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Stakeholder Comparison Comment Rationale Matrix 2012-09-06 AESO AUTHORITATIVE DOCUMENT PROCESS Alberta Reliability Standard – PRC-023-AB-2 Transmission Relay Loadability Date of Request for Comment [yyyy/mm/dd]: Period of Consultation [yyyy/mm/dd]: Comments From: 2012-09-06 2012-09-06 Company Name through 2012-09-28 Contact: Company Contact Phone: Company Contact Number E-mail: Date [yyyy/mm/dd]: Issued for Stakeholder Consultation: 2012-09-06 1 COMPARISON BETWEEN NERC PRC-023-02 AND ALBERTA PRC 023-AB-2 Transmission Relay Loadability Stakeholder Comments PRC-023-AB-2 Reason for Differences (Insert comments here) NERC PRC-023-2 Purpose Protective relay settings shall not limit transmission loadability; not interfere with system operators’ ability to take remedial action to protect system reliability and; be set to reliably detect all fault conditions and protect the electrical network from these faults. Purpose Applicability Applicability This reliability standard applies to: 4.1. Functional Entity 4.1 Transmission Owners with loadresponsive phase protection systems as described in PRC-023-2 - Attachment A, applied to circuits defined in 4.2.1 (Circuits Subject to Requirements R1 – R5). 4.1.2 Generator Owners with loadresponsive phase protection systems as described in PRC-0232 - Attachment A, applied to circuits defined in 4.2.1 (Circuits Subject to Requirements R1 – R5). 4.1.3 Distribution Providers with load-responsive phase protection systems as described in PRC-0232 - Attachment A, applied to circuits defined in 4.2.1(Circuits Subject to Requirements R1 – R5), AESO Replies The purpose of this reliability standard is to ensure the protective relay settings do not limit transmission loadability, do not interfere with an operator’s ability to take remedial action to protect the reliability of the system, and are set to reliably detect all fault conditions and protect the electrical network from these faults. (a) a legal owner of a transmission facility with load-responsive phase protection systems, as described in Appendix 1 applied to any one (1) or more of the following facilities: Issued for Stakeholder Consultation: 2012-09-06 (i) transmission lines operated at two hundred (200) kV and above; The terms used to describe applicable entities in proposed PRC023-AB-2 have been amended from the NERC version in order to correctly identify the applicable entities in Alberta and to align with terms included in the AESO’s Consolidated Authoritative Documents Glossary. . (ii) transmission lines operated below two hundred (200) kV which the ISO identifies as essential to the reliability of the bulk electric system as required in requirement R6.2; 2 COMPARISON BETWEEN NERC PRC-023-02 AND ALBERTA PRC 023-AB-2 Transmission Relay Loadability Stakeholder Comments PRC-023-AB-2 Reason for Differences (Insert comments here) NERC PRC-023-2 provided those circuits have bidirectional flow capabilities. 4.1.4 Planning Coordinator 4.2. Circuits 4.2.1 Circuits Subject to Requirements R1 – R5 4.2.1.1 Transmission lines operated at 200 kV and above. 4.2.1.2 Transmission lines operated at 100 kV to 200 kV selected by the Planning Coordinator in accordance with R6. 4.2.1.3 Transmission lines operated below 100 kV that are part of the BES and selected by the Planning Coordinator in accordance with R6. 4.2.1.4 Transformers with low voltage terminals connected at 200 kV and above. 4.2.1.5 Transformers with low voltage terminals connected at 100 kV to 200 kV selected by the Planning Coordinator in accordance with R6. 4.2.1.6 Transformers with low voltage terminals connected below 100 kV that are part of the BES and selected by the Planning Coordinator in accordance with R6. AESO Replies (iii) transformers with low voltage terminals connected at two hundred (200) kV and above; or (iv) transformers with low voltage terminals connected below two hundred (200) kV which the ISO identifies in accordance with requirement R6.2; (b) a legal owner of a generating unit, that also owns the associated switch yard, with load-responsive phase protection systems, as described in Appendix 1 applied to any one (1) or more of the following facilities: Issued for Stakeholder Consultation: 2012-09-06 (i) transmission lines operated at two hundred (200) kV and above; (ii) transmission lines operated below two hundred (200) kV which the ISO identifies as essential to the reliability of the bulk electric system as required in requirement R6.2; (iii) transformers with low voltage terminals 3 COMPARISON BETWEEN NERC PRC-023-02 AND ALBERTA PRC 023-AB-2 Transmission Relay Loadability Stakeholder Comments PRC-023-AB-2 Reason for Differences (Insert comments here) NERC PRC-023-2 4.2.2 Circuits Subject to Requirement R6 4.2.2.1 Transmission lines operated at 100 kV to 200 kV and transformers with low voltage terminals connected at 100 kV to 200 kV 4.2.2.2 Transmission lines operated below100 kV and transformers with low voltage terminals connected below 100 kV that are part of the BES. AESO Replies connected at two hundred (200) kV and above; or (iv) transformers with low voltage terminals connected below two hundred (200) kV which the ISO identifies in accordance with requirement R6.2; (c) a legal owner of an aggregated generating facility, that also owns the associated switch yard, with load-responsive phase protection systems, as described in Appendix 1 applied to any one (1) or more of the following facilities: (i) transmission lines operated at two hundred (200) kV and above; (ii) transmission lines operated below two hundred (200) kV which the ISO identifies as essential to the reliability of the bulk electric system as required in requirement R6.2; (iii) transformers with low voltage terminals connected at two hundred Issued for Stakeholder Consultation: 2012-09-06 4 COMPARISON BETWEEN NERC PRC-023-02 AND ALBERTA PRC 023-AB-2 Transmission Relay Loadability Stakeholder Comments PRC-023-AB-2 Reason for Differences (Insert comments here) NERC PRC-023-2 AESO Replies (200) kV and above; or (iv) transformers with low voltage terminals connected below two hundred (200) kV which the ISO identifies in accordance with requirement R6.2; and (d) the ISO. Issued for Stakeholder Consultation: 2012-09-06 5 COMPARISON BETWEEN NERC PRC-023-02 AND ALBERTA PRC 023-AB-2 Transmission Relay Loadability Stakeholder Comments PRC-023-AB-2 Reason for Differences (Insert comments here) NERC PRC-023-2 Effective Date The effective dates of the requirements in the PRC-023-2 standard corresponding to the applicable Functional Entities and circuits are summarized in Table 1:NERC Effective Dates. Effective Date January 1, 2014 for requirements R1, R2, R3, R4 and R5 for: (a) transmission lines operated at two hundred (200) kV and above; and AESO Replies The proposed effective date has been amended to allow a reasonable amount of time for Alberta entities to implement proposed PRC-023-AB-2 (b) transformers with low voltage terminals connected at two hundred (200) kV and above, July 1, 2014 for requirement R6. The date set out in the list the ISO maintains .for requirements R1, R2, R3, R4 and R5 for: R1 Each Transmission Owner, Generator Owner, and Distribution Provider shall use any one of the following criteria (Requirement R1, criteria 1 through 13) for any specific circuit terminal to prevent its (a) transmission lines operated below two hundred (200) kV which the ISO identifies as essential to the reliability of the bulk electric system; and (b) transformers with low voltage terminals connected below two hundred (200) kV the ISO identifies as essential to the reliability of the bulk electric system. R1 Each legal owner of a transmission facility, legal owner of a generating unit and legal owner of an aggregated generating facility must use one of the criteria set out in requirements R1.1 through R1.14, inclusive, for each specific circuit Issued for Stakeholder Consultation: 2012-09-06 Based on the list being posted by the AESO on July 1, 2014, the effective date for transmission lines and transformers on the list would be no earlier than July 1, 2016 (24 months from identification of the transmission lines) New Amended Deleted Alberta requirement R1 has been 6 NERC PRC-023-2 phase protective relay settings from limiting transmission system loadability while maintaining reliable protection of the BES for all fault conditions. Each Transmission Owner, Generator Owner, and Distribution Provider shall evaluate relay loadability at 0.85 per unit voltage and a power factor angle of 30 degrees. [Violation Risk Factor: High] [Time Horizon: Long Term Planning]. Criteria 1. Set transmission line relays so they do not operate at or below 150% of the highest seasonal Facility Rating of a circuit, for the available defined loading duration nearest 4 hours (expressed in amperes). COMPARISON BETWEEN NERC PRC-023-02 AND ALBERTA PRC 023-AB-2 Transmission Relay Loadability Stakeholder Comments PRC-023-AB-2 Reason for Differences (Insert comments here) terminal to prevent its phase protective drafted in accordance with the relay settings from limiting transmission AESO’s Alberta reliability standards system loadability while maintaining drafting principles to add clarity to reliable protection of the bulk electric the requirement. system for all fault conditions and evaluate the phase protective relay’s loadability at zero point eight five (0.85) per unit voltage and a power factor angle of thirty (30) degrees. AESO Replies . R1. Set transmission line relays so they do not operate at or below one hundred and fifty (150 %) percent of the highest seasonal facility rating of a circuit for the available defined loading duration nearest to four (4) hours, expressed in amperes; R1.2 Set transmission line relays so 2. Set transmission line relays so they do not operate at or below they do not operate at or below one hundred and fifteen (115 %) percent of the highest seasonal 15-minute facility Issued for Stakeholder Consultation: 2012-09-06 7 COMPARISON BETWEEN NERC PRC-023-02 AND ALBERTA PRC 023-AB-2 Transmission Relay Loadability Stakeholder Comments PRC-023-AB-2 Reason for Differences (Insert comments here) NERC PRC-023-2 115% of the highest seasonal 15minute Facility Rating1 of a circuit (expressed in amperes). AESO Replies rating of a circuit, expressed in amperes; R1.3 Set transmission line relays so 3. Set transmission line relays so they do not operate at or below 115% of the maximum theoretical power transfer capability (using a 90-degree angle between the sending-end and receiving-end voltages and either reactance or complex impedance) of the circuit (expressed in amperes) using one of the following to perform the power transfer calculation: of a circuit (expressed in amperes). R1.3.1 an infinite source, i.e. zero • An infinite source (zero source impedance) with a 1.00 per unit bus voltage at each end of the line. source impedance, with a one point zero zero (1.00) per unit bus voltage at each end of the transmission line; or • An impedance at each end of the line, which reflects the actual system source impedance with a 1.05 per unit voltage behind each source impedance. the transmission line, which reflects the actual system source impedance with a one point zero five (1.05) per unit voltage behind each source impedance; 4. Set transmission line relays on series compensated transmission lines so they do not operate at or 1 they do not operate at or below one hundred and fifteen (115%) percent of the maximum theoretical power transfer capability, using a ninety (90) degree angle between the sending-end and receiving-end voltages and either reactance or complex impedance, of the circuit, expressed in amperes, using one of the following to perform the power transfer calculation: R1.3.2 an impedance at each end of R1.4 Set transmission line relays on series compensated transmission lines When a 15-minute rating has been calculated and published for use in real-time operations, the 15-minute rating can be used to establish the loadability requirement for the protective relays Issued for Stakeholder Consultation: 2012-09-06 8 COMPARISON BETWEEN NERC PRC-023-02 AND ALBERTA PRC 023-AB-2 Transmission Relay Loadability Stakeholder Comments PRC-023-AB-2 Reason for Differences (Insert comments here) NERC PRC-023-2 below the maximum power transfer capability of the line, determined as the greater of: • 115% of the highest emergency rating of the series capacitor. • 115% of the maximum power transfer capability of the circuit (expressed in amperes), calculated in accordance with Requirement R1, criterion 3, using the full line inductive reactance. 5. Set transmission line relays on weak source systems so they do not operate at or below 170% of the maximum end-of-line three-phase fault magnitude (expressed in amperes). 6. Set transmission line relays applied on transmission lines connected to generation stations remote to load so they do not operate at or below 230% of the aggregated generation nameplate capability. AESO Replies so they do not operate at or below the maximum power transfer capability of the transmission line, determined as the greater of: (a) one hundred and fifteen (115 %) percent of the highest emergency rating of the series capacitor, or (b) one hundred and fifteen (115%) percent of the maximum power transfer capability of the circuit, expressed in amperes, calculated in accordance with requirement R1.3, using the full transmission line inductive reactance; R1.5 Set transmission line relays on weak source systems so they do not operate at or below one hundred and seventy (170%) percent of the maximum end-of-line three-phase fault magnitude, expressed in amperes; R1.6 Set transmission line relays applied on transmission lines connected to a generating unit or aggregated generating facility remote to load so they do not operate at or below two hundred and thirty (230%) percent of the total nameplate capability of all the generating units at the facility; R1.7 Set transmission line relays applied at the load center terminal, Issued for Stakeholder Consultation: 2012-09-06 9 COMPARISON BETWEEN NERC PRC-023-02 AND ALBERTA PRC 023-AB-2 Transmission Relay Loadability Stakeholder Comments PRC-023-AB-2 Reason for Differences (Insert comments here) NERC PRC-023-2 7. Set transmission line relays applied at the load center terminal, remote from generation stations, so they do not operate at or below 115% of the maximum current flow from the load to the generation source under any system configuration. AESO Replies remote from a generating unit or aggregated generating facility, so they do not operate at or below one hundred and fifteen (115%) percent of the maximum current flow from the load to the generation source under any system configuration; R1.8 Set transmission line relays 8. Set transmission line relays applied on the bulk system-end of transmission lines that serve load remote to the system so they do not operate at or below 115% of the maximum current flow from the system to the load under any system configuration. 9. Set transmission line relays applied on the load-end of transmission lines that serve load remote to the bulk system so they do not operate at or below 115% of the maximum current flow from the load to the system under any system configuration. 10. Set transformer fault protection relays and transmission line relays on transmission lines terminated applied on the system-end of transmission lines that serve load remote to the system so they do not operate at or below one hundred and fifteen (115%) percent of the maximum current flow from the system to the load under any system configuration; R1.9 Set transmission line relays applied on the load-end of transmission lines that serve load remote to the system so they do not operate at or below one hundred and fifteen (115%) of the maximum current flow from the load to the system under any system configuration; R1.10 Set transformer fault protection relays and transmission line relays on transmission lines terminated only with a transformer so that they do not operate at or below the greater of: Issued for Stakeholder Consultation: 2012-09-06 10 COMPARISON BETWEEN NERC PRC-023-02 AND ALBERTA PRC 023-AB-2 Transmission Relay Loadability Stakeholder Comments PRC-023-AB-2 Reason for Differences (Insert comments here) NERC PRC-023-2 only with a transformer so that the relays do not operate at or below the greater of: • 150% of the applicable maximum transformer nameplate rating (expressed in amperes), including the forced cooled ratings corresponding to all installed supplemental cooling equipment. AESO Replies (a) one hundred and fifty (150%) percent of the applicable maximum transformer nameplate rating, expressed in amperes, including the forced cooled ratings corresponding to all installed supplemental cooling equipment; or (b) one hundred and fifteen (115%) percent of the highest established emergency transformer rating; • 115% of the highest operator established emergency transformer rating 10.1 Set load responsive transformer fault protection relays, if used, such that the protection settings do not expose the transformer to a fault level and duration that exceeds the transformer’s mechanical withstand capability2 R1.11 Set load responsive transformer fault protection relays, if used, such that the protection settings do not expose the transformer to a fault level and duration that exceeds the transformer’s mechanical withstand capability; R1.12 For transformer overload protection relays that do not comply 11. For transformer overload protection relays that do not comply with requirement R1.10: (a) set the relays to allow the with the loadability component of 2 As illustrated by the “dotted line” in IEEE C57.109-1993 - IEEE Guide for Liquid-Immersed Transformer Through-Fault-Current Duration, Clause 4.4, Figure 4 Issued for Stakeholder Consultation: 2012-09-06 11 COMPARISON BETWEEN NERC PRC-023-02 AND ALBERTA PRC 023-AB-2 Transmission Relay Loadability Stakeholder Comments PRC-023-AB-2 Reason for Differences (Insert comments here) NERC PRC-023-2 Requirement R1, criterion 10 set the relays according to one of the following: . AESO Replies transformer to be operated at an overload level of at least one hundred and fifty (150%) percent of the maximum applicable nameplate rating, or one hundred and fifteen (115%) percent of the highest emergency transformer rating, whichever is greater; • Set the relays to allow the transformer to be operated at an overload level of at least 150% of the maximum applicable nameplate rating, or 115% of the (b) the protection relay must allow highest operator established overload in subsection 1.12(a) for at emergency transformer rating, least fifteen (15) minutes to allow the ISO to take controlled action to whichever is greater, for at least relieve the overload; 15 minutes to provide time for the operator to take controlled action (c) install supervision for the relays to relieve the overload. using either a top oil or simulated winding hot spot temperature element; and • Install supervision for the relays (d) the relay setting should be no less using either a top oil or simulated than one hundred (100°C) degrees winding hot spot temperature Celsius for the top oil or one element set no less than 100° C hundred and forty (140°C) degrees for the top oil temperature or no Celsius for the winding hot spot temperature; less than 140° C for the winding hot spot temperature3 3 4 IEEE standard C57.91, Tables 7 and 8, specify that transformers are to be designed to withstand a winding hot spot temperature of 180 degrees C, and Annex A cautions that bubble formation may occur above 140 degrees C Issued for Stakeholder Consultation: 2012-09-06 12 COMPARISON BETWEEN NERC PRC-023-02 AND ALBERTA PRC 023-AB-2 Transmission Relay Loadability Stakeholder Comments PRC-023-AB-2 Reason for Differences (Insert comments here) NERC PRC-023-2 12. When the desired transmission line capability is limited by the requirement to adequately protect the transmission line, set the transmission line distance relays to a maximum of 125% of the apparent impedance (at the impedance angle of the transmission line) subject to the following constraints: . a. Set the maximum torque angle (MTA) to 90 degrees or the highest supported by the manufacturer. b. Evaluate the relay loadability in amperes at the relay trip point at 0.85 per unit voltage and a power factor angle of 30 degrees. c. Include a relay setting component of 87% of the current calculated in Requirement R1, criterion 12 in the Facility Rating determination for the circuit. AESO Replies R1.13 When the desired transmission line capability is limited by the requirement to adequately protect the transmission line, set the transmission line distance relays to a maximum of one hundred and twenty five (125%) percent of the apparent impedance, at the impedance angle of the transmission line, subject to the following constraints: R1.13.1 Set the maximum torque angle to ninety (90) degrees or the highest setting supported by the manufacturer; R1.13.2 Evaluate the relay loadability in amperes at the relay trip point at zero point eight five (0.85) per unit voltage and a power factor angle of thirty (30) degrees; and R1.13.3 Include a relay setting component of eighty seven (87%) percent of the current calculated in requirement R1.13.2 in the facility rating determination for the circuit; and R1.14 Where other situations present 13. Where other situations present practical limitations on circuit practical limitations on circuit capability, set the phase protection relays so they do not operate at or below one hundred Issued for Stakeholder Consultation: 2012-09-06 13 COMPARISON BETWEEN NERC PRC-023-02 AND ALBERTA PRC 023-AB-2 Transmission Relay Loadability Stakeholder Comments PRC-023-AB-2 Reason for Differences (Insert comments here) NERC PRC-023-2 4 capability, set the phase protection relays so they do not operate at or below 115% of such limitations. and fifteen (115%) percent of such limitations. R2. Each Transmission Owner, Generator Owner, and Distribution Provider shall set its out-of-step blocking elements to allow tripping of phase protective relays for faults that occur during the loading conditions used to verify transmission line relay loadability per Requirement R1. [Violation Risk Factor: High] [Time Horizon: Long Term Planning] R2 Each legal owner of a transmission facility, legal owner of a generating unit and legal owner of an aggregated generating facility must set its outof-step blocking elements to allow tripping of phase protective relays for faults that occur during the loading conditions used to verify transmission line relay loadability per requirement R1. R3. Each Transmission Owner, Generator Owner, and Distribution Provider that uses a circuit capability with the practical limitations described in Requirement R1, criterion 6, 7, 8, 9, 12, or 13 shall use the calculated circuit capability as the Facility Rating of the circuit and shall obtain the agreement of the Planning Coordinator, Transmission Operator, and Reliability Coordinator with the calculated circuit capability. [Violation Risk Factor: Medium] [Time Horizon: R3 Any legal owner of a transmission facility, legal owner of a generating unit or legal owner of an aggregated generating facility that uses a circuit capability with the practical limitations described in requirements R1.6, R1.7, R1.8, R1.9, R1.13, or R1.14 must use the calculated circuit capability as the facility rating of the circuit and must obtain the agreement of the ISO to use the calculated circuit capability. AESO Replies New Amended Deleted Alberta requirement R2 has been drafted in accordance with the AESO’s Alberat reliability standards drafting principles to add clarity to the requirement. New Amended Deleted NERC requirement R3 has been amended in proposed PRC-023-AB-2 to identify requirements of the responsible entities in Alberta. Alberta Variance4: The WECC Reliability Coordinator is not included in Alberta requirement R3. NERC requirement R3 states that agreement shall be obtained from the Planning Coordinator, Transmission Operator, and Reliability Coordinator. The AESO is An Alberta variance is a change from the US Reliability Standard that the AESO has determined is material. Issued for Stakeholder Consultation: 2012-09-06 14 COMPARISON BETWEEN NERC PRC-023-02 AND ALBERTA PRC 023-AB-2 Transmission Relay Loadability Stakeholder Comments PRC-023-AB-2 Reason for Differences (Insert comments here) NERC PRC-023-2 the authority from which legal owners of transmission facilities, generating units and aggregated generating units will obtain agreement for the calculated circuit capability and the AESO will consult with the WECC Reliability Coordinator at its discretion. Long Term Planning] R4. Each Transmission Owner, Generator Owner, and Distribution Provider that chooses to use Requirement R1 criterion 2 as the basis for verifying transmission line relay loadability shall provide its Planning Coordinator, Transmission Operator, and Reliability Coordinator with an updated list of circuits associated with those transmission line relays at least once each calendar year, with no more than 15 months between reports. [Violation Risk Factor: Lower] [Time Horizon: Long Term Planning] AESO Replies R4 Any legal owner of a transmission facility, legal owner of a generating unit or legal owner of an aggregated generating facility that uses requirement R1.2 as the basis for verifying transmission line relay loadability must provide the ISO with an updated list of circuits associated with those transmission line relays at least once each calendar year, with no more than fifteen (15) months between reports. Issued for Stakeholder Consultation: 2012-09-06 New Amended Deleted Alberta requirement R4 has been drafted in accordance with the AESO’s Alberta reliability standards drafting principles to add clarity to the requirement. 15 COMPARISON BETWEEN NERC PRC-023-02 AND ALBERTA PRC 023-AB-2 Transmission Relay Loadability Stakeholder Comments NERC PRC-023-2 PRC-023-AB-2 Reason for Differences (Insert comments here) New R5. Each Transmission Owner, R5 Any legal owner of a transmission facility, legal owner Amended Generator Owner, and Distribution of a generating unit or legal owner Deleted Provider that sets transmission line relays according to Requirement R1 of an aggregated generating criterion 12 shall provide an updated facility that uses requirement R1.13 Alberta requirement R5 has been list of the circuits associated with as the basis for verifying drafted in accordance with the those relays to its Regional Entity at transmission line relay loadability AESO’s Alberta reliability standards least once each calendar year, with must provide the ISO with an drafting principles to add clarity to no more than 15 months between updated list of circuits associated the requirement. reports, to allow the ERO to compile with those transmission line relays a list of all circuits that have at least once each calendar year, protective relay settings that limit with no more than fifteen (15) circuit capability. [Violation Risk months between reports. Factor: Lower] [Time Horizon: Long Term Planning] New R6. Each Planning Coordinator shall R6 The ISO must conduct an Amended conduct an assessment at least assessment at least once each once each calendar year, with no calendar year, with no more than Deleted more than 15 months between fifteen (15) months between assessments, by applying the assessments, by applying the Alberta requirement R6 has been criteria in Attachment B to criteria in Appendix 2 to determine drafted in accordance with the determine the circuits in its Planning the circuits in its Planning Coordinator area for which the legal AESO’s Alberta reliability standards Coordinator area for which drafting principles to add clarity to owner of a transmission facility, Transmission Owners, Generator the requirement. legal owner of a generating unit Owners, and Distribution Providers must comply with Requirements R1 and legal owner of an aggregated generating facility must comply through R5. The Planning Coordinator shall: [Violation Risk with requirements R1 through R5. The ISO must: Factor: High] [Time Horizon: Long Term Planning] Issued for Stakeholder Consultation: 2012-09-06 AESO Replies 16 COMPARISON BETWEEN NERC PRC-023-02 AND ALBERTA PRC 023-AB-2 Transmission Relay Loadability Stakeholder Comments PRC-023-AB-2 Reason for Differences (Insert comments here) NERC PRC-023-2 6.1 Maintain a list of circuits subject to PRC-023-2 per application of Attachment B, including identification of the first calendar year in which any criterion in Attachment B applies. R6.1 Maintain a list of circuits per the application of Appendix 2, including an effective date that is no earlier than twenty-four (24) months from identification of the circuits; and 6.2 Provide the list of circuits to all Regional Entities, Reliability Coordinators, Transmission Owners, Generator Owners, and Distribution Providers within its Planning Coordinator area within 30 calendar days of the establishment of the initial list and within 30 calendar days of any changes to that list. R6.2 Provide the list of circuits to the legal owner of a transmission facility, legal owner of a generating unit and legal owner of an aggregated generating facility within its Planning Coordinator area within thirty (30) days of the establishment of the initial list and within thirty (30) days of any changes to that list. M1. Each Transmission Owner, Generator Owner, and Distribution Provider shall have evidence such as spreadsheets or summaries of calculations to show that each of its transmission relays is set according to one of the criteria in Requirement R1, criterion 1 through 13 and shall have evidence such as coordination curves or summaries of calculations that show that relays set per criterion 10 do not expose the MR1. Evidence of using one of the criteria set out in requirements R1.1 through R1.14 as required in requirement R1 exists. Evidence may include: Issued for Stakeholder Consultation: 2012-09-06 AESO Replies (a) spreadsheets or summaries of calculations to show that each of its transmission relays is set in accordance with one of the criteria set out in 17 COMPARISON BETWEEN NERC PRC-023-02 AND ALBERTA PRC 023-AB-2 Transmission Relay Loadability Stakeholder Comments PRC-023-AB-2 Reason for Differences (Insert comments here) requirements R1.1 through R1.14; and NERC PRC-023-2 transformer to fault levels and durations beyond those indicated in the standard. (R1) AESO Replies (b) coordination curves or summaries of calculations that show that relays set per criterion set out in requirement R1.11 do not expose the transformer to fault levels and durations beyond those indicated in the reliability standard. M2. Each Transmission Owner, Generator Owner, and Distribution Provider shall have evidence such as spreadsheets or summaries of calculations to show that each of its out-of-step blocking elements is set to allow tripping of phase protective relays for faults that occur during the loading conditions used to verify transmission line relay loadability per Requirement R1. (R2) MR2 Evidence of setting its out-ofstep blocking elements as required in requirement R2 exists. Evidence may include spreadsheets or summaries of calculations.. M3. Each Transmission Owner, Generator Owner, and Distribution Provider with transmission relays set according to Requirement R1, criterion 6, 7, 8, 9, 12, or 13 shall have evidence such as Facility MR3. Evidence of using, and obtaining the agreement to use, the calculated circuit capability as required in requirement R3 exists. Evidence may include: (a) facility rating spreadsheets or Issued for Stakeholder Consultation: 2012-09-06 18 COMPARISON BETWEEN NERC PRC-023-02 AND ALBERTA PRC 023-AB-2 Transmission Relay Loadability Stakeholder Comments PRC-023-AB-2 Reason for Differences (Insert comments here) facility rating database to show that the calculated circuit capability was used as the facility rating of the circuit; and NERC PRC-023-2 Rating spreadsheets or Facility Rating database to show that it used the calculated circuit capability as the Facility Rating of the circuit and evidence such as dated correspondence that the resulting Facility Rating was agreed to by its associated Planning Coordinator, Transmission Operator, and Reliability Coordinator. (R3) AESO Replies (b) dated correspondence to show that the ISO agreed to the calculated circuit capability. M4. Each Transmission Owner, Generator Owner, or Distribution Provider that sets transmission line relays according to Requirement R1, criterion 2 shall have evidence such as dated correspondence to show that it provided its Planning Coordinator, Transmission Operator, and Reliability Coordinator with an updated list of circuits associated with those transmission line relays within the required timeframe. The updated list may either be a full list, a list of incremental changes to the previous list, or a statement that there are no changes to the previous list. (R4) MR4 Evidence of providing the ISO with an updated list of circuits as required in requirement R4 exists. Evidence may include email or mail to the appropriate ISO recipient with the updated list which may either be a full list, a list of incremental changes to the previous list, or a statement that there are no changes to the previous list. M5. Each Transmission Owner, Generator Owner, or Distribution Provider that sets transmission line MR5 Evidence of providing the ISO with an updated list of circuits as required in requirement R5 exists. Issued for Stakeholder Consultation: 2012-09-06 19 NERC PRC-023-2 relays according to Requirement R1, criterion 12 shall have evidence such as dated correspondence that it provided an updated list of the circuits associated with those relays to its Regional Entity within the required timeframe. The updated list may either be a full list, a list of incremental changes to the previous list, or a statement that there are no changes to the previous list. (R5) M6. Each Planning Coordinator shall have evidence such as power flow results, calculation summaries, or study reports that it used the criteria established within Attachment B to determine the circuits in its Planning Coordinator area for which applicable entities must comply with the standard as described in Requirement R6. The Planning Coordinator shall have a dated list of such circuits and shall have evidence such as dated correspondence that it provided the list to the Regional Entities, Reliability Coordinators, Transmission Owners, Generator Owners, and Distribution Providers within its Planning Coordinator area COMPARISON BETWEEN NERC PRC-023-02 AND ALBERTA PRC 023-AB-2 Transmission Relay Loadability Stakeholder Comments PRC-023-AB-2 Reason for Differences (Insert comments here) Evidence may include email or mail to the appropriate ISO recipient with the updated list which may either be a full list, a list of incremental changes to the previous list, or a statement that there are no changes to the previous list. AESO Replies MR6. Evidence of conducting an assessment as required in requirement R6 exists. Evidence may include as power flow results, calculation summaries, or study reports that the ISO used the criteria established within Appendix 2 to determine the circuits in its Planning Coordinator area. MR6.1 Evidence of maintaining the list of circuits as required in requirement R6.1 exists. Evidence may include a documented list of circuits with the effective date and the revision history captured. MR6.2 Evidence of providing the list Issued for Stakeholder Consultation: 2012-09-06 20 NERC PRC-023-2 within the required timeframe. COMPARISON BETWEEN NERC PRC-023-02 AND ALBERTA PRC 023-AB-2 Transmission Relay Loadability Stakeholder Comments PRC-023-AB-2 Reason for Differences (Insert comments here) of circuits as required in requirement R6.2 exists. Evidence may include email or mail to the applicable entities. Compliance To view the compliance section D of the NERC reliability standard follow this link: http://www.nerc.com/files/BAL-0020.pdf AESO Replies The Alberta reliability standards do not contain a compliance section. Compliance with all Alberta reliability standards is completed in accordance with the Alberta Reliability Standards Compliance Monitoring Program, available on the AESO website at: http://www.aeso.ca/loadsettlement/1 7189.html Regional Differences Regional Differences None identified. None identified. Issued for Stakeholder Consultation: 2012-09-06 21 Table 1: NERC Effective Dates – Per Applicability Section for Alberta (this table will not be included in the final Alberta version) Requirement Applicability NERC: Each Transmission Owner, Generator Owner, and Distribution Provider with transmission lines operating at 200 kV and above and transformers with low voltage terminals connected at 200 kV and above, except as noted below. Effective Date Jurisdictions where Regulatory Approval Jurisdictions where No Regulatory is Required Approval is Required NERC: First day of the first calendar quarter, NERC: First calendar quarter after Board of after applicable regulatory approvals Trustees adoption AB: Per Effective Date Section above. AB: N/A NERC: First day of the first calendar quarter 12 months after applicable regulatory approvals NERC: First day of the first calendar quarter 12 months after Board of Trustees adoption AB: Per Applicability Section above. NERC: • For Requirement R1, criterion 10.1, to set transformer fault protection relays on transmission lines terminated only with a transformer such that the protection settings do not expose the transformer to fault level and duration that exceeds its mechanical withstand capability AB: N/A AB: Per Effective Date Section above. R1 AB: Per Applicability Section above. NERC: • For supervisory elements as described in PRC-023-2 Attachment A, Section 1.6 NERC: First day of the first calendar quarter 24 months after applicable regulatory approvals AB: Per Applicability Section above. NERC: For switch-on-to-fault schemes as described in PRC-023-2 Attachment A, Section 1.3 AB: Per Applicability Section above. 5 NERC: First day of the first calendar quarter 24 months after Board of Trustees adoption AB: N/A AB: Per Effective Date Section above. NERC: Later of the first day of the first calendar quarter after applicable regulatory approvals of PRC-023-2 or the first day of the first calendar quarter 39 months following applicable regulatory approvals of PRC-023-1 NERC: Later of the first day of the first calendar quarter after Board of Trustees adoption of PRC-023-2 or July 1, 20115 AB: N/A 1 July 1, 2011 is the first day of the first calendar quarter 39 months following the Board of Trustees February 12, 2008 approval of PRC-023-1. Issued for Stakeholder Consultation: 2012-09-06 22 (October 1, 2013) NERC: Each Transmission Owner, Generator Owner, and Distribution Provider with circuits identified by the Planning Coordinator pursuant to Requirement R6 AB: Per Applicability Section above. NERC: Each Transmission Owner, Generator Owner, and Distribution Provider with transmission lines operating at 200 kV and above and transformers with low voltage terminals connected at 200 kV and above AB: Per Effective Date Section above. NERC: Later of the first day of the first calendar quarter 39 months following notification by the Planning Coordinator of a circuit’s inclusion on a list of circuits subject to PRC-023-2 per application of Attachment B, or the first day of the first calendar year in which any criterion in Attachment B applies, unless the Planning Coordinator removes the circuit from the list before the applicable effective date NERC: Later of the first day of the first calendar quarter 39 months following notification by the Planning Coordinator of a circuit’s inclusion on a list of circuits subject to PRC-023-2 per application of Attachment B, or the first day of the first calendar year in which any criterion in Attachment B applies, unless the Planning Coordinator removes the circuit from the list before the applicable effective date AB: Per Effective Date Section above. AB: N/A NERC: First day of the first calendar quarter after applicable regulatory approvals NERC: First day of the first calendar quarter after Board of Trustees adoption AB: Per Effective Date Section above. AB: N/A NERC: Later of the first day of the first calendar quarter 39 months following notification by the Planning Coordinator of a circuit’s inclusion on a list of circuits subject to PRC-023-2 per application of Attachment B, or the first day of the first calendar year in which any criterion in Attachment B applies, unless the Planning Coordinator removes the circuit from the list before the applicable effective date NERC: Later of the first day of the first calendar quarter 39 months following notification by the Planning Coordinator of a circuit’s inclusion on a list of circuits subject to PRC-023-2 per application of Attachment B, or the first day of the first calendar year in which any criterion in Attachment B applies, unless the Planning Coordinator removes the circuit from the list before the applicable effective date AB: Per Effective Date Section above. AB: N/A AB: Per Applicability Section above. R2 and R3 NERC: Each Transmission Owner, Generator Owner, and Distribution Provider with circuits identified by the Planning Coordinator pursuant to Requirement R6 AB: Per Applicability Section above. Issued for Stakeholder Consultation: 2012-09-06 23 R4 R5 NERC: Each Transmission Owner, Generator Owner, and Distribution Provider that chooses to use Requirement R1 criterion 2 as the basis for verifying transmission line relay loadability NERC: First day of the first calendar quarter six months after applicable regulatory approvals NERC: First day of the first calendar quarter six months after Board of Trustees adoption AB: Per Applicability Section above. AB: Per Effective Date Section above. AB: N/A NERC: Each Transmission Owner, Generator Owner, and Distribution Provider that sets transmission line relays according to Requirement R1 criterion 12 NERC: First day of the first calendar quarter six months after applicable regulatory approvals NERC: First day of the first calendar quarter six months after Board of Trustees adoption AB: Per Applicability Section above. AB: Per Effective Date Section above. NERC: Each Planning Coordinator shall conduct an assessment by applying the criteria in Attachment B to determine the circuits in its Planning Coordinator area for which Transmission Owners, Generator Owners, and Distribution Providers must comply with Requirements R1 through R5 NERC: First day of the first calendar quarter 18 months after applicable regulatory approvals AB: N/A R6 NERC: First day of the first calendar quarter 18 months after Board of Trustees adoption AB: N/A AB: Per Effective Date Section above. AB: ISO Issued for Stakeholder Consultation: 2012-09-06 24 Table 2: NERC Violation Severity Levels – Not Used in Alberta (this table will not be included in the final Alberta version) Requirement Lower Moderate High N/A N/A N/A N/A N/A N/A N/A N/A N/A R1 R2 R3 Issued for Stakeholder Consultation: 2012-09-06 Severe The responsible entity did not use any one of the following criteria (Requirement R1 criterion 1 through 13) for any specific circuit terminal to prevent its phase protective relay settings from limiting transmission system loadability while maintaining reliable protection of the Bulk Electric System for all fault conditions. OR The responsible entity did not evaluate relay loadability at 0.85 per unit voltage and a power factor angle of 30 degrees. The responsible entity failed to ensure that its out-of-step blocking elements allowed tripping of phase protective relays for faults that occur during the loading conditions used to verify transmission line relay loadability per Requirement R1. The responsible entity that uses a circuit capability with the practical limitations described in Requirement R1 criterion 6, 7, 8, 9, 12, or 13 did not use the calculated circuit capability as the Facility Rating of the circuit. 25 N/A N/A N/A N/A N/A N/A N/A The Planning Coordinator used the criteria established within Attachment B to determine the circuits in its Planning Coordinator area for which applicable entities must comply with the standard and met parts 6.1 and 6.2, but more than 15 months and less than 24 months lapsed between assessments. The Planning Coordinator used the criteria established within Attachment B to determine the circuits in its Planning Coordinator area for which applicable entities must comply with the standard and met parts 6.1 and 6.2, but 24 months or more lapsed between assessments. OR R4 R5 R6 Issued for Stakeholder Consultation: 2012-09-06 OR The responsible entity did not obtain the agreement of the Planning Coordinator, Transmission Operator, and Reliability Coordinator with the calculated circuit capability. The responsible entity did not provide its Planning Coordinator, Transmission Operator, and Reliability Coordinator with an updated list of circuits that have transmission line relays set according to the criteria established in Requirement R1 criterion 2 at least once each calendar year, with no more than 15 months between reports. The responsible entity did not provide its Regional Entity, with an updated list of circuits that have transmission line relays set according to the criteria established in Requirement R1 criterion 12 at least once each calendar year, with no more than 15 months between reports. The Planning Coordinator failed to use the criteria established within Attachment B to determine the circuits in its Planning Coordinator area for which applicable entities must comply with the standard. OR The Planning Coordinator used the criteria established within Attachment B, at least once each 26 OR The Planning Coordinator used the criteria established within Attachment B at least once each calendar year, with no more than 15 months between assessments to determine the circuits in its Planning Coordinator area for which applicable entities must comply with the standard and met 6.1 and 6.2 but provided the list of circuits to the Reliability Coordinators, Transmission Owners, Generator Owners, and Distribution Providers within its Planning Coordinator area between 31 days and 45 days after the list was established or updated. (part 6.2) OR The Planning Coordinator used the criteria established within Attachment B at least once each calendar year, with no more than 15 months between assessments to determine the circuits in its Planning Coordinator area for which applicable entities must comply with the standard and met 6.1 and 6.2 but provided the list of circuits to the Reliability Coordinators, Transmission Owners, Generator Owners, and Distribution Providers within its Planning Coordinator area between 31 days and 45 days Issued for Stakeholder Consultation: 2012-09-06 The Planning Coordinator used the criteria established within Attachment B at least once each calendar year, with no more than 15 months between assessments to determine the circuits in its Planning Coordinator area for which applicable entities must comply with the standard and met 6.1 and 6.2 but provided the list of circuits to the Reliability Coordinators, Transmission Owners, Generator Owners, and Distribution Providers within its Planning Coordinator area between 46 days and 60 days after list was established or updated. (part 6.2) calendar year, with no more than 15 months between assessments to determine the circuits in its Planning Coordinator area for which applicable entities must comply with the standard but failed to meet parts 6.1 and 6.2. OR The Planning Coordinator used the criteria established within Attachment B at least once each calendar year, with no more than 15 months between assessments to determine the circuits in its Planning Coordinator area for which applicable entities must comply with the standard but failed to maintain the list of circuits determined according to the process described in Requirement R6. (part 6.1) OR The Planning Coordinator used the criteria established within Attachment B at least once each calendar year, with no more than 15 months between assessments to determine the circuits in its Planning Coordinator area for which applicable entities must comply with the standard and met 6.1 but failed to provide the list of circuits to the Reliability Coordinators, Transmission Owners, Generator Owners, and Distribution Providers within its Planning Coordinator area or provided the list more than 60 27 after the list was established or updated. (part 6.2) Issued for Stakeholder Consultation: 2012-09-06 days after the list was established or updated. (part 6.2) OR The Planning Coordinator failed to determine the circuits in its Planning Coordinator area for which applicable entities must comply with the standard. 28 Attachment A/Appendix 1- Associated Switch Yard with Load-Responsive Phase Protection Systems NERC PRC-023-2 1. This standard includes any protective functions which could trip with or without time delay, on load current, including but not limited to: 1.1 Phase distance. 1.2. Out-of-step tripping. 1.3. Switch-on-to-fault. 1.4. Overcurrent relays. 1.5. Communications aided protection schemes including but not limited to: 1.5.1 Permissive overreach transfer trip (POTT). 1.5.2 Permissive under-reach transfer trip (PUTT). 1.5.3 Directional comparison blocking (DCB). 1.5.4 Directional comparison unblocking (DCUB). 1.6. Phase overcurrent supervisory elements (i.e., phase fault detectors) associated with current-based, communicationassisted schemes (i.e., pilot wire, phase comparison, and line current differential) where the scheme is capable of tripping for loss of communications. 2. The following protection systems are excluded from requirements of this standard: 2.1. Relay elements that are only PRC-023-AB-02 Reason for Differences Stakeholder Comments (Insert comments here) AESO Replies 1. This reliability standard includes any protective functions which could trip with or without time delay, on load current, including: (a) phase distance; (b) out-of-step tripping; (c) switch-on-to-fault; (d) overcurrent relays; (e) communications aided protection schemes including: (i) permissive overreach transfer trip; (ii) permissive under-reach transfer trip; (iii) directional comparison blocking; and (iv) directional comparison unblocking; and (f) phase overcurrent supervisory elements (i.e. phase fault detectors) associated with current-based, communicationassisted schemes (i.e. pilot wire, phase comparison, and line current differential) where the scheme is capable of tripping for loss of communications. 2. The following protection systems Issued for Stakeholder Consultation: 2012-09-06 29 NERC PRC-023-2 enabled when other relays or associated systems fail. For example: • Overcurrent elements that are only enabled during loss of potential conditions. • Elements that are only enabled during a loss of communications except as noted in section 1.6 2.2. Protection systems intended for the detection of ground fault conditions. 2.3. Protection systems intended for protection during stable power swings. 2.4. Generator protection relays that are susceptible to load. 2.5. Relay elements used only for Special Protection Systems applied and approved in accordance with NERC Reliability Standards PRC-012 through PRC-017 or their successors. 2.6. Protection systems that are designed only to respond in time periods which allow 15 minutes or greater to respond to overload conditions. 2.7. Thermal emulation relays which are used in conjunction with dynamic Facility Ratings. 2.8. Relay elements associated PRC-023-AB-02 Reason for Differences Stakeholder Comments (Insert comments here) AESO Replies are excluded from the requirements of this reliability standard: (a) relay elements that are only enabled when other relays or associated systems fail, including: (i) overcurrent elements that are only enabled during loss of potential conditions; and (ii) elements that are only enabled during a loss of communications except as noted in subsection 1(f) above; (b) protection systems intended for the detection of ground fault conditions; (c) protection systems intended for protection during stable power swings; (d) generator protection relays that are susceptible to load; (e) relay elements used only for remedial action scheme purposes; (f) protection systems that are designed only to respond in time periods which allow fifteen (15) minutes or greater to respond to overload conditions; (g) thermal emulation relays which are used in conjunction with dynamic facility ratings; and (h) relay elements associated with Issued for Stakeholder Consultation: 2012-09-06 30 NERC PRC-023-2 with dc lines. PRC-023-AB-02 Reason for Differences Stakeholder Comments (Insert comments here) AESO Replies direct current lines. Issued for Stakeholder Consultation: 2012-09-06 31 Attachment B/Appendix 2 - Criteria for Establishing List of Circuits NERC PRC-023-2 Circuits to Evaluate PRC-023-AB-02 Reason for Differences Stakeholder Comments (Insert comments here) AESO Replies Circuits to Evaluate • Transmission lines operated at 100 The ISO must evaluate the following circuits: kV to 200 kV and transformers with low voltage terminals connected at (a) transmission lines operated at 100 kV to 200 kV. one hundred (100) kV to two • Transmission lines operated below hundred (200) kV and 100 kV and transformers with low transformers with low voltage terminals connected at one voltage terminals connected below hundred (100) kV to two 100 kV that are part of the BES. hundred (200) kV; and Criteria If any of the following criteria apply to a circuit, the applicable entity must comply with the standard for that circuit. B1. The circuit is a monitored Facility of a permanent flowgate in the Eastern Interconnection, a major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the Québec Interconnection, that has been included to address reliability concerns for loading of that circuit, as confirmed by the applicable Planning Coordinator. B2. The circuit is a monitored Facility of an IROL, where the IROL was determined in the planning horizon pursuant to (b) transmission lines operated below one hundred (100) kV and transformers with low voltage terminals connected below one hundred (100) kV that are essential to the reliability of the bulk electric system. Criteria If any of the following criteria apply to a circuit, the ISO must identify the circuit as required in requirement R6. 1 A major transfer path within the Western Interconnection as defined by the Regional Entity. 2 The circuit is a monitored facility of an interconnection reliability operating limit, where the interconnection reliability operating limit was determined in the planning horizon pursuant to Issued for Stakeholder Consultation: 2012-09-06 32 NERC PRC-023-2 FAC-010. B3. The circuit forms a path (as agreed to by the Generator Operator and the transmission entity) to supply off-site power to a nuclear plant as established in the Nuclear Plant Interface Requirements (NPIRs) pursuant to NUC-001. B4. The circuit is identified through the following sequence of power flow analyses6 a. Simulate double contingency combinations selected by engineering judgment, without manual system adjustments in between the two contingencies (reflects a situation where a System Operator may not have time between the two contingencies to make appropriate system adjustments). performed by the Planning Coordinator for the one-to-five-year planning horizon: b. For circuits operated between 100 kV and 200 kV evaluate the post-contingency loading, in consultation with the Facility owner, against a PRC-023-AB-02 Reason for Differences Stakeholder Comments (Insert comments here) AESO Replies reliability standard FAC-010-AB2.1, System Operation Limits Methodology for the Planning Horizon. 3 The circuit is identified through the following sequence of power flow analyses: (a) simulate double contingency combinations selected by engineering judgment, without manual system adjustments in between the two (2) contingencies (reflects a situation where a system operator may not have time between the two (2) contingencies to make appropriate system adjustments), performed by the ISO for the one-to-fiveyear planning horizon; (b) for circuits operated between one hundred (100) kV and two hundred (200) kV, evaluate the postcontingency loading, in consultation with the legal owner, against a threshold based on the facility rating assigned for that circuit and used in the power flow case by the ISO; 6 Past analyses may be used to support the assessment if no material changes to the system have occurred since the last assessment Issued for Stakeholder Consultation: 2012-09-06 33 NERC PRC-023-2 threshold based on the Facility Rating assigned for that circuit and used in the power flow case by the Planning Coordinator. c. When more than one Facility Rating for that circuit is available in the power flow case, the threshold for selection will be based on the Facility Rating for the loading duration nearest four hours. d. The threshold for selection of the circuit will vary based on the loading duration assumed in the development of the Facility Rating. i. If the Facility Rating is based on a loading duration of up to and including four hours, the circuit must comply with the standard if the loading exceeds 115% of the Facility Rating. ii. If the Facility Rating is based on a loading duration greater than four and up to and including eight hours, the circuit must comply with the standard if the loading exceeds 120% of the Facility Rating. iii. If the Facility Rating is based on a loading duration Issued for Stakeholder Consultation: 2012-09-06 PRC-023-AB-02 Reason for Differences Stakeholder Comments (Insert comments here) AESO Replies (c) when more than one (1) facility rating for that circuit is available in the power flow case, the ISO must base the threshold for selection on the facility rating for the loading duration nearest four (4) hours; (d) the threshold for selection of the circuit will vary based on the loading duration assumed in the development of the facility rating: (i) if the facility rating is based on a loading duration of up to and including four hours, the circuit must comply with the standard if the loading exceeds one hundred and fifteen percent (115%) of the facility rating; (ii) if the facility rating is based on a loading duration greater than four and up to and including eight hours, the circuit must comply with the standard if the loading exceeds one hundred and twenty percent (120%) of the facility rating; or 34 NERC PRC-023-2 of greater than eight hours, the circuit must comply with the standard if the loading exceeds 130% of the Facility Rating. e. Radially operated circuits serving only load are excluded. B5. The circuit is selected by the Planning Coordinator based on technical studies or assessments, other than those specified in criteria B1 through B4, in consultation with the Facility owner. B6. The circuit is mutually agreed upon for inclusion by the Planning Coordinator and the Facility owner. PRC-023-AB-02 Reason for Differences Stakeholder Comments (Insert comments here) AESO Replies (iii) if the facility rating is based on a loading duration of greater than eight (8) hours, the circuit must comply with the standard if the loading exceeds one hundred and thirty percent (130%) of the facility rating; and (e) radially operated circuits serving only load are excluded. 4 The ISO must select the circuit based on technical studies or assessments, other than those specified in criteria 1 through 4, in consultation with the legal owner. 5 The ISO and the legal owner must mutually agree upon the circuit for inclusion. Issued for Stakeholder Consultation: 2012-09-06 35