NORMES DE FIABILITÉ DE LA NERC - BAL (VERSION ANGLAISE)

Transcription

1 COORDONNATEUR DE LA FIABILITÉ Direction Contrôle des mouvements d énergie Demande R NORMES DE FIABILITÉ DE LA NERC - BAL (VERSION ANGLAISE) Original : HQCMÉ-8, Document 2.4 Révisé : (En liasse)

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3 Standard BAL a Real Power Balancing Control Performance A. Introduction 1. Title: Real Power Balancing Control Performance 2. Number: BAL a 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: May 13, 2009 B. Requirements 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. ACE i AVG * 1 10 Period F Bi 1 The equation for ACE is: 2 1 or AVG Period ACEi 10 Bi * F1 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 ( i L 10 minute ACE ) 10 Adopted by the Régie de l'énergie (Decision D-201x-xx): Month xx, 201x Page 1 of 7

4 Standard BAL a Real Power Balancing Control Performance where: L 10 = ( 10 i)( 10 s) B B 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 = ( 1) 12 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 10B clock-minute = ACE n sampling cyclesin clock-minute sampling cyclesin clock-minute -10B F Fclock-minute = n sampling cyclesin clock-minute sampling cyclesin clock-minute The Balancing Authority s clock-minute compliance factor (CF) becomes: Adopted by the Régie de l'énergie (Decision D-201x-xx): Month xx, 201x Page 2 of 7

5 Standard BAL a Real Power Balancing Control Performance CF ACE 10B clock -minute = * Fclock-minute 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 CFclock-hour = n clock-minute 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 = [(CF days-in-month clock-hour [ n )( n one-minute samplesin clock-hour one-minute samplesin clock-hour days-in month ] )] CF month = hours-in-day [(CF clock-hour average-month [ n )( n one-minute samples in clock-hour averages one-minute samples in clock-hour averages hours-in day ] )] The 12-month compliance factor becomes: CF 12-month 12 ( CF month-i i= 1 = 12 i= 1 [ n )( n ( one-minute samples in month ) (one-minute samples in month)-i ] 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: CPS2 = 1 Violations ( Total Periods Unavailable Periods ) month month 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. Adopted by the Régie de l'énergie (Decision D-201x-xx): Month xx, 201x Page 3 of 7

6 Standard BAL a Real Power Balancing Control Performance Violation clock-ten-minutes n = 0 if ACE samples in 10-minutes L 10 n = 1 if ACE samples in 10-minutes > L 10 D. Compliance 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. 1. Compliance Monitoring Process 1.1. Compliance Monitoring Responsibility Regional Reliability Organization Compliance Monitoring Period and Reset Timeframe One calendar month 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 Additional Compliance Information None. 2. Levels of Non-Compliance CPS Level 1: The Balancing Authority Area s value of CPS1 is less than 100% but greater than or equal to 95% Level 2: The Balancing Authority Area s value of CPS1 is less than 95% but greater than or equal to 90%. Adopted by the Régie de l'énergie (Decision D-201x-xx): Month xx, 201x Page 4 of 7

7 Standard BAL a Real Power Balancing Control Performance 2.3. Level 3: The Balancing Authority Area s value of CPS1 is less than 90% but greater than or equal to 85% Level 4: The Balancing Authority Area s value of CPS1 is less than 85%. 3. Levels of Non-Compliance CPS Level 1: The Balancing Authority Area s value of CPS2 is less than 90% but greater than or equal to 85% Level 2: The Balancing Authority Area s value of CPS2 is less than 85% but greater than or equal to 80% Level 3: The Balancing Authority Area s value of CPS2 is less than 80% but greater than or equal to 75% Level 4: The Balancing Authority Area s value of CPS2 is less than 75%. E. Regional Differences 1. The ERCOT Control Performance Standard 2 Waiver approved November 21, F. Associated Documents 1. Appendix 2 Interpretation of Requirement R1 (October 23, 2007). Version History Version Date Action Change Tracking 0 February 8, 2005 BOT Approval New 0 April 1, 2005 Effective Implementation Date New 0 August 8, 2005 Removed Proposed from Effective Date Errata 0 July 24, 2007 Corrected R3 to reference M1 and M2 instead of R1 and R2 0a December 19, 2007 Added Appendix 2 Interpretation of R1 approved by BOT on October 23, a 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 Revised Errata 0 January 23, 2008 Reversed errata change from July 24, 2007 Errata 0.1a October 29, 2008 Board approved errata changes; updated version number to 0.1a 0.1a May 13, 2009 Approved by FERC Errata Adopted by the Régie de l'énergie (Decision D-201x-xx): Month xx, 201x Page 5 of 7

8 Standard BAL a Real Power Balancing Control Performance Appendix 1-BAL CPS1 and CPS2 Data CPS1 DATA Description Retention Requirements ε 1 A constant derived from the targeted frequency bound. This number is the same for each Balancing Authority Area in the Interconnection. Retain the value of ε 1 used in CPS1 calculation. ACE i The clock-minute average of ACE. Retain the 1-minute average values of ACE (525,600 values). B i The Frequency Bias of the Balancing Authority Area. Retain the value(s) of B i used in the CPS1 calculation. F A The actual measured frequency. Retain the 1-minute average frequency values (525,600 values). F S Scheduled frequency for the Interconnection. Retain the 1-minute average frequency values (525,600 values). CPS2 DATA Description Retention Requirements V ε 10 B i B s U 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. The Frequency Bias of the Balancing Authority Area. 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 values of V used in CPS2 calculation. Retain the value of ε 10 used in CPS2 calculation. Retain the value of B i used in the CPS2 calculation. 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. Adopted by the Régie de l'énergie (Decision D-201x-xx): Month xx, 201x Page 6 of 7

9 Standard BAL a Real Power Balancing Control Performance Interpretation of Requirement 1 Appendix 2 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 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. Adopted by the Régie de l'énergie (Decision D-201x-xx): Month xx, 201x Page 7 of 7

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11 Standard BAL a Real Power Balancing Control Performance Appendix QC-BAL a Provisions specific to the standard BAL a 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 a 3. Purpose: 4. Applicability: 5. Effective Date: 5.1. Adoption of the standard by the Régie de l énergie: Month xx 201x 5.2. Adoption of the appendix by the Régie de l énergie: Month xx 201x 5.3. Effective date of the standard and its appendix in Québec: Month xx 201x B. Requirements C. Measures D. Compliance 1. Compliance Monitoring Process 1.1. Compliance Monitoring Responsibility The Régie de l énergie is responsible, in Québec, for compliance monitoring with respect to the reliability standard and its appendix that it adopts Compliance Monitoring Period and Reset Timeframe 1.3. Data Retention 1.4. Additional Compliance Information 2. Levels of Non-Compliance CPS1 3. Levels of Non-Compliance CPS2 E. Regional Differences Adopted by the Régie de l énergie (Decision D-201x-xxxx): Month xx, 201x Page QC-1 of 2

12 Standard BAL a Real Power Balancing Control Performance Appendix QC-BAL a Provisions specific to the standard BAL a applicable in Québec F. Associated Documents Appendix 1 BAL Appendix 2 Version Revision History of the Appendix VersionRevi Adoption Date Action Change Tracking sion 0 Month xx, 201x New appendix New Adopted by the Régie de l énergie (Decision D-201x-xxxx): Month xx, 201x Page QC-2 of 2

13 Standard BAL Disturbance Control Performance A. Introduction 1. Title: Disturbance Control Performance 2. Number: BAL 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 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, Adopted by the Régie de l'énergie (Decision D-2012-xxxx): Month xx, 201x

14 Standard BAL 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. C. Measures 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. 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 A < 0 then Adopted by Board of Trustees: August 5, Adopted by the Régie de l'énergie (Decision D-2012-xxxx): Month xx, 201x

15 Standard BAL Disturbance Control Performance R i = MW Loss max(0, ACE MW Loss A ACE M ) *100% if ACE A > 0 then R i = MW Loss max(0, ACE MW Loss M ) *100% where: MW LOSS is the MW size of the Disturbance as measured at the beginning of the loss, ACE A is the pre-disturbance ACE, ACE M 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. 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 = - 25 MW. ACE The average percent recovery is the arithmetic average of all the calculated R i s for Reportable Disturbances during a given quarter. Average percent recovery is similarly calculated for excludable Disturbances. D. Compliance 1. Compliance Monitoring Process Adopted by Board of Trustees: August 5, Adopted by the Régie de l'énergie (Decision D-2012-xxxx): Month xx, 201x

16 Standard BAL Disturbance Control Performance 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 Compliance Enforcement Authority Regional Entity Compliance Monitoring Period and Reset Timeframe Compliance for DCS will be evaluated for each reporting period. Reset is one calendar quarter without a violation 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 Additional Compliance Information 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 Adopted by Board of Trustees: August 5, Adopted by the Régie de l'énergie (Decision D-2012-xxxx): Month xx, 201x

17 Standard BAL 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 Date Action Change Tracking 0 April 1, 2005 Effective Date New 0 August 8, 2005 Removed Proposed from Effective Date Errata 0 February 14, 2006 Revised graph on page 3, 10 min. to Recovery time. Removed fourth bullet. 1 TBD Modified to address Order No. 693 Directives contained in paragraph 321. Errata Revised. Adopted by Board of Trustees: August 5, Adopted by the Régie de l'énergie (Decision D-2012-xxxx): Month xx, 201x

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19 Standard BAL Disturbance Control Performance Appendix QC-BAL Provisions specific to the standard BAL 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: Disturbance Control Performance 2. Number: BAL Purpose: 4. Applicability: 5. Effective Date: 5.1. Adoption of the standard by the Régie de l énergie: Month xx 201x 5.2. Adoption of the appendix by the Régie de l énergie: Month xx 201x 5.3. Effective date of the standard and its appendix in Québec: Month xx 201x B. Requirements C. Measures D. Compliance 1. Compliance Monitoring Process 1.1. Compliance Enforcement Authority The Régie de l énergie is responsible, in Québec, for compliance enforcement with respect to the reliability standard and its appendix that it adopts. The NERC remains responsible for compliance monitoring of the Regional Reliability Organization Compliance Monitoring Period and Reset Timeframe 1.3. Compliance Monitoring and Enforcement Processes 1.4. Data Retention 1.5. Additional Compliance Information 2. Levels of Non-Compliance Adopted by the Régie de l énergie (Decision D-201x-xxxx): Month xx, 201x Page QC-1 of 6

20 Standard BAL Disturbance Control Performance 3. Violation Severity Levels Appendix QC-BAL Provisions specific to the standard BAL applicable in Québec Requirement Lower Moderate High Severe R1 N/A N/A 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 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 R2 The Regional Reliability Organization, sub-regional Reliability Organization, or Reserve Sharing Group has failed to specify 1 of the following sub-requirements. The Regional Reliability Organization, sub-regional Reliability Organization, or Reserve Sharing Group has failed to specify 2 or 3 of the following sub-requirements. The Regional Reliability Organization, sub-regional Reliability Organization, or Reserve Sharing Group has failed to specify 4 or 5 of the following sub-requirements. The Regional Reliability Organization, sub-regional Reliability Organization, or Reserve Sharing Group has failed to specify all 6 of the following sub-requirements. R2.1 N/A N/A N/A The Regional Reliability Organization, sub-regional Reliability Organization, or Reserve Sharing Group has failed to specify the minimum reserve requirement for the group. Adopted by the Régie de l énergie (Decision D-201x-xxxx): Month xx, 201x Page QC-2 of 6

21 Standard BAL Disturbance Control Performance Appendix QC-BAL Provisions specific to the standard BAL applicable in Québec Requirement Lower Moderate High Severe R2.2 N/A N/A N/A The Regional Reliability Organization, sub-regional Reliability Organization, or Reserve Sharing Group has failed to specify the allocation of reserves among members. R2.3 N/A N/A N/A The Regional Reliability Organization, sub-regional Reliability Organization, or 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. R2.4 N/A N/A N/A The Regional Reliability Organization, sub-regional Reliability Organization, or Reserve Sharing Group has failed to provide the procedure for applying Contingency Reserve in practice. R2.5 N/A N/A N/A The Regional Reliability Organization, sub-regional Reliability Organization, or Reserve Sharing Group has failed to specify the limitations, if any, upon the amount of interruptible load that may be included. Adopted by the Régie de l énergie (Decision D-201x-xxxx): Month xx, 201x Page QC-3 of 6

22 Standard BAL Disturbance Control Performance Appendix QC-BAL Provisions specific to the standard BAL applicable in Québec Requirement Lower Moderate High Severe R2.6 N/A N/A N/A The Regional Reliability Organization, sub-regional Reliability Organization, or 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. R3 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 The Balancing Authority or Reserve Sharing Group failed to review its probable contingencies to determine its prospective most severe single contingencies annually as specified in R3.1. The Balancing Authority or Reserve Sharing Group s average percent recovery per the NERC DCS quarterly report was less than 95% but greater than or equal to 90%. The Balancing Authority or Reserve Sharing Group s average percent recovery per the NERC DCS quarterly report was less than 90% but greater than or equal to 85%. The Balancing Authority or Reserve Sharing Group s average percent recovery per the NERC DCS quarterly report was less than 85%. OR The Balancing Authority or Reserve Sharing Group failed to carry at least enough Contingency Reserve to cover the most severe single contingency as specified in R3.1. R3.1 N/A N/A N/A N/A Adopted by the Régie de l énergie (Decision D-201x-xxxx): Month xx, 201x Page QC-4 of 6

23 Standard BAL Disturbance Control Performance Appendix QC-BAL Provisions specific to the standard BAL applicable in Québec Requirement Lower Moderate High Severe R4 The Balancing Authority or Reserve Sharing Group met the Disturbance Recovery Criterion within the Disturbance Recovery Period for more than 90% and less than 100% of Reportable Disturbances. The Balancing Authority or Reserve Sharing Group met the Disturbance Recovery Criterion within the Disturbance Recovery Period for more than 80% and less than or equal to 90% of Reportable Disturbances. The Balancing Authority or Reserve Sharing Group met the Disturbance Recovery Criterion within the Disturbance Recovery Period for more than 70% and less than or equal to 80% of Reportable Disturbances. The Balancing Authority or Reserve Sharing Group met the Disturbance Recovery Criterion within the Disturbance Recovery Period for more than 0% and less than or equal to 70% of Reportable Disturbances. R4.1 N/A N/A N/A N/A R4.2 N/A N/A N/A N/A R5 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. The Reserve Sharing Group met the DCS requirements for more than 70% and less than or equal to 80% of Reportable Disturbances. The Reserve Sharing Group met the DCS requirements for more than 0% and less than or equal to 70% of Reportable Disturbances. R5.1 N/A N/A N/A N/A R5.2 N/A N/A N/A N/A R6 The Balancing Authority or Reserve Sharing Group failed to restore 5% or less of its contingency reserves during the Contingency Reserve Restoration Period. The Balancing Authority or Reserve Sharing Group failed to restore more than 5% up to (and including) 10% of its contingency reserves during the Contingency Reserve Restoration Period. The Balancing Authority or Reserve Sharing Group failed to restore more than 10% up to (and including) 15% of its Contingency Reserve during the Contingency Reserve Restoration Period. The Balancing Authority or Reserve Sharing Group failed to restore more than 15% of its Contingency Reserves during the Contingency Reserve Restoration Period. R6.1 N/A N/A N/A N/A R6.2 N/A N/A N/A N/A Adopted by the Régie de l énergie (Decision D-201x-xxxx): Month xx, 201x Page QC-5 of 6

24 Standard BAL Disturbance Control Performance Appendix QC-BAL Provisions specific to the standard BAL applicable in Québec E. Regional Differences Version Revision History of the Appendix VersionRevi sion Adoption Date Action Change Tracking 0 Month xx, 201x New appendix New Adopted by the Régie de l énergie (Decision D-201x-xxxx): Month xx, 201x Page QC-6 of 6

25 Standard BAL b Frequency Response and Bias A. Introduction 1. Title: Frequency Response and Bias 2. Number: BAL b 3. Purpose: This standard provides a consistent method for calculating the Frequency Bias component of ACE. 4. Applicability: 4.1. Balancing Authorities. 5. Effective Date: Immediately after approval of applicable regulatory authorities. B. Requirements R1. Each Balancing Authority shall review its Frequency Bias Settings by January 1 of each year and recalculate its setting to reflect any change in the Frequency Response of the Balancing Authority Area. R1.1. The Balancing Authority may change its Frequency Bias Setting, and the method used to determine the setting, whenever any of the factors used to determine the current bias value change. R1.2. Each Balancing Authority shall report its Frequency Bias Setting, and method for determining that setting, to the NERC Operating Committee. R2. Each Balancing Authority shall establish and maintain a Frequency Bias Setting that is as close as practical to, or greater than, the Balancing Authority s Frequency Response. Frequency Bias may be calculated several ways: R2.1. The Balancing Authority may use a fixed Frequency Bias value which is based on a fixed, straight-line function of Tie Line deviation versus Frequency Deviation. The Balancing Authority shall determine the fixed value by observing and averaging the Frequency Response for several Disturbances during on-peak hours. R2.2. The Balancing Authority may use a variable (linear or non-linear) bias value, which is based on a variable function of Tie Line deviation to Frequency Deviation. The Balancing Authority shall determine the variable frequency bias value by analyzing Frequency Response as it varies with factors such as load, generation, governor characteristics, and frequency. R3. Each Balancing Authority shall operate its Automatic Generation Control (AGC) on Tie Line Frequency Bias, unless such operation is adverse to system or Interconnection reliability. R4. Balancing Authorities that use Dynamic Scheduling or Pseudo-ties for jointly owned units shall reflect their respective share of the unit governor droop response in their respective Frequency Bias Setting. R4.1. Fixed schedules for Jointly Owned Units mandate that Balancing Authority (A) that contains the Jointly Owned Unit must incorporate the respective share of the unit governor droop response for any Balancing Authorities that have fixed schedules (B and C). See the diagram below. R4.2. The Balancing Authorities that have a fixed schedule (B and C) but do not contain the Jointly Owned Unit shall not include their share of the governor droop response in their Frequency Bias Setting. Adopted by the Régie de l'énergie (Decision D-201x-xx): Month xx, 201x Page 1 of 5

26 Standard BAL b Frequency Response and Bias Jointly Owned Unit A B C R5. Balancing Authorities that serve native load shall have a monthly average Frequency Bias Setting that is at least 1% of the Balancing Authority s estimated yearly peak demand per 0.1 Hz change. R5.1. Balancing Authorities that do not serve native load shall have a monthly average Frequency Bias Setting that is at least 1% of its estimated maximum generation level in the coming year per 0.1 Hz change. R6. A Balancing Authority that is performing Overlap Regulation Service shall increase its Frequency Bias Setting to match the frequency response of the entire area being controlled. A Balancing Authority shall not change its Frequency Bias Setting when performing Supplemental Regulation Service. C. Measures M1. Each Balancing Authority shall perform Frequency Response surveys when called for by the Operating Committee to determine the Balancing Authority s response to Interconnection Frequency Deviations. D. Compliance Not Specified. E. Regional Differences None identified. F. Associated Documents 1. Appendix 1 Interpretation of Requirement R3 (October 23, 2007). 2. Appendix 2 Interpretation of Requirements R2, R2.2, R5, and R5.1 (February 12, 2008). Version History Version Date Action Change Tracking 0 April 1, 2005 Effective Date New 0 August 8, 2005 Removed "Proposed" from Effective Date Errata 0 March 16, 2007 FERC Approval Order 693 New Adopted by the Régie de l'énergie (Decision D-201x-xx): Month xx, 201x Page 2 of 5

27 Standard BAL b Frequency Response and Bias 0a December 19, 2007 Added Appendix 1 Interpretation of R3 approved by BOT on October 23, 2007 Addition 0a July 21, 2008 FERC Approval of Interpretation of R3 Addition 0b February 12, 2008 Added Appendix 2 Interpretation of R2, R2.2, R5, and R5.1 approved by BOT on February 12, b January 16, 2008 Section F: added 1. ; changed hyphen to en dash. Changed font style for Appendix 1 to Arial; updated version number to 0.1b Addition Errata 0.1b October 29, 2008 BOT approved errata changes Errata 0.1a May 13, 2009 FERC Approved errata changes version changed to 0.1a (Interpretation of R2, R2.2, R5, and R5.1 not yet approved) 0.1b May 21, 2009 FERC Approved Interpretation of R2, R2.2, R5, and R5.1 Errata Addition Adopted by the Régie de l'énergie (Decision D-201x-xx): Month xx, 201x Page 3 of 5

28 Standard BAL b Frequency Response and Bias Interpretation of Requirement 3 Appendix 1 Request: Does the WECC Automatic Time Error Control Procedure (WATEC) violate Requirement 3 of BAL-003-0? Interpretation: Requirement 3 of BAL Frequency Response and Bias deals with Balancing Authorities using Tie-Line Frequency Bias as the normal mode of automatic generation control. BAL R3. Each Balancing Authority shall operate its Automatic Generation Control (AGC) on Tie Line Frequency Bias, unless such operation is adverse to system or Interconnection reliability. Tie-Line Frequency Bias is one of the three foundational control modes available in a Balancing Authority s energy management system. (The other two are flat-tie and flat-frequency.) Many Balancing Authorities layer other control objectives on top of their basic control mode, such as automatic inadvertent payback, CPS optimization, time control (in single BA Interconnections). As long as Tie-Line Frequency Bias is the underlying control mode and CPS1 is measured and reported on the associated ACE equation, there is no violation of BAL Requirement 3: ACE = (NI A NI S ) 10B (F A F S ) I ME Adopted by the Régie de l'énergie (Decision D-201x-xx): Month xx, 201x Page 4 of 5

29 Standard BAL b Frequency Response and Bias Appendix 2 Interpretation of Requirements R2, R2.2, R5, R5.1 Request: ERCOT specifically requests clarification that a Balancing Authority is entitled to use a variable bias value as authorized by Requirement R2.2, even though Requirement 5 seems not to account for the possibility of variable bias settings. Interpretation: The consensus of the Resources Subcommittee is that BAL Frequency Response and Bias Requirement R2 does not conflict with BAL Requirement R5. BAL Frequency Response and Bias Requirement 2 requires a Balancing Authority to analyze its response to frequency excursions as a first step in determining its frequency bias setting. The Balancing Authority may then choose a fixed bias (constant through the year) per Requirement 2.1, or a variable bias (varies with load, specific generators, etc.) per Requirement 2.2. BAL R2. Each Balancing Authority shall establish and maintain a Frequency Bias Setting that is as close as practical to, or greater than, the Balancing Authority s Frequency Response. Frequency Bias may be calculated several ways: R2.1. R2.2. The Balancing Authority may use a fixed Frequency Bias value which is based on a fixed, straight-line function of Tie Line deviation versus Frequency Deviation. The Balancing Authority shall determine the fixed value by observing and averaging the Frequency Response for several Disturbances during on-peak hours. The Balancing Authority may use a variable (linear or non-linear) bias value, which is based on a variable function of Tie Line deviation to Frequency Deviation. The Balancing Authority shall determine the variable frequency bias value by analyzing Frequency Response as it varies with factors such as load, generation, governor characteristics, and frequency. BAL Frequency Response and Bias Requirement 5 sets a minimum contribution for all Balancing Authorities toward stabilizing interconnection frequency. The 1% bias setting establishes a minimum level of automatic generation control action to help stabilize frequency following a disturbance. By setting a floor on bias, Requirement 5 also helps ensure a consistent measure of control performance among all Balancing Authorities within a multi-balancing Authority interconnection. However, ERCOT is a single Balancing Authority interconnection. The bias settings ERCOT uses do produce, on average, the best level of automatic generation control action to meet control performance metrics. The bias value in a single Balancing Authority interconnection does not impact the measure of control performance. BAL R5. Balancing Authorities that serve native load shall have a monthly average Frequency Bias Setting that is at least 1% of the Balancing Authority s estimated yearly peak demand per 0.1 Hz change. R5.1. Balancing Authorities that do not serve native load shall have a monthly average Frequency Bias Setting that is at least 1% of its estimated maximum generation level in the coming year per 0.1 Hz change. Adopted by the Régie de l'énergie (Decision D-201x-xx): Month xx, 201x Page 5 of 5

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31 Standard BAL b Frequency Response and Bias Appendix QC-BAL b Provisions specific to the standard BAL b 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: Frequency Response and Bias 2. Number: BAL b 3. Purpose: 4. Applicability: 5. Effective Date: 5.1. Adoption of the standard by the Régie de l énergie: Month xx 201x 5.2. Adoption of the appendix by the Régie de l énergie: Month xx 201x 5.3. Effective date of the standard and its appendix in Québec: Month xx 201x B. Requirements C. Measures D. Compliance E. Regional Differences F. Associated Documents Appendix 1 Appendix 2 Version Revision History of the Appendix VersionRevi Adoption Date Action Change Tracking sion 0 Month xx, 201x New appendix New Adopted by the Régie de l énergie (Decision D-201x-xxxx): Month xx, 201x Page QC-1 of 1

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33 Standard BAL Time Error Correction A. Introduction 1. Title: Time Error Correction 2. Number: BAL Purpose: The purpose of this standard is to ensure that Time Error Corrections are conducted in a manner that does not adversely affect the reliability of the Interconnection. 4. Applicability: 4.1. Reliability Coordinators 4.2. Balancing Authorities 5. Effective Date: April 1, 2005 B. Requirements R1. Only a Reliability Coordinator shall be eligible to act as Interconnection Time Monitor. A single Reliability Coordinator in each Interconnection shall be designated by the NERC Operating Committee to serve as Interconnection Time Monitor. R2. The Interconnection Time Monitor shall monitor Time Error and shall initiate or terminate corrective action orders in accordance with the NAESB Time Error Correction Procedure. R3. Each Balancing Authority, when requested, shall participate in a Time Error Correction by one of the following methods: R3.1. The Balancing Authority shall offset its frequency schedule by 0.02 Hertz, leaving the Frequency Bias Setting normal; or R3.2. The Balancing Authority shall offset its Net Interchange Schedule (MW) by an amount equal to the computed bias contribution during a 0.02 Hertz Frequency Deviation (i.e. 20% of the Frequency Bias Setting). R4. Any Reliability Coordinator in an Interconnection shall have the authority to request the Interconnection Time Monitor to terminate a Time Error Correction in progress, or a scheduled Time Error Correction that has not begun, for reliability considerations. C. Measures R4.1. Balancing Authorities that have reliability concerns with the execution of a Time Error Correction shall notify their Reliability Coordinator and request the termination of a Time Error Correction in progress. Not specified. D. Compliance Not specified. E. Regional Differences None identified. Adopted by NERC Board of Trustees: February 8, of 2 Effective Date: April 1, 2005 Adopted by the Régie de l'énergie: Month xx, 201x