Balancing Authority shall provide adequate and reliable telecommunications facilities for the exchange of Interconnection and operating information:

R1.1.

Internally.

R1.2.

Between the Reliability Coordinator and its Transmission Operators and Balancing

Authorities.

R1.3.

With other Reliability Coordinators, Transmission Operators, and Balancing

Authorities as necessary to maintain reliability.

R1.4.

Where applicable, these facilities shall be redundant and diversely routed.

R2.

Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall manage, alarm, test and/or actively monitor vital telecommunications facilities. Special attention shall be given to emergency telecommunications facilities and equipment not used for routine communications.

R3.

Each Reliability Coordinator, Transmission Operator and Balancing Authority shall provide a means to coordinate telecommunications among their respective areas. This coordination shall include the ability to investigate and recommend solutions to telecommunications problems within the area and with other areas.

R4.

Unless agreed to otherwise, each Reliability Coordinator, Transmission Operator, and

Balancing Authority shall use English as the language for all communications between and among operating personnel responsible for the real-time generation control and operation of the interconnected Bulk Electric System. Transmission Operators and Balancing Authorities may use an alternate language for internal operations.

R5.

Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall have written operating instructions and procedures to enable continued operation of the system during the loss of telecommunications facilities.

R6.

Each NERCNet User Organization shall adhere to the requirements in Attachment 1-COM-

001, “NERCNet Security Policy.”

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


C. Measures

M1.

Each Reliability Coordinator, Transmission Operator and Balancing Authority shall have and provide upon request evidence that could include, but is not limited to communication facility test-procedure documents, records of testing, and maintenance records for communication facilities or equivalent that will be used to confirm that it manages, alarms, tests and/or actively monitors vital telecommunications facilities. (Requirement 2 part 1)

M2.

The Reliability Coordinator, Transmission Operator or Balancing Authority 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 equivalent, that will be used to determine compliance to Requirement 4.

M3.

Each Reliability Coordinator, Transmission Operator and Balancing Authority shall have and provide upon request its current operating instructions and procedures, either electronic or hard copy that will be used to confirm that it meets Requirement 5.

M4.

The NERCnet User Organization shall have and provide upon request evidence that could include, but is not limited to documented procedures, operator logs, voice recordings or transcripts of voice recordings, electronic communications, etc that will be used to determine if it adhered to the (User Accountability and Compliance) requirements in Attachment 1-COM-

001. (Requirement 6)

D. Compliance

1.


1.1.


NERC shall be responsible for compliance monitoring of the Regional Reliability Organizations

Regional Reliability Organizations shall be responsible for compliance monitoring of all other entities

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 calendar 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.)

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

1.3.

Data Retention

For Measure 1 each Reliability Coordinator, Transmission Operator, Balancing Authority shall keep evidence of compliance for the previous two calendar years plus the current year.

For Measure 2 each Reliability Coordinator, Transmission Operator, and Balancing

Authority shall keep 90 days of historical data (evidence).



For Measure 3, each Reliability Coordinator, Transmission Operator, Balancing

Authority shall have its current operating instructions and procedures to confirm that it meets Requirement 5.

For Measure 4, each Reliability Coordinator, Transmission Operator, Balancing Authority and NERCnet User Organization shall keep 90 days of historical data (evidence).

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.


Attachment 1  COM-001 — NERCnet Security Policy

2.

Levels of Non-Compliance for Transmission Operator, Balancing Authority or Reliability

Coordinator

2.1.

Level 1:

Not applicable.

2.2.

Level 2:

Not applicable.

2.3.

Level 3:

There shall be a separate Level 3 non-compliance, for every one of the following requirements that is in violation:

2.3.1

The Transmission Operator, Balancing Authority or Reliability Coordinator used a language other then English without agreement as specified in R4.

2.3.2

There are no written operating instructions and procedures to enable continued operation of the system during the loss of telecommunication facilities as specified in R5.

2.4.

Level 4:

Telecommunication systems are not actively monitored, tested, managed or alarmed as specified in R2.

3.

Levels of Non-Compliance — NERCnet User Organization

3.1.

Level 1:

Not applicable.

3.2.

Level 2:

Not applicable.

3.3.

Level 3:

Not applicable.

3.4.

Level 4:

Did not adhere to the requirements in Attachment 1-COM-001, NERCnet

Security Policy.


None Identified.

Version History

Version Date

0

0

April 1, 2005

August 8, 2005

Action Change Tracking

Effective Date New

Removed “Proposed” from Effective Date Errata



1

1

1.1

November 1, 2006

April 6, 2007

October 29, 2008

Adopted by Board of Trustees

Requirement 1, added the word “for” between “facilities” and “the exchange.”

BOT adopted errata changes; updated version number to “1.1”

Revised

Errata

Errata



Attachment 1



COM-001 — NERCnet Security Policy

Policy Statement

The purpose of this NERCnet Security Policy is to establish responsibilities and minimum requirements for the protection of information assets, computer systems and facilities of NERC and other users of the

NERC frame relay network known as “NERCnet.” The goal of this policy is to prevent misuse and loss of assets.

For the purpose of this document, information assets shall be defined as processed or unprocessed data using the NERCnet Telecommunications Facilities including network documentation. This policy shall also apply as appropriate to employees and agents of other corporations or organizations that may be directly or indirectly granted access to information associated with NERCnet.

The objectives of the NERCnet Security Policy are:

• To ensure that NERCnet information assets are adequately protected on a cost-effective basis and to a level that allows NERC to fulfill its mission.

• To establish connectivity guidelines for a minimum level of security for the network.

• To provide a mandate to all Users of NERCnet to properly handle and protect the information that they have access to in order for NERC to be able to properly conduct its business and provide services to its customers.

NERC’s Security Mission Statement

NERC recognizes its dependency on data, information, and the computer systems used to facilitate effective operation of its business and fulfillment of its mission. NERC also recognizes the value of the information maintained and provided to its members and others authorized to have access to NERCnet. It is, therefore, essential that this data, information, and computer systems, and the manual and technical infrastructure that supports it, are secure from destruction, corruption, unauthorized access, and accidental or deliberate breach of confidentiality.

Implementation and Responsibilities

This section identifies the various roles and responsibilities related to the protection of NERCnet resources.

NERCnet User Organizations

Users of NERCnet who have received authorization from NERC to access the NERC network are considered users of NERCnet resources. To be granted access, users shall complete a User Application

Form and submit this form to the NERC Telecommunications Manager.

Responsibilities

It is the responsibility of NERCnet User Organizations to:

• Use NERCnet facilities for NERC-authorized business purposes only.

• Comply with the NERCnet security policies, standards, and guidelines, as well as any procedures specified by the data owner.

• Prevent unauthorized disclosure of the data.

• Report security exposures, misuse, or non-compliance situations via Reliability Coordinator

Information System or the NERC Telecommunications Manager.

• Protect the confidentiality of all user IDs and passwords.

• Maintain the data they own.

• Maintain documentation identifying the users who are granted access to NERCnet data or applications.

• Authorize users within their organizations to access NERCnet data and applications.



• Advise staff on NERCnet Security Policy.

• Ensure that all NERCnet users understand their obligation to protect these assets.

• Conduct self-assessments for compliance.

User Accountability and Compliance

All users of NERCnet shall be familiar and ensure compliance with the policies in this document.

Violations of the NERCnet Security Policy shall include, but not be limited to any act that:

• Exposes NERC or any user of NERCnet to actual or potential monetary loss through the compromise of data security or damage.

• Involves the disclosure of trade secrets, intellectual property, confidential information or the unauthorized use of data.

Involves the use of data for illicit purposes, which may include violation of any law, regulation or reporting requirement of any law enforcement or government body.



Appendix QC-COM-001-1.1

Provisions specific to the standard COM-001-1.1 applicable in Québec


A. Introduction

1.

Title: Telecommunications

2.

Number: COM-001-1.1

3.


4.


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 Transmission Operator, Balancing Authority or

Reliability Coordinator


3.

Levels of Non-Compliance — NERCnet User Organization




Appendix QC-COM-001-1.1

Provisions specific to the standard COM-001-1.1 applicable in Québec



Attachment 1-COM-001



Revision Adoption Date

0 October 30, 2013

Action

New appendix

Change Tracking

New


Standard EOP-001-2.1b — Emergency Operations Planning

A.

Introduction

1.

Title: Emergency Operations Planning

2.

Number:

EOP-001-2.1b

3.

Purpose:

Each Transmission Operator and Balancing Authority needs to develop, maintain, and implement a set of plans to mitigate operating emergencies. These plans need to be coordinated with other Transmission Operators and Balancing Authorities, and the

Reliability Coordinator.

4.

Applicability

4.1.


4.2.


5.

Proposed Effective Date:

Twenty-four months after the first day of the first calendar quarter following applicable regulatory approval. In those jurisdictions where no regulatory approval is required, all requirements go into effect twenty-four months after Board of Trustees adoption.

B.

Requirements

R1.

Balancing Authorities shall have operating agreements with adjacent Balancing Authorities that shall, at a minimum, contain provisions for emergency assistance, including provisions to obtain emergency assistance from remote Balancing Authorities.

R2.

Each Transmission Operator and Balancing Authority shall:

R2.1.

Develop, maintain, and implement a set of plans to mitigate operating emergencies for insufficient generating capacity.

R2.2.

Develop, maintain, and implement a set of plans to mitigate operating emergencies on the transmission system.

R2.3.

Develop, maintain, and implement a set of plans for load shedding.

R3.

Each Transmission Operator and Balancing Authority shall have emergency plans that will enable it to mitigate operating emergencies. At a minimum, Transmission Operator and

Balancing Authority emergency plans shall include:

R3.1.

Communications protocols to be used during emergencies.

R3.2.

A list of controlling actions to resolve the emergency. Load reduction, in sufficient quantity to resolve the emergency within NERC-established timelines, shall be one of the controlling actions.

R3.3.

The tasks to be coordinated with and among adjacent Transmission Operators and


R3.4.

Staffing levels for the emergency.

R4.

Each Transmission Operator and Balancing Authority shall include the applicable elements in

Attachment 1-EOP-001 when developing an emergency plan.

R5.

The Transmission Operator and Balancing Authority shall annually review and update each emergency plan. The Transmission Operator and Balancing Authority shall provide a copy of its updated emergency plans to its Reliability Coordinator and to neighboring Transmission

Operators and Balancing Authorities.

Adopted by the Régie de l'énergie (Decision D-2013-176): October 30, 2013 1


R6.

The Transmission Operator and Balancing Authority shall coordinate its emergency plans with other Transmission Operators and Balancing Authorities as appropriate. This coordination includes the following steps, as applicable:

R6.1.

The Transmission Operator and Balancing Authority shall establish and maintain reliable communications between interconnected systems.

R6.2.

The Transmission Operator and Balancing Authority shall arrange new interchange agreements to provide for emergency capacity or energy transfers if existing agreements cannot be used.

R6.3.

The Transmission Operator and Balancing Authority shall coordinate transmission and generator maintenance schedules to maximize capacity or conserve the fuel in short supply. (This includes water for hydro generators.)

R6.4.

The Transmission Operator and Balancing Authority shall arrange deliveries of electrical energy or fuel from remote systems through normal operating channels.

C.

Measures

M1.

The Transmission Operator and Balancing Authority shall have its emergency plans available for review by the Regional Reliability Organization at all times.

M2.

The Transmission Operator and Balancing Authority shall have its two most recent annual selfassessments available for review by the Regional Reliability Organization at all times.

D.

Compliance

1.


1.1.


Regional Reliability Organization.

1.2.

Compliance Monitoring Period and Reset Time Frame

The Regional Reliability Organization shall review and evaluate emergency plans every three years to ensure that the plans consider the applicable elements of Attachment 1-

EOP-001.

The Regional Reliability Organization may elect to request self-certification of the

Transmission Operator and Balancing Authority in years that the full review is not done.

Reset: one calendar year.

1.3.

Data Retention

Current plan available at all times.

1.4.


Not specified.

Adopted by the Régie de l'énergie (Decision D-2013-176): October 30, 2013 2


Requirement

R1

R2

2.

Violation Severity Levels:

R2.1

Lower

The Balancing Authority failed to demonstrate the existence of the necessary operating agreements for less than 25% of the adjacent

BAs.

Or less than 25% of those agreements do not contain provisions for emergency assistance.

The Transmission Operator or

Balancing Authority failed to comply with one (1) of the sub-components.


Balancing Authority’s emergency plans to mitigate insufficient generating capacity are missing minor details or minor program/procedural elements.

R2.2 The Transmission Operator or

Balancing Authority’s plans to mitigate transmission system emergencies are missing minor details or minor program/procedural elements.

Moderate

The Balancing Authority failed to demonstrate the existence of the necessary operating agreements for 25% to 50% of the adjacent BAs.

Or 25 to 50% of those agreements do not contain provisions for emergency assistance.


Balancing Authority failed to comply with two (2) of the sub-components.


Balancing Authority's has demonstrated the existence of emergency plans to mitigate insufficient generating capacity emergency plans but the plans are not maintained.

High

The Balancing Authority failed to demonstrate the existence of the necessary operating agreements for 50% to 75% of the adjacent BAs.

Or 50% to 75% of those agreements do not contain provisions for emergency assistance.

N/A


Balancing Authority's emergency plans to mitigate insufficient generating capacity emergency plans are neither maintained nor implemented.


Balancing Authority's has demonstrated the existence of transmission system emergency plans but are not maintained.


Balancing Authority's transmission system emergency plans are neither maintained nor implemented.

Severe

The Balancing Authority failed to demonstrate the existence of the necessary operating agreements for 75% or more of the adjacent BAs.

Or more than 75% of those agreements do not contain provisions for emergency assistance.


Balancing Authority has failed to comply with three

(3) of the sub-components.


Balancing Authority has failed to develop emergency mitigation plans for insufficient generating capacity.


Balancing Authority has failed to develop, maintain, and implement operating emergency mitigation plans for emergencies on the transmission system.

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

3


Requirement

R2.3

R3

Lower


Balancing Authority’s load shedding plans are missing minor details or minor program/procedural elements.

Moderate


Balancing Authority's has demonstrated the existence of load shedding plans but are not maintained.


Balancing Authority failed to comply with one (1) of the sub-components.


Balancing Authority failed to comply with two (2) of the sub-components.

High


Balancing Authority's load shedding plans are partially compliant with the requirement but are neither maintained nor implemented.


Balancing Authority has failed to comply with three


Severe


Balancing Authority has failed to develop, maintain, and implement load shedding plans.


Balancing Authority has failed to comply with all four


R3.1

R3.2


Balancing Authority’s communication protocols included in the emergency plan are missing minor program/procedural elements.


Balancing Authority’s list of controlling actions has resulted in meeting the intent of the requirement but is missing minor program/procedural elements.

N/A

N/A

N/A


Balancing Authority provided a list of controlling actions, however the actions fail to resolve the emergency within

NERC-established timelines.


Balancing Authority has failed to include communication protocols in its emergency plans to mitigate operating emergencies.


Balancing Authority has failed to provide a list of controlling actions to resolve the emergency.


4


Requirement

R3.3

R3.4

R4

R5

R6

Lower


Balancing Authority has demonstrated coordination with Transmission Operators and Balancing Authorities but is missing minor program/procedural elements.

N/A

Moderate

The Transmission Operator and Balancing Authority is missing minor program/procedural elements.

The Transmission Operator and Balancing Authority has failed to annually review one of it's emergency plans

N/A

High Severe


Balancing Authority has failed to demonstrate the tasks to be coordinated with adjacent Transmission

Operator and Balancing

Authorities as directed by the requirement.

N/A The Transmission Operator or

Balancing Authority’s emergency plan does not include staffing levels for the emergency

N/A

The Transmission Operator and Balancing Authority’s emergency plan has complied with 90% or more of the number of sub-components.

The Transmission Operator and Balancing Authority’s emergency plan has complied with 70% to 90% of the number of sub-components.

N/A

The Transmission Operator and/or the Balancing

Authority failed to comply with one (1) of the subcomponents.


Authority failed to comply with two (2) of the subcomponents.

The Transmission Operator and Balancing Authority’s emergency plan has complied with between 50% to 70% of the number of subcomponents.

The Transmission Operator and Balancing Authority has failed to annually review two of its emergency plans or communicate with one of it's neighboring Balancing

Authorities.


Authority has failed to comply with three (3) of the sub-components.

The Transmission Operator and Balancing Authority’s emergency plan has complied with 50% or less of the number of sub-components

The Transmission Operator and Balancing Authority has failed to annually review and/or communicate any emergency plans with its

Reliability Coordinator, neighboring Transmission

Operators or Balancing

Authorities.


Authority has failed to comply with four (4) or more of the sub-components.


5


Moderate Requirement

R6.1

Lower


Balancing Authority has failed to establish and maintain reliable communication between interconnected systems.

N/A

R6.2

R6.3

R6.4


Balancing Authority has failed to arrange new interchange agreements to provide for emergency capacity or energy transfers with required entities when existing agreements could not be used.


Balancing Authority has failed to coordinate transmission and generator maintenance schedules to maximize capacity or conserve fuel in short supply.

N/A

N/A


Balancing Authority has failed to arrange for deliveries of electrical energy or fuel from remote systems through normal operating channels.

N/A

N/A

N/A

N/A

N/A

High


6

N/A

Severe

N/A

N/A

N/A


E.


None identified.

Version History

Version Date

0

0

0

February 8,

2005

April 1, 2005

Action

Adopted by the Board of Trustees

Effective Date

Change Tracking

New

New


1 October 17,

2008

Deleted R2

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

Violation Severity Levels

Corrected typographical errors in BOT approved version of VSLs

Revised

IROL Project

2 August 5, 2009 Revised

Project 2006-03

2

2

August 5, 2009

March 17, 2011

Removed R2.4 as redundant with EOP-

005-2 Requirement R1 for the

Transmission Operator; the Balancing

Authority does not need a restoration plan.

Adopted by NERC Board of Trustees:

August 5, 2009

FERC Order issued approving EOP-

001-2 (Clarification issued on July 13,

2011)

Revised

Revised

2b

2b

2b

2.1b

November 4,

2010

November 4,

2010

December 15,

2011

March 8, 2012

Adopted by NERC Board of Trustees Project 2008-09 -

Interpretation of

Requirement R1

Adopted by NERC Board of Trustees Project 2009-28 -

Interpretation of

Requirement R2.2

FERC Order issued approving Interpretation of R1 and R2.2 (Order effective December

15, 2011)

Project 2008-09 -

Interpretation of

Requirement R1 and

Project 2009-28 -

Interpretation of

Requirement R2.2

Errata adopted by Standards Committee;

(changed title and references to Attachment

1 to omit inclusion of version numbers and corrected references in Appendix 1

Question 4 from “EOP-001-0” to “EOP-

001-2”)

Errata


7


2.1b September 13,

2012

FERC approved


Errata

8


Attachment 1-EOP-001

Elements for Consideration in Development of Emergency Plans

1.

Fuel supply and inventory — An adequate fuel supply and inventory plan that recognizes reasonable delays or problems in the delivery or production of fuel.

2.

Fuel switching — Fuel switching plans for units for which fuel supply shortages may occur, e.g., gas and light oil.

3.

Environmental constraints — Plans to seek removal of environmental constraints for generating units and plants.

4.

System energy use — The reduction of the system’s own energy use to a minimum.

5.

Public appeals — Appeals to the public through all media for voluntary load reductions and energy conservation including educational messages on how to accomplish such load reduction and conservation.

6.

Load management — Implementation of load management and voltage reductions, if appropriate.

7.

Optimize fuel supply — The operation of all generating sources to optimize the availability.

8.

Appeals to customers to use alternate fuels — In a fuel emergency, appeals to large industrial and commercial customers to reduce non-essential energy use and maximize the use of customer-owned generation that rely on fuels other than the one in short supply.

9.

Interruptible and curtailable loads — Use of interruptible and curtailable customer load to reduce capacity requirements or to conserve the fuel in short supply.

10.

Maximizing generator output and availability — The operation of all generating sources to maximize output and availability. This should include plans to winterize units and plants during extreme cold weather.

11.

Notifying IPPs — Notification of cogeneration and independent power producers to maximize output and availability.

12.

Requests of government — Requests to appropriate government agencies to implement programs to achieve necessary energy reductions.

13.

Load curtailment — A mandatory load curtailment plan to use as a last resort. This plan should address the needs of critical loads essential to the health, safety, and welfare of the community.

Address firm load curtailment.

14.

Notification of government agencies — Notification of appropriate government agencies as the various steps of the emergency plan are implemented.

15.

Notifications to operating entities — Notifications to other operating entities as steps in emergency plan are implemented.


9


Appendix 1

Requirement Number and Text of Requirement

R1. Balancing Authorities shall have operating agreements with adjacent Balancing Authorities that shall, at a minimum, contain provisions for emergency assistance, including provisions to obtain emergency assistance from remote Balancing Authorities.

Questions:

1.

What is the definition of emergency assistance in the context of this standard? What scope and time horizons, if any, are considered necessary in this definition?

2.

What was intended by using the adjective “adjacent” in Requirement 1? Does “adjacent

Balancing Authorities” mean “All” or something else? Is there qualifying criteria to determine if a very small adjacent Balancing Authority area has enough capacity to offer emergency assistance?

3.

What is the definition of the word “remote” as stated in the last phrase of Requirement 1? Does remote mean every Balancing Authority who’s area does not physically touch the Balancing

Authority attempting to comply with this Requirement?

4.

Would a Balancing Authority that participates in a Reserve Sharing Group Agreement, which meets the requirements of Reliability Standard BAL-002-0, Requirement 2, have to establish additional operating agreements to achieve compliance with Reliability Standard EOP-001-2,

Requirement 1?

Responses:

1.

In the context of this standard, emergency assistance is emergency energy. Emergency energy would normally be arranged for during the current operating day. The agreement should describe the conditions under which the emergency energy will be delivered to the responsible Balancing

Authority.

2.

The intent is that all Balancing Authorities, interconnected by AC ties or DC (asynchronous) ties within the same Interconnection, have emergency energy assistance agreements with at least one

Adjacent Balancing Authority and have sufficient emergency energy assistance agreements to mitigate reasonably anticipated energy emergencies. However, the standard does not require emergency energy assistance agreements with all Adjacent Balancing Authorities, nor does it preclude having an emergency assistance agreement across Interconnections.

3.

A remote Balancing Authority is a Balancing Authority other than an Adjacent Balancing

Authority. A Balancing Authority is not required to have arrangements in place to obtain emergency energy assistance with any remote Balancing Authorities. A Balancing Authority’s agreement(s) with Adjacent Balancing Authorities does (do) not preclude the Adjacent Balancing

Authority from purchasing emergency energy from remote Balancing Authorities.

4.

A Reserve Sharing Group agreement that contains provisions for emergency assistance may be used to meet Requirement R1 of EOP-001-2.


10


Appendix 2

Requirement Number and Text of Requirement

R2.2. Develop, maintain, and implement a set of plans to mitigate operating emergencies on the transmission system.

Questions:

Does the BA need to develop a plan to maintain a load-interchange-generation balance during operating emergencies and follow the directives of the TOP?

Questions:

The answer to both parts of the question is yes. The Balancing Authority is required by the standard to develop, maintain, and implement a plan. The plan must consider the relationships and coordination with the Transmission Operator for actions directly taken by the Balancing Authority.

The Balancing Authority must take actions either as directed by the Transmission Operator or the

Reliability Coordinator (reference TOP-001-1, Requirement R3), or as previously agreed to with the

Transmission Operator or the Reliability Coordinator to mitigate transmission emergencies. As stated in Requirement R4, the emergency plan shall include the applicable elements in “Attachment 1

–EOP-001.”


11

Standard EOP-001-2.1b — Emergency Operations Planning

Appendix QC-EOP-001-2.1b

Provisions specific to the standard EOP-001-2.1b applicable in Québec


A. Introduction

1.

Title: Emergency Operations Planning

2.

Number: EOP-001-2.1b

3.


4.


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.

Violation Severity Levels:




Attachment 1 EOP-001-0b



Standard EOP-001-2.1b — Emergency Operations Planning

Appendix QC-EOP-001-2.1b

Provisions specific to the standard EOP-001-2.1b applicable in Québec

Appendix 1


Appendix 2

In section 3, read "Responses" instead of "Questions". Read "Attachment 1-EOP-001-0b" instead of

"Attachment 1-EOP-001-0" in the last sentence.


Revision Adoption Date Action Change Tracking

0 October 30, 2013 New appendix New


Standard IRO-014-1 — Procedures, Processes, or Plans to Support Coordination Between

Reliability Coordinators

A. Introduction

1.

Title: Procedures, Processes, or Plans to Support Coordination Between


2.

Number: IRO-014-1

3.

Purpose: To ensure that each Reliability Coordinator’s operations are coordinated such that they will not have an Adverse Reliability Impact on other Reliability Coordinator Areas and to preserve the reliability benefits of interconnected operations.

4.

Applicability

4.1.

Reliability Coordinator

5.

Effective Date:

B. Requirements

November 1, 2006

R1.

The Reliability Coordinator shall have Operating Procedures, Processes, or Plans in place for activities that require notification, exchange of information or coordination of actions with one or more other Reliability Coordinators to support Interconnection reliability. These Operating

Procedures, Processes, or Plans shall address Scenarios that affect other Reliability Coordinator

Areas as well as those developed in coordination with other Reliability Coordinators.

R1.1.

These Operating Procedures, Processes, or Plans shall collectively address, as a minimum, the following:

R1.1.1.

Communications and notifications, including the conditions

1

under which one Reliability Coordinator notifies other Reliability Coordinators; the process to follow in making those notifications; and the data and information to be exchanged with other Reliability Coordinators.

R1.1.2.

Energy and capacity shortages.

R1.1.3.

Planned or unplanned outage information.

R1.1.4.

Voltage control, including the coordination of reactive resources for voltage control.

R1.1.5.

Coordination of information exchange to support reliability assessments.

R1.1.6.

Authority to act to prevent and mitigate instances of causing Adverse

Reliability Impacts to other Reliability Coordinator Areas.

R2.

Each Reliability Coordinator’s Operating Procedure, Process, or Plan that requires one or more other Reliability Coordinators to take action (e.g., make notifications, exchange information, or coordinate actions) shall be:

R2.1.

Agreed to by all the Reliability Coordinators required to take the indicated action(s).

R2.2.

Distributed to all Reliability Coordinators that are required to take the indicated action(s).

1

Examples of conditions when one Reliability Coordinator may need to notify another Reliability

Coordinator may include (but aren’t limited to) sabotage events, Interconnection Reliability Operating

Limit violations, voltage reductions, insufficient resources, arming of special protection systems, etc.

Adopted by Board of Trustees: February 7, 2006

Effective Date: November 1, 2006

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

1 of 4



R3.

A Reliability Coordinator’s Operating Procedures, Processes, or Plans developed to support a

Reliability Coordinator-to-Reliability Coordinator Operating Procedure, Process, or Plan shall include:

R3.1.

A reference to the associated Reliability Coordinator-to-Reliability Coordinator

Operating Procedure, Process, or Plan.

R3.2.

The agreed-upon actions from the associated Reliability Coordinator-to-Reliability

Coordinator Operating Procedure, Process, or Plan.

R4.

Each of the Operating Procedures, Processes, and Plans addressed in Reliability Standard IRO-

014 Requirement 1 and Requirement 3 shall:

R4.1.

Include version control number or date.

R4.2.

Include a distribution list.

R4.3.

Be reviewed, at least once every three years, and updated if needed.

C. Measures

M1.

The Reliability Coordinator's System Operators shall have available for Real-time use, the latest approved version of Operating Procedures, Processes, or Plans that require notifications, information exchange or the coordination of actions between Reliability Coordinators.

M1.1

These Operating Procedures, Processes, or Plans shall address:

M1.1.1

Communications and notifications, including the conditions under which one Reliability Coordinator notifies other Reliability Coordinators; the process to follow in making those notifications; and the data and information to be exchanged with other Reliability Coordinators.

M1.1.2 Energy and capacity shortages.

M1.1.3 Planned or unplanned outage information.

M1.1.4 Voltage control, including the coordination of reactive resources for voltage control.

M1.1.5

Coordination of information exchange to support reliability assessments.

M1.1.6

Authority to act to prevent and mitigate instances of causing Adverse

Reliability Impacts to other Reliability Coordinator Areas.

M2.

The Reliability Coordinator shall have evidence that these Operating Procedures, Processes, or

Plans were:

M2.1

Agreed to by all the Reliability Coordinators required to take the indicated action(s).

M2.2

Distributed to all Reliability Coordinators that are required to take the indicated action(s).

M3.

The Reliability Coordinator’s Operating Procedures, Processes, or Plans developed (for its

System Operators’ internal use) to support a Reliability Coordinator-to-Reliability Coordinator

Operating Procedure, Process, or Plan received from another Reliability Coordinator shall:

M3.1

Be available to the Reliability Coordinator’s System Operators for Real-time use,

M3.2

Include a reference to the associated source document, and

M3.3

Support the agreed-upon actions from the source document.




2 of 4



M4.

The Reliability Coordinator’s Operating Procedures, Processes, or Plans that addresses

Reliability Coordinator-to-Reliability Coordinator coordination shall each include a version control number or date and a distribution list. The Reliability Coordinator shall have evidence that these Operating Procedures, Processes, or Plans were reviewed within the last three years.

D. Compliance

1.


1.1.


Regional Reliability Organization

1.2.


The Performance-Reset Period shall be one calendar year.

1.3.

Data Retention

The Reliability Coordinator shall keep documentation for the prior calendar year and the current calendar year. The Compliance Monitor shall keep compliance data for a minimum of three years or until the Reliability Coordinator has achieved full compliance, whichever is longer.

1.4.


The Reliability Coordinator shall demonstrate compliance through self-certification submitted to its Compliance Monitor annually. The Compliance Monitor shall also use a scheduled on-site review at least once every three years and investigations upon complaint.

The Compliance Monitor shall conduct an investigation upon a complaint within 30 days of the alleged infraction’s discovery date. The Compliance Monitor shall complete the investigation within 45 days after the start of the investigation. As part of an audit or investigation, the Compliance Monitor shall interview other Reliability Coordinators to identify Operating Procedures, Processes or Plans that were distributed to the Reliability

Coordinator being audited to verify that these documents are available for Real-time use by the receiving Reliability Coordinator’s System Operators.

The Reliability Coordinator shall have the following documents available for inspection during an on-site audit or within five business days of a request as part of an investigation upon a complaint:

1.4.1

The latest version of its Operating Procedures, Processes, or Plans that require notification, exchange of information, or coordination of actions with one or more other Reliability Coordinators to support Interconnection reliability.

1.4.2

Evidence of distribution of Operating Procedures, Processes, or Plans.

2.


2.1.

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

2.1.1

The latest versions of Operating Procedures, Processes, or Plans (identified through self-certification) that require notification, exchange of information, or coordination of actions with one or more other Reliability Coordinators to support Interconnection reliability do not include a version control number or date, and a distribution list.

2.1.2

The latest versions of Reliability Coordinator internal documents developed to support action(s) required as a result of other Reliability Coordinators do not include




3 of 4


Reliability Coordinators both a reference to the source Operating Procedure, Process, or Plan and the agreedupon actions from the source Operating Procedure, Process, or Plan.

2.2.

Level 2: There shall be a level two non-compliance if any of the following conditions is present:

2.2.1

Documents required by this standard were not distributed to all entities on the distribution list.

2.2.2

Documents required by this standard were not available for System Operators’ Realtime use.

2.2.3

Documents required by this standard do not address all required topics.

2.3.

Level 3: Documents required by this standard do not address any of the six required topics in Reliability Standard IRO-014 R1.

2.4.

Level 4: Not Applicable.


None Identified.

Version History

Version Date

Version 1 08/10/05

Action Change Tracking

1.

Changed incorrect use of certain hyphens (-) to “en dash (–).”

2.

Hyphenated “30-day” when used as adjective.

3.

Changed standard header to be consistent with standard “Title.”

4.

Initial capped heading “Definitions of

Terms Used in Standard.”

5.

Added “periods” to items where appropriate.

6.

Changed “Timeframe” to “Time Frame” in item D, 1.2.

7.

Lower cased all words that are not “defined” terms — drafting team, self-certification.

8.

Changed apostrophes to “smart” symbols.

9.

Added comma in all word strings

“Procedures, Processes, or Plans,” etc.

10.

Added hyphens to “Reliability Coordinatorto-Reliability Coordinator” where used as adjective.

11.

Removed comma in item 2.1.2.

12.

Removed extra spaces between words where appropriate.

01/20/06




4 of 4

Standard IRO-014-1 — Procedures, Processes, or Plans to Support Coordination

Between Reliability Coordinators

Appendix QC-IRO-014-1

Provisions specific to the standard IRO-014-1 applicable in Québec


A. Introduction

1.

Title: Procedures, Processes, or Plans to Support Coordination Between


2.

Number: IRO-014-1

3.


4.


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

Standard IRO-014-1 — Procedures, Processes, or Plans to Support Coordination

Between Reliability Coordinators








Change Tracking

New


Standard IRO-015-1 — Notifications and Information Exchange Between Reliability Coordinators

A. Introduction

1.

Title: Notifications and Information Exchange Between Reliability Coordinators

2.


3.


4.

Applicability

4.1.

Reliability Coordinators

5.

Effective Date:

B. Requirements

November 1, 2006

R1.

The Reliability Coordinator shall follow its Operating Procedures, Processes, or Plans for making notifications and exchanging reliability-related information with other Reliability

Coordinators.

R1.1.

The Reliability Coordinator shall make notifications to other Reliability Coordinators of conditions in its Reliability Coordinator Area that may impact other Reliability

Coordinator Areas.

R2.

The Reliability Coordinator shall participate in agreed upon conference calls and other communication forums with adjacent Reliability Coordinators.

R2.1.

The frequency of these conference calls shall be agreed upon by all involved

Reliability Coordinators and shall be at least weekly.

R3.

The Reliability Coordinator shall provide reliability-related information as requested by other


C. Measures

M1.

The Reliability Coordinator shall have evidence (such as operator logs or other data sources) it has followed its Operating Procedures, Processes, or Plans for notifying other Reliability

Coordinators of conditions in its Reliability Coordinator Area that may impact other Reliability

Coordinator Areas.

M2.

The Reliability Coordinator shall have evidence (such as operator logs or other data sources) that it participated in agreed upon (at least weekly) conference calls and other communication forums with adjacent Reliability Coordinators.

M3.

The Reliability Coordinator shall have evidence that it provided requested reliability-related information to other Reliability Coordinators.

D. Compliance

1.


1.1.






1 of 3


1.2.


The Performance Reset Period shall be one calendar year.

1.3.

Data Retention

The Reliability Coordinator shall keep auditable documentation for a rolling 12 months.

The Compliance Monitor shall keep compliance data for a minimum of three years or until the Reliability Coordinator has achieved full compliance — whichever is longer.

1.4.


The Reliability Coordinator shall demonstrate compliance through self-certification submitted to its Compliance Monitor annually. The Compliance Monitor shall also use a scheduled on-site review at least once every three years and investigations upon complaint.

The Compliance Monitor shall conduct an investigation upon a complaint within 30 days of the alleged infraction’s discovery date. The Compliance Monitor shall complete the investigation within 45 days after the start of the investigation. As part of an audit or an investigation, the Compliance Monitor shall interview other Reliability Coordinators within the Interconnection and verify that the Reliability Coordinator being audited or investigated has been making notifications and exchanging reliability-related information according to agreed Operating Procedures, Processes, or Plans.

The Reliability Coordinator shall have the following available for its Compliance Monitor to inspect during a scheduled, on-site review or within five days of a request as part of an investigation upon complaint:

1.4.1

Evidence it has participated in agreed-upon conference calls or other communications forums.

1.4.2

Operating logs or other data sources that document notifications made to other


2.


2.1.

Level 1: Did not participate in agreed upon (at least weekly) conference calls and other communication forums with adjacent Reliability Coordinators.

2.2.

Level 2: Did not notify other Reliability Coordinators as specified in its Operating

Procedures, Processes, or Plans for making notifications but no Adverse Reliability Impacts resulted from the incident.

2.3.

Level 3: Did not provide requested reliability-related information to other Reliability

Coordinators.

2.4.

Level 4: Did not notify other Reliability Coordinators as specified in its Operating

Procedures, Processes, or Plans for making notifications and Adverse Reliability Impacts resulted from the incident.


None Identified.

Version History

Version

Version 1

Date

08/10/05

Action

1.

Changed incorrect use of certain hyphens (-) to “en dash

(–).”

Change Tracking

01/20/06




2 of 3


2.

Hyphenated “30-day” and reliability-related when used as adjective.

3.

Changed standard header to be consistent with standard

“Title.”

4.


5.

Initial capped heading

“Definitions of Terms Used in

Standard.”

6.

Changed “Timeframe” to

“Time Frame” in item D, 1.2.

7.

Lower cased all words that are not “defined” terms — drafting team, and selfcertification.

8.

Changed apostrophes to

“smart” symbols.

9.

Added comma in all word strings “Procedures, Processes, or Plans,” etc.

10.

Added hyphens to “Reliability

Coordinator-to-Reliability

Coordinator” where used as adjective.

11.

Removed comma in item

2.1.2.

12.





3 of 3

Standard IRO-015-1 — Notifications and Information Exchange Between Reliability

Coordinators




A. Introduction

1.

Title: Notifications and Information Exchange Between Reliability Coordinators

2.

Number: IRO-015-1

3.


4.


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.






Standard IRO-015-1 — Notifications and Information Exchange Between Reliability

Coordinators






Change Tracking

New


Standard IRO-016-1 — Coordination of Real-time Activities Between Reliability Coordinators

A. Introduction

1.

Title: Coordination of Real-time Activities Between Reliability Coordinators

2.


3.


4.

Applicability

4.1.

Reliability Coordinator

5.

Effective Date:

B. Requirements

November 1, 2006

R1.

The Reliability Coordinator that identifies a potential, expected, or actual problem that requires the actions of one or more other Reliability Coordinators shall contact the other Reliability

Coordinator(s) to confirm that there is a problem and then discuss options and decide upon a solution to prevent or resolve the identified problem.

R1.1.

If the involved Reliability Coordinators agree on the problem and the actions to take to prevent or mitigate the system condition, each involved Reliability Coordinator shall implement the agreed-upon solution, and notify the involved Reliability

Coordinators of the action(s) taken.

R1.2.

If the involved Reliability Coordinators cannot agree on the problem(s) each

Reliability Coordinator shall re-evaluate the causes of the disagreement (bad data, status, study results, tools, etc.).

R1.2.1.

If time permits, this re-evaluation shall be done before taking corrective actions.

R1.2.2.

If time does not permit, then each Reliability Coordinator shall operate as though the problem(s) exist(s) until the conflicting system status is resolved.

R1.3.

If the involved Reliability Coordinators cannot agree on the solution, the more conservative solution shall be implemented.

R2.

The Reliability Coordinator shall document (via operator logs or other data sources) its actions taken for either the event or for the disagreement on the problem(s) or for both.

C. Measures

M1.

For each event that requires Reliability Coordinator-to-Reliability Coordinator coordination, each involved Reliability Coordinator shall have evidence (operator logs or other data sources) of the actions taken for either the event or for the disagreement on the problem or for both.

D. Compliance

1.


1.1.



1.2.


The performance reset period shall be one calendar year.




1 of 3


1.3.

Data Retention

The Reliability Coordinator shall keep auditable evidence for a rolling 12 months. In addition, entities found non-compliant shall keep information related to the non-compliance until it has been found compliant. The Compliance Monitor shall keep compliance data for a minimum of three years or until the Reliability Coordinator has achieved full compliance, whichever is longer.

1.4.


The Reliability Coordinator shall demonstrate compliance through self-certification submitted to its Compliance Monitor annually. The Compliance Monitor shall use a scheduled on-site review at least once every three years. The Compliance Monitor shall conduct an investigation upon a complaint that is received within 30 days of an alleged infraction’s discovery date. The Compliance Monitor shall complete the investigation and report back to all involved Reliability Coordinators (the Reliability Coordinator that complained as well as the Reliability Coordinator that was investigated) within 45 days after the start of the investigation. As part of an audit or investigation, the Compliance

Monitor shall interview other Reliability Coordinators within the Interconnection and verify that the Reliability Coordinator being audited or investigated has been coordinating actions to prevent or resolve potential, expected, or actual problems that adversely impact the Interconnection.

The Reliability Coordinator shall have the following available for its Compliance Monitor to inspect during a scheduled, on-site review or within five working days of a request as part of an investigation upon complaint:

1.4.1

Evidence (operator log or other data source) to show coordination with other


2.


2.1.

Level 1: For potential, actual or expected events which required Reliability

Coordinator-to-Reliability Coordinator coordination, the Reliability Coordinator did coordinate, but did not have evidence that it coordinated with other Reliability

Coordinators.

2.2.

Level 2: Not applicable.

2.3.


2.4.

Level 4: For potential, actual or expected events which required Reliability

Coordinator-to-Reliability Coordinator coordination, the Reliability Coordinator did not coordinate with other Reliability Coordinators.


None identified.

Version History

Version

Version 1

Date Action

August 10, 2005 1.

Changed incorrect use of certain hyphens (-) to “en dash (–).”

2.

Hyphenated “30-day” and “Reliability

Coordinator-to-Reliability Coordinator” when used as adjective.

Change Tracking

01/20/06




2 of 3


3.

Changed standard header to be consistent with standard “Title.”

4.


5.

Initial capped heading “Definitions of

Terms Used in Standard.”

6.

Changed “Timeframe” to “Time Frame” in item D, 1.2.

7.

Lower cased all words that are not “defined” terms — drafting team, and selfcertification.

8.

Changed apostrophes to “smart” symbols.

9.

Removed comma after word “condition” in item R.1.1.

10.

Added comma after word “expected” in item 1.4, last sentence.

11.





3 of 3

Standard IRO-016-1 — Coordination of Real-time Activities Between Reliability

Coordinators




A. Introduction

1.

Title: Coordination of Real-time Activities Between Reliability Coordinators

2.

Number: IRO-016-1

3.


4.


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.






Standard IRO-016-1 — Coordination of Real-time Activities Between Reliability

Coordinators






Change Tracking

New


Standard PER-001-0.2 — Operating Pers onnel Res pons ibility and Authority

A.

Introduction

1.

Title: Operating Personnel Responsibility and Authority

2.

Number:

PER-001-0.2

3.

Purpose:

Transmission Operator and Balancing Authority operating personnel must have the responsibility and authority to implement real-time actions to ensure the stable and reliable operation of the Bulk Electric System.

4.

Applicability

4.1.


4.2.


5.

Effective Date:

December 10, 2009

B.

Requirements

R1.

Each Transmission Operator and Balancing Authority shall provide operating personnel with the responsibility and authority to implement real-time actions to ensure the stable and reliable operation of the Bulk Electric System.

C.

Measures

M1.

The Transmission Operator and Balancing Authority provide documentation that operating personnel have the responsibility and authority to implement real-time actions to ensure the stable and reliable operation of the Bulk Electric System. These responsibilities and authorities are understood by the operating personnel. Documentation shall include:

M1.1

A written current job description that states in clear and unambiguous language the responsibilities and authorities of each operating position of a Transmission Operator and Balancing Authority. The job description identifies personnel subject to the authority of the Transmission Operator and Balancing Authority.

M1.2

The current job description is readily accessible in the control room environment to all operating personnel.

M1.3

A written current job description that states operating personnel are responsible for complying with the NERC reliability standards.

M1.4

Written operating procedures that state that, during normal and emergency conditions, operating personnel have the authority to take or direct timely and appropriate realtime actions. Such actions shall include shedding of firm load to prevent or alleviate

System Operating Limit or Interconnection Reliability Operating Limit violations.

These actions are performed without obtaining approval from higher-level personnel within the Transmission Operator or Balancing Authority.

D.

Compliance

1.


Periodic Review: An on-site review including interviews with Transmission Operator and

Balancing Authority operating personnel and document verification will be conducted every three years. The job description identifying operating personnel authorities and responsibilities will be reviewed, as will the written operating procedures or other documents delineating the authority of the operating personnel to take actions necessary to maintain the reliability of the

Bulk Electric System during normal and emergency conditions.

Adopted by the Régie de l'énergie (Decision D-2013-176): October 30, 2013 1 of 3


1.1.


Self-certification: The Transmission Operator and Balancing Authority shall annually complete a self-certification form developed by the Regional Reliability Organization based on measures M1.1 to M1.4.

1.2.


One calendar year.

1.3.

Data Retention

Permanent.

1.4.


2.


2.1.

Level 1:

The Transmission Operator or Balancing Authority has written documentation that includes three of the four items in M1.

2.2.

Level 2:

The Transmission Operator or Balancing Authority has written documentation that includes two of the four items in M1.

2.3.

Level 3:

The Transmission Operator or Balancing Authority has written documentation that includes one of the four items in M1.

2.4.

Level 4:

The Transmission Operator or Balancing Authority has written documentation that includes none of the items in M1, or the personnel interviews indicate

Transmission Operator or Balancing Authority do not have the required authority.

E.


None identified.

Version History

Version

0

Date Action Change Tracking

February 8, 2005 Adopted by NERC Board of Trustees New

0

0

0.1

0.1

0.1

April 1, 2005

August 8, 2005

Effective Date

Removed “Proposed” from Effective

Date

April 15, 2009 Replaced “position” with “job” on

M1.1

April 15, 2009 Errata adopted by Standards Committee

December 10, 2009 Approved by FERC — added effective date

New

Errata

Errata

Errata

Update



0.2

0.2

March 8, 2012

September 13,

2012

Errata adopted by Standards

Committee; (moved the word,

“Interconnection” in Measure M1.4. so that it appears as the first word in the term “Interconnection

Reliability Operating Limit” rather than the last word in the phrase,

“System Operating Limit

Interconnection)

FERC approved

Errata

Errata


Standard PER-001-0.2 — Operating Personnel Responsibility and Authority

Appendix QC-PER-001-0.2

Provisions specific to the standard PER-001-0.2 applicable in Québec


A. Introduction

1.

Title: Operating Personnel Responsibility and Authority

2.

Number: PER-001-0.2

3.


4.


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.




Standard PER-001-0.2 — Operating Personnel Responsibility and Authority

Appendix QC-PER-001-0.2

Provisions specific to the standard PER-001-0.2 applicable in Québec





0 October 30, 2013 New Appendix

Change Tracking

New


Standard TOP-004-2 — Transmission Operations

A. Introduction

1.

Title:

2.

Number:

Transmission Operations

TOP-004-2

3.

Purpose: To ensure that the transmission system is operated so that instability, uncontrolled separation, or cascading outages will not occur as a result of the most severe single Contingency and specified multiple Contingencies.

4.

Applicability:

4.1.

Transmission Operators

5.

Proposed Effective Date: Twelve months after BOT adoption of FAC-014.

B. Requirements

R1.

Each Transmission Operator shall operate within the Interconnection Reliability Operating

Limits (IROLs) and System Operating Limits (SOLs).

R2.

Each Transmission Operator shall operate so that instability, uncontrolled separation, or cascading outages will not occur as a result of the most severe single contingency.

R3.

Each Transmission Operator shall operate to protect against instability, uncontrolled separation, or cascading outages resulting from multiple outages, as specified by its

Reliability Coordinator.

R4.

If a Transmission Operator enters an unknown operating state (i.e. any state for which valid operating limits have not been determined), it will be considered to be in an emergency and shall restore operations to respect proven reliable power system limits within 30 minutes.

R5.

Each Transmission Operator shall make every effort to remain connected to the

Interconnection. If the Transmission Operator determines that by remaining interconnected, it is in imminent danger of violating an IROL or SOL, the Transmission

Operator may take such actions, as it deems necessary, to protect its area.

R6.

Transmission Operators, individually and jointly with other Transmission Operators, shall develop, maintain, and implement formal policies and procedures to provide for transmission reliability. These policies and procedures shall address the execution and coordination of activities that impact inter- and intra-Regional reliability, including:

R6.1.

Monitoring and controlling voltage levels and real and reactive power flows.

R6.2.

Switching transmission elements.

R6.3.

Planned outages of transmission elements.

R6.4.

Responding to IROL and SOL violations.

C. Measures

M1.

Each Transmission Operator that enters an unknown operating state for which valid limits have not been determined, 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, alarm program printouts, or other equivalent evidence that will be used to determine if it restored operations to respect proven reliable power system limits within 30 minutes as specified in Requirement 4.

M2.

Each Transmission Operator shall have and provide upon request current policies and procedures that address the execution and coordination of activities that impact inter- and intra-Regional reliability for each of the topics listed in Requirements 6.1 through 6.6.

Adopted by Board of Trustees: November 1, 2006


Page 1 of 3


D. Compliance

1.

Compliance Monitoring Process

1.1.


Regional Reliability Organizations shall be responsible for compliance monitoring.

1.2.






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.)

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

1.3.

Data Retention

2.

Each Transmission Operator shall keep 90 days of historical data for Measure 1.

Each Transmission Operator shall have current, in-force policies and procedures, as evidence of compliance to Measure 2.


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 supporting compliance data

1.4.


None.

Levels of Non-Compliance:

2.1.


2.2.

Level 2: Did not have formal policies and procedures to address one of the topics listed in R6.1 through R6.4.

2.3.

Level 3: Did not have formal policies and procedures to address two of the topics listed in R6.1 through R6.4.



Page 2 of 3


2.4.

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 restore operations to respect proven reliable power system limits within 30 minutes as specified in R4.

2.4.2

Did not have formal policies and procedures to address three or all of the topics listed in R6.1 through R6.4.


None identified.

Version History

Version

0

Date Action

April 1, 2005 Effective Date

0 August 8, 2005 Removed “Proposed” from Effective

Date

Change Tracking

New

Errata

Revised

2006 and Compliance Elements adopted by

Board of Trustees on November 1, 2006

2007

Revised

Errata from FAC-010-1, 011-1, and 014-1 standards approved by BOT on

November 1, 2006.

- Revised R3 and R6 with conforming changes made as errata to Levels of

Non-compliance



Page 3 of 3


Appendix QC-TOP-004-2

Provisions specific to the standard TOP-004-2 applicable in Québec


A. Introduction

1.

Title: Transmission Operations

2.

Number: TOP-004-2

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









Change Tracking

New


Standard TOP-007-0 — Reporting SOL and IROL Violations

A. Introduction

1.

Title: Reporting System Operating Limit (SOL) and Interconnection Reliability

Operating Limit (IROL) Violations

2.

Number: TOP-007-0

3.

Purpose:

This standard ensures SOL and IROL violations are being reported to the Reliability

Coordinator so that the Reliability Coordinator may evaluate actions being taken and direct additional corrective actions as needed.

4.

Applicability:

4.1.


4.2.


5.

Effective Date: April 1, 2005

B. Requirements

R1.

A Transmission Operator shall inform its Reliability Coordinator when an IROL or SOL has been exceeded and the actions being taken to return the system to within limits.

R2.

Following a Contingency or other event that results in an IROL violation, the Transmission

Operator shall return its transmission system to within IROL as soon as possible, but not longer than 30 minutes.

R3.

A Transmission Operator shall take all appropriate actions up to and including shedding firm load, or directing the shedding of firm load, in order to comply with Requirement R2.

R4.

The Reliability Coordinator shall evaluate actions taken to address an IROL or SOL violation and, if the actions taken are not appropriate or sufficient, direct actions required to return the system to within limits.

C. Measures

M1.

Evidence that the Transmission Operator informed the Reliability Coordinator when an IROL or SOL was exceeded and the actions taken to return the system to within limits.

M2.

Evidence that the Transmission Operator returned the system to within IROL within 30 minutes for each incident that an IROL, or SOL that became an IROL due to changed system conditions, was exceeded.

M3.

Evidence that the Reliability Coordinator evaluated actions and provided direction required to return the system to within limits.

D. Compliance

1.


1.1.


The Reliability Coordinator shall report any IROL violation exceeding 30 minutes to the Regional Reliability Organization and NERC within 72 hours. Each Regional

Reliability Organization shall report any such violations to NERC via the NERC compliance reporting process. The Reliability Coordinator shall report any SOL violation that has become an IROL violation because of changed system conditions; i.e. exceeding the limit will require action to prevent:

Adopted by NERC Board of Trustees: February 8, 2005

Effective Date: April 1, 2005


1 of 3


1.1.1.

System instability.

1.1.2.

Unacceptable system dynamic response or equipment tripping.

1.1.3.

Voltage levels in violation of applicable emergency limits.

1.1.4.

Loadings on transmission facilities in violation of applicable emergency limits.

1.1.5.

Unacceptable loss of load based on regional and/or NERC criteria.

1.2.


The reset period is monthly.

1.3.

Data Retention

The data retention period is three months.

2.


2.1.

The Transmission Operator did not inform the Reliability Coordinator of an IROL or an SOL that has become an IROL because of changed system conditions, and the actions they are taking to return the system to within limits, or

2.2.

The Transmission Operator did not take corrective actions as directed by the

Reliability Coordinator to return the system to within the IROL within 30 minutes.

(See Table 1-TOP-007-0 below.)

2.3.

The limit violation was reported to the Reliability Coordinator, who did not provide appropriate direction to the Transmission Operator, resulting in an IROL violation in excess of 30 minutes duration.

Table 1-TOP-007-0 IROL and SOL Reporting Levels of Non-Compliance

Percentage by which IROL or

SOL that has become an IROL is exceeded*

Limit exceeded for more than 30 minutes, up to 35 minutes.

Level 1


Level 2


Level 2

Limit exceeded for more than 45 minutes.

Level 3 Greater than 0%, up to and including 5%

Greater than 5%, up to and including 10%




Greater than 25%

Level 2

Level 2

Level 3

Level 3

Level 4

Level 2

Level 3

Level 3

Level 4

Level 4

Level 3

Level 3

Level 4

Level 4

Level 4

Level 3

Level 4

Level 4

Level 4

Level 4

*Percentage used in the left column is the flow measured at the end of the time period (30, 35, 40, or

45 minutes).




2 of 3


None identified.

Version History

Version Date

0

0

April 1, 2005

Action

Effective Date

Change Tracking

New





3 of 3





A. Introduction

1.

Title: Reporting SOL and IROL Violations

2.

Number: TOP-007-0

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.







Table 1-TOP-007-0







Change Tracking

New


Standard TOP-008-1 — Response to Transmission Limit Violations

A. Introduction

1.

2.

3.

Title: Response to Transmission Limit Violations

Number: TOP-008-1

Purpose: To ensure Transmission Operators take actions to mitigate SOL and IROL violations.

4.

5.

Applicability

4.1.


Effective Date:

B. Requirements

January 1, 2007

R1.

The Transmission Operator experiencing or contributing to an IROL or SOL violation shall take immediate steps to relieve the condition, which may include shedding firm load.

R2.

Each Transmission Operator shall operate to prevent the likelihood that a disturbance, action, or inaction will result in an IROL or SOL violation in its area or another area of the Interconnection. In instances where there is a difference in derived operating limits, the Transmission Operator shall always operate the Bulk Electric System to the most limiting parameter.

R3.

The Transmission Operator shall disconnect the affected facility if the overload on a transmission facility or abnormal voltage or reactive condition persists and equipment is endangered. In doing so, the Transmission Operator shall notify its Reliability

Coordinator and all neighboring Transmission Operators impacted by the disconnection prior to switching, if time permits, otherwise, immediately thereafter.

R4.

The Transmission Operator shall have sufficient information and analysis tools to determine the cause(s) of SOL violations. This analysis shall be conducted in all operating timeframes. The Transmission Operator shall use the results of these analyses to immediately mitigate the SOL violation.

C. Measures

M1.

The Transmission Operator involved in an SOL or IROL violation shall have and provide upon request evidence that could include, but is not limited to, operator logs, voice recordings, electronic communications, alarm program printouts, or other equivalent evidence that will be used to determine if it took immediate steps to relieve the condition. (Requirement 1)

M2.

The Transmission Operator that disconnects an overloaded facility shall have and provide upon request evidence that could include, but is not limited to, operator logs, voice recordings, electronic communications, alarm program print outs, or other equivalent evidence that will be used to determine if it disconnected an overloaded facility in accordance with Requirement 3 Part 1

M3.

The Transmission Operator that disconnects an overloaded facility 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


Effective Date: January 1, 2007

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

Page 1 of 3

Standard TOP-008-1 — Response to Transmission Limit Violations equivalent evidence that will be used to determine if it notified its Reliability

Coordinator and all neighboring Transmission Operators impacted by the disconnection prior to switching, if time permitted, otherwise, immediately thereafter.

(Requirement 3 Part 2)

M4.

The Transmission Operator shall have and provide upon request evidence that could include, but is not limited to, computer facilities documents, computer printouts, training documents, copies of analysis program results, operator logs or other equivalent evidence that will be used to confirm that it has sufficient information and analysis tools to determine the cause(s) of SOL violations. (Requirement 4 Part 1)

M5.

The Transmission Operator that violates an SOL 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 confirm that it used the results of these analyses to immediately mitigate the SOL violation. (Requirement 4 Part 3)

D. Compliance

1.


1.1.


Regional Reliability Organizations shall be responsible for compliance monitoring.

1.2.






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.)

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

1.3.

Data Retention

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

Measure 1, 2 and 3.

Each Transmission Operator shall have current documents as evidence of compliance to Measures 4 and 5.




Page 2 of 3

Standard TOP-008-1 — Response to Transmission Limit Violations


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 data

1.4.


None.

Levels of Non-Compliance for Transmission Operator 2.

2.1.


2.2.

Level 2: Disconnected an overloaded facility as specified in R3 but did not notify its Reliability Coordinator and all neighboring Transmission Operators impacted by the disconnection prior to switching, or immediately thereafter.

2.3.


2.4.

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 take immediate steps to relieve an IROL or SOL violation in accordance with R1.

2.4.2

Did not disconnect an overloaded facility as specified in R3.

2.4.3

Does not have sufficient information and analysis tools to determine the cause(s) of SOL violations. (R4 Part 1)

2.4.4

Did not use the results of analyses to immediately mitigate an SOL violation. (R4 Part 3)


None identified.

Version History

Version

0

Date Action

April 1, 2005 Effective Date

0 August 8, 2005 Removed “Proposed” from Effective

Date

Change Tracking

New

Errata

Revised

2006




Page 3 of 3

Standard TOP-008-1— Response to Transmission Limit Violations




A. Introduction

1.

Title: Response to Transmission Limit Violations

2.

Number: TOP-008-1

3.


4.

Applicability:

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


C. Measures


D. Compliance

1.


1.1.



1.2.



1.3.

Data Retention


1.4.



2.



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

Standard TOP-008-1— Response to Transmission Limit Violations







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

NORMES DE FIABILITÉ DE LA NERC

NORMES DE FIABILITÉ DE LA NERC

ADOPTÉES PAR LA RÉGIE DE L’ÉNERGIE,

À ÊTRE MISES EN VIGUEUR AU 1

AVRIL 2015

(VERSION ANGLAISE)

∈

−

−

Related documents

Products

Support

NORMES DE FIABILITÉ DE LA NERC

NORMES DE FIABILITÉ DE LA NERC

ADOPTÉES PAR LA RÉGIE DE L’ÉNERGIE,

À ÊTRE MISES EN VIGUEUR AU 1

AVRIL 2015

(VERSION ANGLAISE)

∈

−

−

Related documents

Add this document to collection(s)

Add this document to saved

Suggest us how to improve StudyLib