2004 operating templates

Approved July 18, 2002 Compliance Templates P1 T1 NERC Operating Standards

October 26, 2003

Reliability Principle 2

The frequency and voltage of interconnected bulk electric systems shall be controlled within defined limits through the balancing of real and reactive power supply and demand.

Section Policy 1, Section A, Control Performance Standard Brief Description

Control Performance Standard, Load and Generation Matching, and Frequency Control

Applicable to:

Control Areas Standard

CPS 1 and CPS 2 Control Performance Standards Monitoring Responsibility

Regional Reliability Councils (RRCs) Measuring Processes

Compliance with the CPS 1 standard shall be measured on a percentage basis as set forth in the NERC Performance Standard Training Document.

Periodic Reporting

Control Areas must have achieved the minimum compliance level and must send one completed copy of the CPS 1 and CPS 2 form “NERC Control Performance Standard Survey-All Interconnections” each month to the Regions as per established dates.

The Regional Reliability Council must submit a summary document reporting compliance with CPS 1 and CPS 2 to NERC no later than the 20th day of the following month.

Periodic Compliance Monitoring Compliance for CPS 1 and CPS 2 will be evaluated and penalties and sanctions applied for each reporting period.

7/18/02

Reporting Period One calendar month Full (100%) Compliance Requirements

The Control Area meets the CPS 1 and CPS 2 Control Performance Standards, when CPS 1 is greater than or equal to100% and CPS 2 is greater than or equal to 90% in a reporting period.

Levels of Non-Compliance

Non-compliance for CPS 1 and CPS 2 is evaluated separately and penalties and sanctions are applied individually. Non-compliance for CPS 1 in a month, shall mean that the rolling twelve month average of CPS 1 ending in that month is less than 100%. Non-compliance for CPS 2 shall mean that the monthly CPS 2 average is below 90%. Both CPS 1 and CPS 2 are calculated and evaluated monthly. CPS 1 Level 1: the Control Area’s value of CPS 1 is less than 100% but greater

than or equal to 95%. Level 2: the Control Area’s value of CPS 1 is less than 95% but greater


than or equal to 85%.

Level 4: the Control Area’s value of CPS 1 is less than 85%.

CPS2

Level 1: the Control Area’s value of CPS 2 is less than 90% but greater than or equal to 85%.

Level 2: the Control Area’s value of CPS 2 is less than 85% but greater


than or equal to 75%. Level 4: the Control Area’s value of CPS 2 is less than 75%.

Compliance Assessment Notes

Verification of compliance will be done through established periodic monitoring processes.

7/18/02

Penalties/sanctions

The dollar penalty/sanction calculated from the Compliance Enforcement Table will be the larger of the fixed dollar amount or the calculated dollar amount using the $/MW value times the larger of the most recent year’s data:

(1) average annual hourly generation (MWh generated divided by hours in year) or

(2) average annual hourly load (MWh consumed divided by hours in year)

Reset Period One calendar month without a violation Data Retention The data that supports the calculation of CPS 1 and CPS 2 are to be

retained in electronic form for at least a one-year period. If the CPS 1 and CPS 2 data for a Control 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.

CPS 1 DATA Description Retention Requirements ε1 A constant derived from

the targeted frequency bound. This number is the same for each Control Area in the interconnection.

Retain the value of ε1 used in CPS 1 calculation.

ACEi The clock-minute average of ACE.

Retain the 1-minute average values of ACE (525,600 values).

βi The frequency bias of the Control Area.

Retain the value(s) of Bi used in the CPS 1 calculation.

FA The actual measured frequency.

Retain the 1-minute average frequency values (525,600 values).

Fs Scheduled frequency for the Interconnection.

Retain the 1-minute average frequency values (525,600 values).

7/18/02

CPS 2 DATA Description Retention Requirements V Number of incidents per

hour in which the absolute value of ACE is greater than L10.

Retain the values of V used in CPS 2 calculation.

ε10 A constant derived from the frequency bound. It is the same for each Control Area within an Interconnection.

Retain the value of ε10 used in CPS 2 calculation.

βi The frequency bias of the Control Area.

Retain the value of Bi used in the CPS 2 calculation.

βs The sum of frequency bias of the Control Areas in the respective Interconnection. For systems with variable bias, this is equal to the sum of the minimum frequency bias setting.

Retain the value of Bs used in the CPS 2 calculation. Retain the 1-minute minimum bias value (525,600 values).

U Number of unavailable ten-minute periods per hour used in calculating CPS 2.

Retain the number of 10-minute unavailable periods used in calculating CPS 2 for the reporting period.

7/18/02

Approved July 18, 2002 Compliance Templates P1 T2 NERC Operating Standard

October 26, 2003 Reliability Principle 2

The frequency and voltage of interconnected bulk electric systems shall be controlled within defined limits through the balancing of real and reactive power supply and demand.

Section

Policy 1, Section B, Disturbance Control Standard Brief Description

Disturbance Control Standard Applicable To

Control Areas that are not part of a Reserve Sharing Group and Reserve Sharing Groups

Standard

ACE must be returned to zero or to its pre-disturbance level within the Disturbance Recovery Period following the start of a Reportable Disturbance.

Monitoring Responsibility Regional Reliability Councils (RRC’s). Measuring Processes

Compliance with the Disturbance Control Standard (DCS) shall be measured on a percentage basis as set forth in the NERC Performance Standard Training Document.

Periodic Reporting

Control Areas and/or Reserve Sharing Groups must return one completed copy of DCS form “NERC Control Performance Standard Survey-All Interconnections” each quarter to the Region as per set dates.

The Regional Reliability Council must submit a summary document reporting compliance with DCS to NERC no later than the 20th day of the month following the end of the quarter.

Periodic Compliance Monitoring Compliance for DCS will be evaluated and penalties and sanctions applied for each reporting period.

Page 1 26/10/03

Reporting Period One calendar quarter Full (100%) Compliance Requirements

Control Area or Reserve Sharing Group returned the ACE to zero or to its pre-disturbance level within the Disturbance Recovery Period, following the start of all Reportable Disturbances. DCS is calculated quarterly and compliance evaluated as the Average Percentage Recovery (APR) as defined in the Performance Standard Training Document.


Level 1: value of APR is less than 100% but greater than or equal to 95%. Level 2: value of APR is less than 95% but greater than or equal to 90%. Level 3: value of APR is less than 90% but greater than or equal to 85%.

Level 4: value of APR is less than 85%.

Compliance Assessment Notes Verification of compliance will be done through established periodic monitoring processes.

Penalties/Sanctions

The dollar penalty/sanction calculated from the Compliance Enforcement Table will be the larger of the fixed dollar amount or the calculated dollar amount using the $/MW value times the larger of the most recent year’s data:

(1) average annual hourly generation (MWh generated divided by hours in year) or

(2) average annual hourly load (MWh consumed divided by hours in year)

Reset Period

One calendar quarter without a violation.

Page 2 26/10/03

Data Retention The data that supports the calculation of DCS is to be retained in electronic form for at least a one-year period. If the DCS data for a Reserve Sharing Group and Control 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.

DCS DATA Description Retention Requirements MW loss The MW size of the

disturbance as measured at the beginning of the loss.

Retain the value of MW loss used in DCS calculation.

ACEA The pre-disturbance ACE.

Retain the value of ACEA used in DCS calculation.

ACEM The maximum algebraic value of ACE measured within ten minutes following the disturbance event.

Retain the value of ACEM used in the DCS calculation.

ACEm The minimum algebraic value of ACE measured within the recovery period following the disturbance event.

Retain the value of ACEm used in the DCS calculation.

Date of incident The date the incident occurred.

Retain the date.

Time of incident The time of the incident in hours, minutes, and seconds.

Retain the time as precise as possible.

Description of incident Describe the incident in sufficient details to define the incident.

Retain sufficient details to define the incident, i.e. name and MW output of unit that tripped. Cause of incident.

Recovery Time Duration The duration of time of the incident in hours, minutes, and seconds to have the ACE return to 0.

Retain the incident time as precise as possible.

Page 3 26/10/03

Compliance Templates P2 T1 NERC Operating Standards

October 26, 2003

Reliability Principle 1 Interconnected bulk electric systems shall be planned and operated in a coordinated manner to perform reliably under normal and abnormal conditions as defined in the NERC Standards.

Section Policy 2, Section A. Transmission Operations, Requirement 1 1.1 1.2

And Section B Requirement 1

Brief Description Transmission Operation/ Operating Security Procedures Applicable to

Entities responsible for the reliability of the interconnected system (ERRIS) Standard

ERRIS’ individually and jointly, shall develop, and maintain formal policies and procedures to address the execution and coordination of activities that affect inter-and intra-Regional transmission system security. The policies should address:

Equipment ratings Monitoring and controlling voltage levels and real and reactive power

flows Switching transmission elements Planned outages of transmission elements Development of Operating Security Limits Responding to Operating Security Limit violations.

Monitoring Responsibility Regional Reliability Council (RRC) Measurement

ERRIS policies and procedures address the execution and coordination of activities that affect inter-and intra-Regional security, including:

equipment ratings; monitoring and controlling voltage levels and real and reactive power

flows; switching transmission elements; planned outages of transmission elements; Operating Security Limits Response to Operating Security Limit violations.

Measuring Processes Periodic Review ERRIS will be selected for operational reviews at least every three years Self-CertificationEach ERRIS will annually self-certify compliance to the measures as required by its RRC.


Level 1 – The ERRIS policies and procedures do not address one of the six measurable items. Level 2 - The ERRIS policies and procedures do not address two of the six measurable items. Level 3 - The ERRIS policies and procedures do not address three of the six measurable items. Level 4 - The ERRIS policies and procedures do not address more than three of the six measurable items.


ERRIS review will verify that they did develop, and maintain formal currently valid policies and procedures to provide transmission security as indicated. This review will cover:

availability of the policies and procedures, update procedures

The Operational review should include an assessment of policies and

procedures addressing the following: equipment ratings; monitoring and controlling voltage levels and real and reactive power

flows; switching transmission elements; planned outages of transmission elements; development of Operating Security Limits, Responding to Operating Security Limit violations.

Due to the changes that are occurring across the interconnections, it has become difficult to identify various sectors within each entity. To facilitate the development of the compliance program, the term ERRIS (Entities responsible for the reliability of the interconnected system) is being used in the Compliance Templates. An ERRIS can include, but is not limited to control areas, transmission operators, generation operators, balancing authorities etc. In this way, the applicability of each standard can be determined by the Regional Reliability Councils to facilitate their particular organizational set up.

PENALTIES/SANCTIONS The sanction will be the larger of the fixed dollar amount shown in the Enforcement Table or the calculated dollar amount using the following sanction measures: Miles of bulk transmission line in the ERRIS area operating at a nominal voltage

100kV and greater. Maximum amount of installed generating capacity in the ERRIS, in whole MW,

during the most recent calendar year. Average MW output of generation in the ERRIS in the most recent calendar year,

in whole MW, calculated as the MW hour generation output during the year, divided by the number of hours in a year. Peak load in the ERRIS, in the preceding year in whole MW.

Compliance Reset Period

One Calendar year Data retention requirements

Documentation must be kept available Multiplier: 1.0 Occurrence Period –One Calendar year


October 26, 2003


Interconnected bulk electric systems shall be planned and operated in a coordinated manner to perform reliably under normal and abnormal conditions as defined in the NERC Standards.

Section Policy 2, Section A. Transmission Operations, Requirement 2, 2.1, 2.2

And Section B. Voltage and Reactive Control Requirement 3.2.2 Reactive Restoration.

Brief Description Transmission Operation/ Operating Security Limit Violations Applicable to


Following an Operating Security Limit (OSL) violation, the ERRIS should have returned its transmission system to within Operating Security Limits as soon as possible, within Regional or Sub Regional requirements but not longer than 30 minutes.

Monitoring Responsibility Regional Reliability Council (RRC)

Measurement The entity responsible for the reliability of the interconnected system returned its transmission system to within Operating Security Limits as soon as possible but not longer than 30 minutes.

Measuring Processes Periodic Reporting The ERRIS will be required to report monthly to the RRC any violation of Operating Security Limits on an appropriate number of elements as selected by each Regional Reliability Organization (RRC).


For each separate incident violating the OSL compliance standard, the level of the violation shall be as set forth in the following table:

Limit exceeded

for more than 30 minutes, up to 35 minutes

Limit exceeded for more than 35 minutes, up to 40 minutes

Limit exceeded for more than 40 minutes, up to 45 minutes

Limit exceeded for more than 45 minutes

Percentage by violation of OSL

greater than 0%, up to and including 5%

Level 1 Level 2 Level 2 Level 3









greater than 25% Level 4 Level 4 Level 4 Level 4 Compliance Assessment Notes

The RRC will select an appropriate number of critical elements to be monitored for the Compliance. The ERRIS responsible for each selected element will report monthly on any violation of Operating Security Limits, and the duration of any violations.

Each violation of this Standard shall be reported to the RRO and the NERC

Compliance Director within 72 hours using the NERC Preliminary Disturbance Report Form as found in Appendix 5F, “Reporting Requirements for Major Electric System Emergencies.”

Due to the changes that are occurring across the interconnections, it has become difficult to identify various sectors within each entity. To facilitate the development of the compliance program, the term ERRIS (Entities responsible for the reliability of the interconnected system) is being used in the Compliance

Templates. An ERRIS can include, but is not limited to control areas, transmission operators, generation operators, balancing authorities etc. In this way, the applicability of each standard can be determined by the Regional Reliability Councils to facilitate their particular organizational set up. DEFINITION: OPERATING SECURITY LIMIT. The value of a system operating parameter (e.g. total power transfer across an interface) that satisfies the most limiting of prescribed pre- and post-contingency operating criteria as determined by equipment loading capability and acceptable stability and voltage conditions.

PENALTIES/SANCTIONS The sanction will be the larger of the fixed dollar amount shown in the Enforcement Table or the calculated dollar amount using the following sanction measures: Miles of bulk transmission line in the ERRIS area operating at a nominal voltage





One Calendar year Data retention requirements

Three months Multiplier: 3.0 Occurrence Period –Per event



Information necessary for the planning and operation of interconnected bulk electric systems shall be made available to those entities responsible for planning and operating the systems reliably.

Section Policy 4, Section A. Requirements 2, 5, 6 Policy 4, Section B, Requirement 5 Brief Description System Coordination/Transmission System Monitoring

Applicable to Entities responsible for the reliability of the interconnected system (ERRIS)

Standard The ERRIS must have provided adequate facilities for the system operators to monitor the following equipment, under normal and emergency situations:

Transmission line status MW and MVAR flows Voltage LTC settings and Status of rotating and static reactive resources and System frequency

The monitoring equipment must be designed to alert system operators of limit violations and the need for corrective action.

Each ERRIS shall provide to other ERRIS’, the Electric Security Data that they require for operational security assessments and coordinating operations


Each Operating Authority meets 100% compliance when they demonstrate that they have:

Facilities for the system operators to monitor transmission line status, MW and MVAR flows, voltage, LTC settings and status of rotating and static reactive resources and system frequency, in a timely manner, under normal and emergency situations.

Monitoring equipment to alert system operators of limit violations and the

need for corrective action.

Equipment and processes used to share critical Bulk Electrical System (BES) reliability data with system operators in other ERRIS’

Measuring Processes

Periodic Review ERRIS will be selected for operational reviews at least every three years Self-CertificationEach ERRIS will annually self-certify compliance to the measures as required by its RRC.

Levels of Non-Compliance LEVEL 1- N/A LEVEL 2 - The EERIS meets two of the above requirements of the template. LEVEL 3 – The EERIS meets one of the above requirements of the template. LEVEL 4 – The EERIS meets none of the above requirements of the template.

Compliance Assessment Notes 3-year Review

ERRIS will demonstrate that the system operators have adequate facilities and processes to meet 100% compliance requirements. As part of the Periodic Review, a questionnaire will be sent to adjacent ERRIS to verify that the ERRIS being reviewed adequately shares critical BES reliability data with them. Due to the changes that are occurring across the interconnections, it has become difficult to identify various sectors within each entity. To facilitate the development of the compliance program, the term ERRIS (Entities responsible for the reliability of the interconnected system) is being used in the Compliance Templates. An ERRIS can include, but is not limited to control areas, transmission operators, generation operators, balancing authorities etc. In this way, the applicability of each standard can be determined by the Regional Reliability Councils to facilitate their particular organizational set up.

Penalties/sanctions The sanction will be the larger of the fixed dollar amount shown in the Enforcement Table or the calculated dollar amount using the following sanction measures: Miles of bulk transmission line in the ERRIS’s area operating at a nominal voltage


during the most recent calendar year. Average MW output of generation in the ERRIS in the most recent calendar year, in

whole MW, calculated as the MWhour generation output during the year, divided by the number of hours in a year. Peak load in the ERRIS, in the preceding year in whole MW.


One year without a violation from the time of the violation Data retention requirements

N/A Multiplier: 1.0 Occurrence Period –One calendar year

Compliance Templates P 4 T2 NERC Operating Standards




The security of the interconnected bulk electric systems shall be assessed, monitored, and maintained on a wide-area basis.

Section Policy 4, Section B Requirements 3, 3.1 Brief Description System Coordination/Operational Security Information Applicable to

ERRIS - Entities Responsible for the reliability of the interconnected system.

Standard Each (ERRIS) shall provide its Reliability Coordinator (s) with operating data that the Reliability Coordinator requires to monitor system conditions within the RC area. The RC will identify the data requirements from the list in Policy 4, Appendix 4B. The RC will identify any additional operating information requirements, relating to operation of the bulk power system and also, which data must be provided electronically.


The ERRIS meets 100% compliance when they provide the Reliability Coordinator with the information required, within the time intervals specified therein, and in a format agreed upon by the Reliability Coordinator.

Measuring Processes

Periodic Review Entities will be selected for operational reviews at least every three years

Self Certification Each entity will annually self-certify compliance to the measures as required by its RRC.

Levels of Non-Compliance LEVEL 1- The ERRIS is providing the Reliability Coordinator with the data required, in specified time intervals and format, but there are problems with consistency of delivery identified in the measuring process that need remedy (e.g., the data is not supplied consistently due to equipment malfunctions, or scaling is incorrect). LEVEL 2 - N/A LEVEL 3 - N/A LEVEL 4 - The ERRIS is not providing the Reliability Coordinator with data having the specified content, or time interval reporting, or format. The information missing is included in the RC’s list of data.

Compliance Assessment Notes:

Each Reliability Coordinator will prepare a list of data requirements, formats, and time intervals for reporting.


Penalties/sanctions

The sanction will be the larger of the fixed dollar amount shown in the Enforcement Table or the calculated dollar amount using the following sanction measures: Miles of bulk transmission line in the ERRIS’s area operating at a nominal

voltage 100kV and greater. Maximum amount of installed generating capacity in the ERRIS, in whole MW,


in whole MW, calculated as the MWhour generation output during the year, divided by the number of hours in a year. Peak load in the ERRIS, in the preceding year in whole MW.





Section Policy 4, Section B Requirements 4 4.1 Brief Description System Coordination/Operational Security Information/ISN

Applicable to

Reliability Coordinators

Standard Upon request, Reliability Coordinators must exchange Security Data that is necessary to allow other Reliability Coordinators to perform their operational security assessments and coordinate their reliable operations.

Measurement

The Reliability Coordinator meets 100% compliance when they provide the other Reliability Coordinators with the information required, within the time intervals specified therein, and in a format agreed to. In the Eastern Interconnection the data exchange shall be via the Interregional Security Network, ISN. In ERCOT and WSCC, arrangements should be specified between Reliability Coordinators in the respective regions (and with the Eastern Interconnect).

Monitoring Responsibility Regional Reliability Council (RRC) Measuring Processes


Self Certification Each ERRIS will annually self-certify compliance to the measures as required by its RRC.

Levels of Non-Compliance LEVEL 1 - The RC is providing other Reliability Coordinators with the data required, in specified time intervals and format, but there are problems with consistency of delivery identified in the measuring process that need remedy (e.g., the data is not supplied consistently due to equipment malfunctions, or scaling is incorrect). LEVEL 2 - N/A LEVEL 3 – N/A LEVEL 4 - The RC is not providing other Reliability Coordinators with data having the specified content, or time interval reporting, or format. The information missing is included in the RC’s list of data.

Compliance Assessment Notes:

The RC needs to provide list of expected data to be provided. Questionnaires should be sent to adjacent Reliability Coordinators by RRC for their input on the performance of the Reliability Coordinator in review.


Penalties/sanctions The sanction will be the larger of the fixed dollar amount shown in the Enforcement Table or the calculated dollar amount using the following sanction measures: The total circuit miles of transmission above 100kV of the territory administered by

the Reliability Coordinator. The average annual generation in MW of the territory administered by the Reliability

Coordinator or The average annual load in MW of the territory administered by the Reliability

Coordinator


One year without a violation from the time of the violation Data retention requirements N/A Multiplier: 1.0 Occurrence Period –One calendar year

Compliance Templates P5 T1NERC Operating Standards

October 26, 2003

Reliability Principle 4 Plans for emergency operation and system restoration of interconnected bulk electric systems shall be developed, coordinated, maintained and implemented.

Section Policy 5, Section A, Requirement 1

Emergency Operations/Coordination with other systems Policy 6, Section B, Requirement 2 Emergency Operations/A set of Capacity and Energy Emergency plans consistent with NERC Operating Policies shall be developed, maintained, and implemented

Brief Description Emergency Operations/Implementation of Capacity and Energy Emergency plans and coordination with other systems

Applicable to Entities responsible for the reliability of the interconnected system (ERRIS)

Standard 1. The ERRIS must implement their Capacity and Energy Emergency plans,

when required and as appropriate, to reduce risks to the interconnected system 2. The ERRIS must communicate its current and future system conditions to

neighboring ERRIS and their Reliability Coordinator if they are experiencing an operating emergency.

Monitoring Responsibility Regional Reliability Councils (RRC)

Measuring Process Investigation

At the discretion of the RRC or NERC, an investigation may be initiated to review the operation of an ERRIS during a period when their system was highly stressed. This could occur as the result of contingencies, extreme difficulty in meeting system loads, or any other situation deemed noteworthy. Notification of

an investigation must be made by the RRC to the ERRIS being investigated as soon as possible, but no later than 60 days after the event. Measurement 1 The ERRIS will be reviewed to determine if their Capacity and Energy Emergency Plans were appropriately followed. (“Appropriately”, since for a particular situation, not all of the steps may be effective or required) Measurement 2- Evidence will be gathered to determine the level of communication between the ERRIS and other ERRIS. An assessment will be made by the investigator(s) as to whether the level and timing of communication of system conditions and actions taken to relieve emergency conditions was acceptable and in conformance with the Capacity and Energy Emergency Plans.

Investigation Time Frame The Regional Reliability Council must complete the evaluation of levels of compliance within 30 days of the start of the investigation or within a time frame as required by RRC procedures. Reporting Period Each event Full (100%) Compliance Requirements The ERRIS implemented their Capacity and Energy Emergency plans, when required and as appropriate and communicated its system conditions to neighboring ERRIS and their Reliability Authority as required. Levels of Non-Compliance

Level 1 –N/A Level 2 – N/A

Level 3 – One or more of the actions of the Capacity and Energy Emergency Plans were not implemented resulting in a prolonged abnormal system condition.

Level 4 – One or more of the actions of the Capacity and Energy Emergency Plans were not implemented resulting in a prolonged abnormal system condition and there was a delay or gap in communications.

Compliance Assessment Notes The intent of this measurement is to evaluate how well the entity followed its emergency procedures during stressed operating times. Since highly stressed is not a NERC defined term, for the sake of this template, the term means any occasion when the entity needed to implement most of its emergency action steps. Furthermore, when emergency procedures are implemented on consecutive days, the RRC need not initiate an investigation of each day, but shall select one of those days.

A time frame of 30 days after the start of the investigation or within a time frame as required by RRC procedures has been established to ensure that an ERRIS will have closure to any investigation within a reasonable time. Due to the changes that are occurring across the interconnections, it has become difficult to identify various sectors within each entity. To facilitate the development of the compliance program, the term ERRIS (Entities responsible for the reliability of the interconnected system) is being used in the Compliance Templates. An ERRIS can include, but is not limited to control areas, transmission operators, generation operators, balancing authorities etc. In this way, the applicability of each template can be determined by the Regional Reliability Councils to facilitate their particular organizational set up. Penalties/sanctions The sanction will be the larger of the fixed dollar amount shown in the Enforcement Table or the calculated dollar amount using the following sanction measures:

Miles of bulk transmission line in the ERRIS area operating at a nominal voltage 100kV and greater. Maximum amount of installed generating capacity in the ERRIS, in whole MW,




One year without a violation from the time of the violation Data retention requirements • The ERRIS is required to maintain data for 60 days following a stress event • After an investigation is completed, the RRC is required to keep the report of the

investigation on file for two years. Multiplier 1.0 Occurrence Period One calendar year

Compliance Templates P6 T1NERC Operating Standards

October 26, 2003


Section

Policy 6, Section B, Requirement 2

Brief Description Emergency Operations/Preparation of Capacity and Energy Emergency Plans

Applicable to


Capacity and Energy Emergency plans consistent with NERC Operating Policies shall be developed and maintained by each ERRIS to cope with operating emergencies.

Monitoring Responsibility

Regional Reliability Councils (RRC) Measuring Processes Review

The Regional Reliability Councils must review and evaluate emergency plans every three years to ensure that as a minimum they address the essential “Functional Areas of a Capacity and Energy Emergency Plan” listed below and to ensure that procedures are included to guide the operators in the implementation of the plan.

Self-Assessment

The RRC may elect to conduct yearly checks of the ERRIS that may take the form of a self-certification document in years that the full review is not done.

Reporting Period Each Calendar year Full (100%) Compliance Requirements

Capacity and Energy Emergency plans consistent with NERC Operating Policies have been developed and are being maintained to cope with operating emergencies.


Level 1 – One of the applicable “Functional Areas of a Capacity and Energy Emergency Plan” has not been addressed in the emergency plans.

Level 2 –Two of the applicable “Functional Areas of a Capacity and Energy Emergency Plan” have not been addressed in the emergency plans. Level 3 – Three of the applicable “Functional Areas of a Capacity and Energy Emergency Plan” have not been addressed in the emergency plans.

Level 4 – Four or more of the applicable “Functional Areas of a Capacity and Energy Emergency Plan” have not been addressed in the emergency plans.

Compliance Assessment Notes The following Functional Areas must be addressed in the Capacity and Energy Emergency plans. (It should be noted that some of the items may not be applicable as the responsibilities for the item may not rest with the entity being reviewed, and therefore, they should not be penalized for not having that item in the plan.) 1. Coordinating functions. The functions to be coordinated with and among

neighboring systems. (The plan should include references to coordination of actions among neighboring systems when the plans are implemented.)

2. Fuel supply. An adequate fuel supply and inventory plan which recognizes reasonable delays or problems in the delivery or production of fuel, fuel switching plans for units for which fuel supply shortages may occur, e.g., gas and light oil, and a plan to optimize all generating sources to optimize the availability of the fuel, if fuel is in short supply.

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.

7. Appeals to large customers. Appeals to large industrial and commercial customers to reduce non-essential energy use and start any customer-owned backup generation.

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

9. 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.

10. Notifying IPPs. Notification of co-generation and independent power producers to maximize output and availability.

11. 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.

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

13. Notification to ERRIS. Notification should be made to other ERRIS as the steps of the emergency plan are implemented.

Due to the changes that are occurring across the interconnections, it has become difficult to identify various sectors within each entity. To facilitate the development of the compliance program, the term ERRIS (Entities responsible for the reliability of the interconnected system) is being used in the Compliance Templates. An ERRIS can include, but is not limited to control areas, transmission operators, generation operators, balancing authorities etc. In this way, the applicability of each template can be determined by the Regional Reliability Councils to facilitate their particular organizational set up. Penalties/sanctions The sanction will be the larger of the fixed dollar amount shown in the Enforcement Table or the calculated dollar amount using the following sanction measures:

Miles of bulk transmission line in the ERRIS area operating at a nominal voltage 100kV and greater. Maximum amount of installed generating capacity in the ERRIS, in whole MW,



Compliance Reset Period • One calendar year • Due to the severity of the non-compliance, the RRC may decide to establish short-

term re-occurrence time frames Data retention requirements • The ERRIS must have its Capacity and Energy Emergency Plans available for a

review by the RRC

• The ERRIS must have the information from their last annual self-assessment available

Multiplier: 1.0 Occurrence Period- One calendar year


October 26, 2003


Section Policy 6, Section D Brief Description Emergency Operations/Preparation of Restoration Plans Applicable to

The entities responsible for the reliability of the interconnected system (ERRIS) Standard

Each ERRIS shall develop and periodically update a logical plan to reestablish its electric system in a stable and orderly manner in the event of a partial or total shut down of the system. (NERC Reference Document – Electric System Restoration)

Monitoring Responsibility Regional Reliability Councils (RRC) Measuring Processes

Periodic Review The Regional Reliability Councils must review and evaluate restoration plans every three years to ensure that as a minimum they address the essential items listed below.

1. Identification of the relationships and responsibilities of the personnel necessary to the restoration.

2. The provision for reliable black-start resources including: resources for startup power for generating units, sufficient fuel resources, transmission resources, and communication resources and power supplies.

3. Contingency plans for failed resources. 4. The necessary operating instructions and procedures for synchronizing

areas of the system that have become separated. 5. The necessary operating instructions and procedures to cover loss of

vital telecommunications systems.

6. The necessary operating instructions and procedures for restoring loads, including identification of critical load requirements.

7. A set of procedures for periodic review and updating the restoration plan (at least yearly) and provisions for simulating and, where practical, actual testing and verification of the resources and procedures (at least every three years).

8. Documentation that operating personnel have been trained in the implementation of the plan and have participated in restoration exercises.

Self-Assessment

The RRC may elect to conduct yearly checks of the ERRIS that may take the form of a self-certification document in years that the full review is not done.

Reporting Period

Each Calendar year or every three years as appropriate

Full Compliance The ERRIS has developed and periodically updates a logical plan to reestablish its electric system in a stable and orderly manner in the event of a partial or total shut down of the system. The plan addresses the essential items above under the heading “Periodic Review”.


Level 1 – The Restoration Plan has been developed, but does not include one of the items 1 through 8 above.

Level 2 – The Restoration Plan has been developed, but does not include two of the items 1 through 8 above.

Level 3 – The Restoration Plan has been developed but does not include three of the items 1 through 8 above.

Level 4 – There is no Restoration Plan in place, or the Restoration Plan does not include 4 or more of the items 1 through 8 above.

Compliance Assessment Notes: The NERC publication entitled “Electric System Restoration – A Reference Document” is included in the NERC Operating Policies as an appendix. It describes in detail what should be covered in a restoration plan.

Due to the changes that are occurring across the interconnections, it has become difficult to identify various sectors within each entity. To facilitate the development of the compliance program, the term ERRIS (Entities responsible for the reliability of the interconnected system) is being used in the Compliance Templates. An ERRIS can include, but is not limited to control areas, transmission operators, generation operators, balancing authorities etc. In this way, the applicability of each template can be determined by the Regional Reliability Councils to facilitate their particular organizational set up.

Penalties/sanctions The sanction will be the larger of the fixed dollar amount shown in the Enforcement

Table or the calculated dollar amount using the following sanction measures:

- Maximum amount of installed generating capacity in the ERRIS, in whole MW or, during the most recent calendar year.

- Miles of bulk transmission line in the ERRIS area operating at a nominal voltage100kV and greater.

- Average MW output of generation in the ERRIS in the most recent calendar year, in whole MW, calculated as the MW hour generation output during the year, divided by the number of hours in a year.

- Peak load in the ERRIS, in the preceding year in whole MW. -

Compliance Reset Period • One calendar year Data retention requirements • The ERRIS must have its Restoration Plans available for a review • The ERRIS must have the information from their last annual self-assessment

available Multiplier: 1.0 Occurrence Period- One calendar year



Personnel responsible for planning and operating interconnected bulk electric systems shall be trained, qualified, and have the responsibility and authority to implement actions.

Section Policy 8, Section A Brief Description Operating Personnel and Training/Responsibility and Authority Applicable to


The SYSTEM OPERATOR must have the responsibility and authority to implement real-time actions that ensure the stable and reliable operation of the BULK ELECTRIC SYSTEM.


The SYSTEM OPERATOR shall have the responsibility and authority to implement real-time actions that ensure the stable and reliable operation of the BULK ELECTRIC SYSTEM. (SEE COMPLIANCE ASSESSMENT NOTES CHECKLIST)

Measuring Processes

3-Year Review A review will be conducted every three years. The job description that identifies the SYSTEM OPERATOR’S authorities and responsibilities will be reviewed, as will the written operating procedures or other documents delineating the authority of a SYSTEM OPERATOR to take actions necessary to maintain the reliability of the Bulk Electric System during normal and emergency conditions.

Items to be measured - Availability of a clearly written job description that identifies the

System Operator's authorities and responsibilities - Written operating procedures delineating the authority of a System Operator and the actions a System Operator implements in response to system contingencies. - The demonstrated ability of the System Operator to take necessary actions to maintain reliability during normal and emergency conditions.

Self-certification The RRC will deliver a self-certification form based on the “Check List” in the Compliance Assessment Notes below, to the ERRIS as part of the self-certification of compliance process.

Levels of Non-Compliance Level 1 – The ERRIS meets four of the five items in the Checklist (Items 1-5). Level 2 – The ERRIS meets three of the five items in the Checklist (Items 1-5). Level 3 – The ERRIS meets two of the five items in the Checklist (Items 1-5). Level 4 – The ERRIS meets one or less of the five items in the Checklist (Items 1-5) or fails either interview described in #6 or #7 in the Checklist.


Checklist

1. A written job description exists which states in clear and unambiguous language the responsibilities and authorities of a SYSTEM OPERATOR. The job description also identifies SYSTEM PERSONNEL subject to the authority of the SYSTEM OPERATOR.

2. Written job description states the SYSTEM OPERATOR’S responsibility to comply with the NERC Operating Policies.

3. Written job description is readily accessible in the control room environment to all SYSTEM OPERATORS.

4. Written operating procedures state that during normal operating conditions, the SYSTEM OPERATOR has the authority to take or direct timely and appropriate real-time actions without obtaining approval from higher level personnel within the SYSTEM OPERATOR'S own OPERATING AUTHORITY.

5. Written operating procedures state that during emergency conditions the SYSTEM OPERATOR has the authority to take or direct timely and appropriate real-time actions, up to and including shedding of firm load to prevent or alleviate OPERATING SECURITY LIMIT violations. These actions are performed without obtaining approval from higher level personnel within the SYSTEM OPERATOR'S own OPERATING AUTHORITY.

OPTIONAL CHECKLIST ITEMS ITEMS 6 AND/OR 7 MAY BE ADDED TO THE SELF-CERTIFICATION PROCESS AT THE DISCRETION OF THE RRC. 6. Interviews with randomly selected SYSTEM OPERATORS confirm that they

have exercised their authority to implement actions during normal and emergency conditions. These actions were performed without being required to seek approval from higher level personnel within the SYSTEM OPERATOR'S own OPERATING AUTHORITY.

7. Interviews with randomly selected SYSTEM PERSONNEL, whose actions are directed by the SYSTEM OPERATOR acknowledge the responsibility and authority of the SYSTEM OPERATOR.


PENALTIES/SANCTIONS

The dollar sanction is the fixed dollar amount shown on the enforcement table.

Compliance Reset Period One calendar year Data Retention Period Continuous Multiplier: 1.0 Occurrence Period – One Calendar year


October 26, 2003


Personnel responsible for planning and operating interconnected bulk electric systems shall be trained, qualified, and have the responsibility and authority to implement actions.

Section Policy 8, Section C Brief Description Operating Personnel and Training/ Operating Authorities shall staff

required operating positions with NERC-Certified System Operators. Applicable to

Entity responsible for the reliability of the interconnected system (ERRIS)

Standard As of January 1st, 2001, an ERRIS that maintains a control center(s) for the real-time operation of the interconnected BULK ELECTRIC SYSTEM shall staff operating positions that meet the following criteria with NERC-Certified SYSTEM OPERATORS.

Positions that have the primary responsibility, either directly or through communications with others, for the real-time operation of the interconnected BULK ELECTRIC SYSTEM, and positions that are directly responsible for complying with NERC Operating Policies.

EXCEPTION – While in training to become an NERC-Certified SYSTEM OPERATOR, an uncertified individual may work only in a non-independent position and must be under the direct authority of an NERC-Certified SYSTEM OPERATOR.


THE ERRIS has NERC-Certified SYSTEM OPERATOR(S) on shift in required positions at all times, as per the requirements.

Exception: During a real-time operating emergency, the time when control is transferred from a primary control center to a backup control center shall not be included in the calculation of non-compliance. This time shall be limited to no more than four (4) hours.

Measuring Processes 3-Year Review A review will be conducted every three years. On the job records should be maintained for at least one rolling year, recording the staff on shift throughout the year. The reviewer will ask to see this document to verify that the measures were met for each month. Self-CertificationEach RRC will prepare and deliver a Self-certification form to allow self-certification of compliance to the measures. Exception Reporting Any violation of the standard must be reported to the RRC who will inform the NERC Compliance Director, indicating the reason for the non-compliance and the mitigation plans taken.


Level 1: The ERRIS did not meet the requirement for a total time greater than 0 hours and up to 12 hours during a one calendar month period for each required position. Level 2: The ERRIS did not meet the requirement for a total time greater than 12 hours and up to 36 hours during a one calendar month period for each required position. Level 3: The ERRIS did not meet the requirement for a total time greater than 36 hours and up to 72 hours during a one-month calendar period for each required position. Level 4: The ERRIS did not meet the requirement for a total time greater than 72 hours during a one calendar month period for each required position.

Compliance Assessment Notes If an ERRIS is applying the exception rule that allows an uncertified individual (in training), to work in a non-independent position under the direct authority of an NERC-Certified SYSTEM OPERATOR, the reviewer should note the time span that the exception has been applied to the individual, to ensure that the exception rule is not being misused.


PENALTIES/SANCTIONS

The dollar sanction is the fixed dollar amount shown on the enforcement table.

Compliance Reset Period One month without a violation Data Retention Period Present calendar year plus previous calendar year shift schedules Multiplier: 1.0 Occurrence Period – One calendar month




Section Policy 9 Section A, Requirements 1, 1.1, 1.2 Brief Description Reliability Coordinator Procedures/Next day Operations Planning Applicable to


Standard Each Reliability Coordinator shall ensure that next-day security analyses are carried out to ensure the bulk power system can be operated in anticipated normal and contingency conditions. Studies shall be conducted to highlight potential interface and other operating limits including overloaded transmission lines and transformers, voltage and stability limits, etc.


The Reliability Coordinator is found to have conducted systems studies as required by the standard.

Measuring Processes


Self-CertificationEach Reliability Coordinator will annually, self-certify compliance to the measures as required by its RRC.

Exception Reporting

Reliability Coordinators will report monthly, any days that System Studies were not conducted as required to highlight potential interface and other operating limits including overloaded transmission lines and transformers, voltage and stability limits, etc. Reports will be sent to the NERC Compliance Director.

Levels of Non-Compliance Level 1- System Studies were not conducted as required for one day in a calendar month. Level 2 – System Studies were not conducted as required, for 2-3 days in a calendar month. Level 3 – System Studies were not conducted as required, for 4-5 days in a calendar month. Level 4 – System Studies were not conducted as required, for more than 5 days in a calendar month.

Compliance Assessment Notes Periodic Review and Investigation

.For a selected 30-day period, in the past three calendar months, Reliability Coordinators will provide documentation showing that they conducted next-day security analyses to ensure the bulk power system could be operated in anticipated normal and contingency conditions. Also, that they identified potential interface and other operating limits including overloaded transmission lines and transformers, voltage and stability limits, etc. Study case results and related documentation shall be available for this review for 3 months preceding the present month.

Regions will define days for which actual day-ahead studies are required.

Penalties/sanctions The sanction will be the larger of the fixed dollar amount shown in the Enforcement Table or the calculated dollar amount using the following sanction measures: The average annual generation of the territory administered by the Reliability

Coordinator The average annual load of the territory administered by the Reliability Coordinator The total circuit miles of transmission above 100kV of the territory administered by

the Reliability Coordinator. Compliance Reset Period


3 preceding calendar months (documentation as described above, not study data) Multiplier: 1 Occurrence Period –One calendar month




Section Policy 9, Section C, Requirement 3, 3.2.2.1

Appendix C1, Section A, Requirement 5 Appendix C1, Section A, Requirement 4 4.3

Brief Description Reliability Coordinator Procedures/Implementing Transmission system relief.

Applicable to


Standard A Reliability Coordinator must take appropriate actions in accordance with established policies, procedures, authority and expectations, to relieve transmission loading when requested by another Reliability Coordinator including notifying appropriate CONTROL AREAS to curtail INTERCHANGE TRANSACTIONS.

Monitoring Responsibility Regional Reliability Council (RRC) Measurement The Reliability Coordinator took appropriate actions in accordance with established policies, procedures, authority and expectations, to relieve transmission loading when requested by another Reliability Coordinator. Measuring Processes

Investigation A complaint that an entity is not meeting the requirements of this measure may trigger an investigation. Either the RRC or NERC Compliance Director will initiate the investigation.


Level 1 – N/A

Level 2 – N/A Level 3 – N/A Level 4 – The Reliability Coordinator did not comply with the provisions of their established procedures, including correct implementation of holds or curtailments consistent with the procedures.


For the Eastern Interconnection, TLR Procedure notification documentation, Operator logs of sink and neighbor control areas as well as related electronic communications are subject to field review.

Any repeat violations will be considered as 2nd, 3rd occurrences etc. until the violator has completed two months without violations.

See Appendix 9C1-Transmission Loading Relief Procedure – for the Eastern Interconnection. ERCOT and WSCC procedures are also documented in Appendices to Policy 9.

Penalties/sanctions The sanction will be the larger of the fixed dollar amount shown in the Enforcement Table or the calculated dollar amount using the following sanction measures: The total circuit miles of transmission above 100kV of the territory administered by



Coordinator Compliance Reset Period

One month without a violation Data retention requirements 90 days Multiplier: 1.0 Occurrence Period – One calendar year


October 26, 2003



Section Policy 9, Section C, Requirement 4 Brief Description Reliability Coordinator Procedures/Current Day Operations-Authority to

Implement Emergency Procedures

Applicable to Reliability Coordinators

Standard Reliability Coordinators must have the authority to immediately direct Operating Entities within their Security Area to re-dispatch generation, reconfigure transmission, or reduce load to mitigate critical conditions until Interchange Transactions can be reduced utilizing a transmission loading relief, or other transmission loading control procedures, to return the system to a reliable state

Monitoring Responsibility Regional Reliability Councils (RRC) Measuring Process

Periodic Review The Regional Reliability Council must review Reliability Coordinator at least every three years to ensure that the Reliability Authority has the authority to immediately direct Operating Authorities within their Security Area to re-dispatch generation, reconfigure transmission, or reduce load to mitigate critical conditions until Interchange Transactions can be reduced utilizing a transmission loading relief procedure, or other transmission loading control procedures, to return the system to a reliable state An agreement is in place with the entities being directed, that give the RC the authority to direct Operating Authorities within their Security Area to immediately re-dispatch

generation, reconfigure transmission, or reduce load to mitigate critical conditions and return the system to a reliable state

Full Compliance Reliability Coordinators have the authority to re-dispatch generation, reconfigure transmission, or reduce load to mitigate critical conditions until Interchange Transactions can be reduced utilizing a transmission loading relief procedure, or other transmission loading control procedures, to return the system to a reliable state.

Levels of Non-Compliance Level 1 – N/A Level 2 – N/A Level 3 – Reliability Coordinators indicate that they have the authority as required; however documentation does not support this claim. Level 4 – the Reliability Coordinators do not have the authority to re-dispatch generation, reconfigure transmission, or reduce load to mitigate critical conditions until Interchange Transactions can be reduced utilizing a transmission loading relief procedure, or other procedures, to return the system to a reliable state.


Documentation must be provided which clearly demonstrates that the Reliability Coordinators have been given the authority to re-dispatch generation, reconfigure transmission, or reduce load by all of the Operating Authorities within its security area.


Agreement

An agreement is a contract or other document delineating an arrangement that expresses assent by two or more parties to the same object. This arrangement determines a course of action to be followed by all parties involved in the situation. The key components of the agreement must identify the ability, intent and authority of the parties. The requirement for these agreements can be satisfied in a variety of ways, including but not limited to: contracts, designation of authority documents, policies, procedures.

Penalties/Sanctions

The sanction will be the larger of the fixed dollar amount shown in the Enforcement Table or the calculated dollar amount using the following sanction measures: (Times the multiplier)

The total circuit miles of transmission above 100kV of the territory administered by the Reliability Coordinator. The average annual generation in MW of the territory administered by the Reliability


Coordinator The rated MVA of a generating unit.

Multiplier 1.0



Documentation must be available at all times. Occurrence Period One year from when the on-site review was completed or the self-certification was received.




Section Policy 9, Appendix B, Requirement 1.1 Brief Description Reliability Coordinator Procedures/Energy Emergency Alerts Applicable to

Reliability Coordinators Standard An Energy Emergency Alert may be initiated only by a RELIABILITY

COORDINATOR at: 1) The RELIABILITY COORDINATOR’S own decision 2) The request of a CONTROL AREA 3) The request of a LOAD SERVING ENTITY.

Note: The cost of available resources shall not be a consideration for initiating an alert. Monitoring Responsibility Regional Reliability Council (RRC)

Measurement

Reliability Coordinator initiated an Energy Emergency Alert, as per the requirements.

Measuring Processes

Investigations At the discretion of a Region or NERC, an investigation may be initiated to review the operation of days when Control Areas were near to or experiencing the interruption of firm load, to determine if an Energy Emergency Alert should have been issued.

Levels of non-Compliance

Level 1 – NA

Level 2 – NA Level 3 – NA Level 4 – Emergency Alert not issued as required, (delete “issued when not required”)

Compliance Assessment Notes Penalties/sanctions The sanction will be the larger of the fixed dollar amount shown in the Enforcement Table or the calculated dollar amount using the following sanction measures: The total circuit miles of transmission above 100kV of the territory administered by



Coordinator

Compliance Reset Period One year without a violation from the time of the violation

Data retention requirements


2004 operating templates

Documents