SCHEDULE B HQCME Registration Information and applicable standards for Énergie La Lièvre S.E.C. (“Lièvre”) and Energy Brookfield Marketing Inc. (“EBMI”) Standards Included Title BAL‐005‐0b Automatic Generation Control Applic
able to Lièvre as: GOP‐2 Requirements Brief description “Bulk”, “Non Bulk” or NA (not applicable) in the context of the proposed Two (2) tier approach process R1.1. Each Generator Operator with generation facilities operating in an Interconnection 1 shall ensure that those generation facilities are included within the metered boundaries of a Balancing Authority Area2. Making sure all generation is included within the metered boundaries of a Balancing Authority area. That is metered by HQCME as BA. Bulk: Lièvre’s generation resources are essentially used for commercial interchange transactions external to Québec. These resources are excluded from HQCMÉ‘s resource adequacy analysis for Québec load and are not part of the supply. Thus, HQCMÉ as the BA must consider for its own load when it coordinates the operational plans of Balancing Authorities in its area, only the net energy injection required for HQCMÉ security analysis and its area control error (ACE) calculations with its neighbours. Requirement ought to apply, as per existing installations, to the interconnections with HQT and Hydro One (HO) only per existing agreements for monitoring and billing net energy exchanges from Lièvre’s Installation. NA for each GO unit/plant. Responsibility for ensuring common Tie Line MW (intertie) metering that is used between neighbouring BAs lies with HQCMÉ as the BA (BAL‐005 R12). Requires that neighbouring TOs have an agreement for provision of such metering, but not at the GO level. CIP‐001‐1 Sabotage GOP2 R1. Each.... Generator Operator ...shall have Each responsible entity must have Bulk: See NERC Glossary of terms; Interconnection means; when capitalized, any one of the three major electric system networks in North America: Eastern, Western, and ERCOT (Authors note: now includes Québec). 2 See NERC Glossary of terms; Balancing Authority Area means; the collection of generation, transmission, and loads within the metered boundaries of the Balancing Authority. The Balancing Authority maintains load‐resource balance within this area. 1
‐ 1 ‐ Reporting procedures for the recognition of and for making their operating personnel aware of sabotage events on its facilities and multi‐site sabotage affecting larger portions of the Interconnection. R2. Each.... Generator Operator ...shall have procedures for the communication of information concerning sabotage events to appropriate parties in the Interconnection. a documented sabotage reporting procedures and communication protocols in place for communicating such events to the appropriate internal staff, other entities and authorities. For D5A intertie transmission facilities designated “Bulk” by HQCMÉ & IESO when exporting to Ontario segregated3 from the HQT network and H9A being an intertie with another jurisdiction. Non Bulk: For all other facilities. R3. Each..... Generator Operator ...shall provide its operating personnel with sabotage response guidelines, including personnel to contact, for reporting disturbances due to sabotage events. R4. Each ..., Generator Operator..., shall establish communications contacts, as applicable, with local Federal Bureau of Investigation (FBI) or Royal Canadian Mounted Police (RCMP) officials and develop reporting procedures as appropriate to their circumstances. COM‐002‐2 EOP‐002‐2 Communication and Coordination Capacity and GOP‐2 R1. Each ..., Generator Operator..., shall have communications (voice and data links) with appropriate Reliability Coordinators, Balancing Authorities, and Transmission Operators. Such communications shall be staffed and available for addressing a real‐time emergency condition. Having the capability and staff to communicate with HQCME and HQT for emergency situations. Existing processes, procedures and communication facilities in place with HQT and HQCMÉ for its interconnection with HQT. Communication requirements for the interties, under the NERC standards, lie with the RC. R9. When a Transmission Service Provider R9: identifies the obligations of the Energy expects to elevate the transmission service LSE and RC if and when the TSP Emergencies priority of an Interchange Transaction from elevates transmission service Priority 6 (Network Integration Transmission priority from 6 to 7 per other Service from Non‐designated Resources) to standards NA Non Bulk: NA: Though listed as applicable by HQCMÉ for TSP‐2. The standard only applies to the BA, RC and LSEs. Priority 7 (Network Integration Transmission There are no reliability obligations for TSP’s Service from designated Network Resources) as under this standard. permitted in its transmission tariff (See Attachment 1‐IRO‐006‐0 “Transmission Loading When exporting to Ontario, Lièvre’s installation must operate connected radial to the Ontario network segregated, (electrically isolated) from the HQT network; Segregated Mode of Operation (SMO) refers to an Ontario market rule term that refers to Ontario generators (or loads) connected radial to Québec system and electrically isolated from the Ontario Network (IESO‐controlled grid (ICG)). 3
‐ 2 ‐ Relief Procedure” for explanation of Transmission Service Priorities) EOP‐004‐1 Disturbance Reporting GOP‐2 R2.Each ..., Generator Operator... shall promptly analyze Bulk Electric System disturbances on its system or facilities. R3. Each ..., Generator Operator....experiencing a reportable incident shall provide a preliminary written report to its Regional Reliability Organization and NERC. (Per Requirement R3.1, R3.2 and R.3.3). Analysis and report disturbance affecting the responsible entity’s facilities or impacted by the local area network. Bulk; for D5A intertie facilities designated “Bulk” by HQCMÉ & IESO when exporting to Ontario and H9A being an intertie with another jurisdiction. Non Bulk; For all other facilities Lièvre has existing procedure with HQT to appropriately assess incidents to enable HQT and HQCMÉ to meet its disturbance reporting obligation to NERC and NPCC. Incident investigation /follow‐ups are best coordinated by one entity, the RC. R3.4. If, in the judgment of the Regional Reliability Organization, after consultation with the Reliability Coordinator, Balancing Authority, Transmission Operator, Generator Operator, or Load Serving Entity in which a disturbance occurred, a final report is required, the affected Reliability Coordinator, Balancing Authority, Transmission Operator, Generator Operator, or Load Serving Entity shall prepare this report within 60 days. As a minimum, the final report shall have a discussion of the events and its cause, the conclusions reached, and recommendations to prevent recurrence of this type of event. The report shall be subject to Regional Reliability Organization approval. FAC‐001‐0 Facility Connection Requirements TO‐3 R1. The Transmission Owner shall document, maintain, and publish facility connection requirements to ensure compliance with NERC Reliability Standards and applicable Regional Reliability Organization, subregional, Power Pool, and individual Transmission Owner planning criteria and facility connection requirements. The Transmission Owner’s facility connection requirements shall address connection requirements for: i) generation, ii) transmission and iii) end‐user facilities All reporting (verbal and written) for Lièvre should remain as is to HQCME per existing protocols, not directly to NPCC and NERC. Note: This standard is typically for transmission owners like HQT, Hydro One, etc. It is not normally for generator owners that have their own transmission “distribution” assets as well for interconnecting their own facilities and legacy local loads. NA: Lièvre’s Installations are designed for its own use and are not intended for use by other HQ load customers or generators. Therefore a connection requirement document is not required nor warranted. R2. The Transmission Owner’s facility connection requirements shall address, but are ‐ 3 ‐ not limited to, the following items: (all listed sub items). R3. The Transmission Owner shall maintain and update its facility connection requirements as required. The Transmission Owner shall make documentation of these requirements available to the users of the transmission system, the Regional Reliability Organization, and NERC on request (five business days). FAC‐002 ‐0 Coordination of TO3, Plans For New GO‐3 Generation, Transmission, and End‐User R1 The Generator Owner, Transmission Owner, Distribution Provider, and Load‐Serving Entity seeking to integrate generation facilities, transmission facilities, and electricity end‐user facilities shall each coordinate and cooperate on its assessments with its Transmission Planner and Planning Authority. The assessment shall include: (R1.1 to R1.5) Coordinating new connections, or facilities with TP and PC These specific facilities will fall under the proposed QCMEP for new/modified connections that are deemed Bulk or affect interties and will require Lièvre to follow HQT’s and IESOʹs Connection Assessment and Approval 4 processes. R2: The ....Transmission Owner ....shall each retain its documentation (of its evaluation of the reliability impact of the new facilities and their connections on the interconnected transmission systems) for three years and shall provide the documentation to the Regional Reliability Organization(s) Regional Reliability Organization(s) and NERC on request (within 30 calendar days). FAC‐003‐1 Transmission Vegetation Management Program TO‐3 R1. The Transmission Owner shall prepare, and keep current, a formal transmission vegetation management program (TVMP). The TVMP shall include the Transmission Owner’s objectives, practices, approved procedures, and work specifications1. Bulk; for D5A intertie facilities designated Bulk by HQCMÉ and IESO when exporting to Ontario and H9A being an intertie with another jurisdiction. Non Bulk; for all other facilities that potentially affect the local area, Lièvre will be required to follow HQT connection and approval processes. Responsibility for coordinating between neighbouring jurisdictions under the NERC standards lies with HQT as the Planning Coordinator (PC). Maintaining vegetation under and along transmission right‐of‐way (ROW) for transmission lines 200 kV and above and those, the RRO (RC in Québec’s case) deems critical. Bulk; for D5A intertie facilities designated Bulk by HQCMÉ and IESO when exporting to Ontario and H9A being an intertie with another jurisdiction. Non Bulk; for all other transmission lines. Application of the requirement for Non Bulk lines 200 kV and above to be based on what HQT proposes for its own Non Bulk transmission lines for consistency in R1.1 to R1.5 R2. The Transmission Owner shall create and implement an annual plan for vegetation IESO market manual 2.10 – Connection Assessment and Approval Procedure 4
‐ 4 ‐ application; management work to ensure the reliability of the system. The plan shall describe the methods used, such as manual clearing, mechanical clearing, herbicide treatment, or other actions. The plan should be flexible enough to adjust to changing conditions, taking into consideration anticipated growth of vegetation and all other environmental factors that may have an impact on the reliability of the transmission systems. Adjustments to the plan shall be documented as they occur. The plan should take into consideration the time required to obtain permissions or permits from landowners or regulatory authorities. Each Transmission Owner shall have systems and procedures for documenting and tracking the planned vegetation management work and ensuring that the vegetation management work was completed according to work specifications. R3. The Transmission Owner shall report quarterly to its RRO, or the RRO’s designee, sustained transmission line outages determined by the Transmission Owner to have been caused by vegetation. (Per: R3.1 to R3.4) FAC‐008‐1 Facility Ratings Methodology TO‐3, GO‐3 R1. The Transmission Owner and Generator Owner shall each document its current methodology used for developing Facility Ratings (Facility Ratings Methodology) of its solely and jointly owned Facilities. The methodology shall include all of the following: R1.1 to R1.3.5 R2. The Transmission Owner and Generator Owner shall each make its Facility Ratings Methodology available for inspection and technical review by those Reliability Coordinators, Transmission Operators, Transmission Planners, and Planning Authorities that have responsibility for the area in which the associated Facilities are located, within 15 ‐ 5 ‐ Facility owners are responsible for documents relating to methodologies used in developing facility and equipment ratings. The facility ratings methodology used could include nameplate ratings, engineering analysis, IEEE standards, standards developed following accredited procedures of the Canadian Standards Association (CSA) etc. Bulk; for D5A intertie facilities designated Bulk by HQCMÉ and IESO when exporting to Ontario and H9A being an intertie with another jurisdiction. Non‐Bulk for all other facilities The primary focus of these reliability obligations should be the transmission facilities interconnecting with HQT, and in the case of the interties, those that connect with Hydro One (HO) required for modeling purposes. The capabilities of the individual generation units/stations and associated interconnecting facility ratings have commercial implications business days of receipt of a request. only rather than reliability (security) needs of either HQT or HQCMÉ and are unwarranted. R3. If a Reliability Coordinator, Transmission Operator, Transmission Planner, or Planning Authority provides written comments on its technical review of a Transmission Owner’s or Generator Owner’s Facility Ratings Methodology, the Transmission Owner or Generator Owner shall provide a written response to that commenting entity within 45 calendar days of receipt of those comments. The response shall indicate whether a change will be made to the Facility Ratings Methodology and, if no change will be made to that Facility Ratings Methodology, the reason why. FAC‐009‐1 Establish and Communicate Facility Ratings TO‐3, GO‐3 R1. The Transmission Owner and Generator Owner shall each establish Facility Ratings for its solely and jointly owned Facilities that are consistent with the associated Facility Ratings Methodology. R2. The Transmission Owner and Generator Owner shall each provide Facility Ratings for its solely and jointly owned Facilities that are existing Facilities, new Facilities, modifications to existing Facilities and re‐ratings of existing Facilities to its associated Reliability Coordinator(s), Planning Authority(ies), Transmission Planner(s), and Transmission Operator(s) as scheduled by such requesting entities. Requires establishment and communication of the facility ratings or changes to ratings established in accordance with the methodologies established under FAC‐008, to its TSP, TP, PC and RC Bulk; for D5A intertie facilities designated Bulk by HQCMÉ and IESO when exporting to Ontario and H9A being an intertie with another jurisdiction. Non‐Bulk for all other facilities While, HQT in its capacity as the TOP, PC and the TP require Lièvre’s facility rating information for its interconnection with HQT for purposes of its (HQCMÉ’ and HQT’s) models to meet the transmission planning standards and for calculating SOLs, this is a local area impact issue for the HQT interconnection and should remain a local area reliability related issue. Responsibility to establish and communicate intertie total transfer capability (TTC) and SOLs/IROLs under the NERC standards lie with the RC in real time and the PC in the planning time horizon. Corresponding facility rating information is required from the facility owners. INT‐001‐3 Interchange Information PSE R1. The Load‐Serving Entity and Purchasing‐
Selling Entity shall insure that Arranged Interchange is submitted to the Interchange Authority. ‐ 6 ‐ Ensure e‐Tags are submitted for all Intertie transactions or point to point transaction PSEs enter into. Our comments are subject to the question of the application of the standard reliability rules to PSE. Bulk: R1.1. All Dynamic Schedules at the expected average MW profile for each hour. Interchange transaction standards are related to transaction tagging (e‐tagging) requirements and apply for all intertie connections between BA’s areas and point to point transactions. This equally applies (or should) to HQP’s point to point transactions within Québec over other Québec TSP installations. NA for Dynamic schedules since not employed. INT‐004‐2 Dynamic Interchange Transaction Modifications PSE R2. The Purchasing‐Selling Entity responsible for tagging a Dynamic Interchange Schedule shall ensure the tag is updated for the next available scheduling hour and future hours when any one of the following occurs: R2.1. The average energy profile in an hour is greater than 250 MW and in that hour the actual hourly integrated energy deviates from the hourly average energy profile indicated on the tag by more than +10%. Deals with Dynamic transactions on the inter‐ties that some PSE entities enter into with generation or load in another jurisdiction. Transactions into Ontario and other NPCC member interfaces are set on an hourly basis and Dynamic transactions are not available. Response to Interchange Authority TSP‐2 R1. Prior to the expiration of the reliability assessment period defined in the timing requirements tables in this standard, Column B, the Balancing Authority and Transmission Service Provider shall respond to each On‐time Request for Interchange (RFI), and to each Emergency RFI and Reliability Adjustment RFI from an Interchange Authority to transition an Arranged Interchange to a Confirmed Interchange. R1.2. Each involved Transmission Service Provider shall confirm that the transmission service arrangements associated with the Arranged Interchange have adjacent Transmission Service Provider connectivity, are valid and prevailing transmission system limits ‐ 7 ‐ Bulk, but NA: Dynamic transaction tagging is not employed by the NPCC area (RC) members. This also is the case for Lièvre’s Installation when connected radial to Ontario, or when operating in segregated mode of Operation (SMO) (see footnote 3). R2.2. The average energy profile in an hour is less than or equal to 250 MW and in that hour the actual hourly integrated energy deviates from the hourly average energy profile indicated on the tag by more than +25 megawatt‐hours. INT‐006‐3 See our earlier comment for PSE. Explicit for the TSP to follow this standards interchange transaction approval time lines and approval process for e‐tags. Bulk: Interchange transaction standards are related to transaction tagging (e‐tagging) requirements and apply for all intertie connections between BA’s areas and point to point transactions. EBMI would be the PSE (subject to the comments made above) and Lièvre the TSP for transactions to Ontario and the only entity able to transact on these interties. Therefore it places an obligation on itself to approve transmission service for its own interchange transactions. For the IESO‐administered markets (IAM), transactions that clear the market have will not be violated “equivalent” to Firm transmission service available in a physical market. For transaction elsewhere, such as New York Lièvre requires to ensure transmission service is available on each leg (Transmission path) of the arranged transaction. Note: version 3 is currently in effect IRO‐001‐1 Reliability Coordination — Responsibilities and Authorities GOP‐2 TSP‐2, PSE R8. The Generator Operators and Transmission Service Providers shall comply with Reliability Coordinator directives unless such actions would violate safety, equipment, or regulatory or statutory requirements. Under these circumstances, the Transmission Operator, Balancing Authority, Generator Operator, Transmission Service Provider, Load‐Serving Entity, or Purchasing‐Selling Entity shall immediately inform the Reliability Coordinator of the inability to perform the directive so that the Reliability Coordinator may implement alternate remedial actions. The standard establishes the accountabilities and authorities of the RC. Non Bulk; for all Lièvre’s facilities with the exception of the requirement to follow the RC directives related to interchange ( e‐tagged) R8: Requires the listed responsible entities to take action as directed by the RC (HQCMÉ) for “real‐time “day to day operations. transactions on the interties Lièvre transacts on. For Lièvre’s Installation, with exception of the interties D5A and H9A and interchange transactions entered into elsewhere, these actions are typically with respect to maintaining system operating limits (SOL) at the interconnection with HQT, which is a local area implication. to alleviate actual or potential IROL violations, Bulk; for all 3 entity types, related to the responding appropriately to the RC directives which in this case is with respect to the interties. For the interconnections with HQT, following the directive of the RC is related to SOL limits, which is a local area reliability related issue only. In the case on the interties, it is with respect to IROLs IRO‐004‐2 Reliability Coordination — Operations Planning TSP‐2, R1. Each Transmission Operator, Balancing Authority, and Transmission Service Provider shall comply with the directives of its Reliability Coordinator based on the next day assessments in the same manner in which it would comply during real time operating events. R1; TSP5 Must follow the direction of the RC for security (SOL and IROL) assessment the RC has made for next day operations, similar to those required to follow for real time (IRO‐005).. Typically this is with respect to Bulk; for D5A intertie facilities designated Bulk by HQCMÉ and IESO when exporting to Ontario and H9A being an intertie with another jurisdiction. Non‐Bulk for all other facilities; and limited to the interconnection transfer capability with HQT (SOL limits and net energy flows); which See NERC Glossary of Terms; TSP means; the entity that administers the transmission tariff and provides Transmission Service to Transmission Customers under applicable transmission service agreements. Transmission Service means; services provided to the Transmission Customer by the Transmission Service Provider to move energy from a Point of Receipt to a Point of Delivery. 5
‐ 8 ‐ interconnections, between other area of the Interconnections6 jurisdictions e.g. Québec ‐ New York and the transfer capabilities of those tie lines, for next day operations, unless point to point transmission service is also used.. For Lièvre’ adequacy does not come to play in Québec’s market model. However, interchange transactions do and these requirements are related to the INT standards and related actions required for e‐tags. is the limit of HQCME’s purview as the RC for Lièvre’s Installation. In the case of Lièvre’s Installation, Lièvre is the only entity that can transact on the interties with Ontario and HQCMÉ, as the RC leaves the role of managing this interface with the IESO directly coordinating with Lièvre, rather than RC to RC. Note: version 2 of the standard is in effect now rather than the version 1 HQCMÉ listed and is now only applicable to BAs, TOP’s and TSPs to follow the direction of RC. This latest version eliminates duplications of requirements that exist in other standards. The standard places an obligation on the responsible entities (the TSP for Lièvre) to follow the direction of the RC, for “day ahead” SOL limits (local area limits) and in the case of exporting to Ontario or importing to Québec on the interties, for IROL’s, related to physical transmission service it has provided for interchange transactions (e‐tags). For a TSP this is the same as Requirement R8 in IRO‐001 but for next day’s operations. IRO‐005‐2 Reliability Coordination — Current Day Operations TSP‐2, GOP‐2, PSE R13. Each Reliability Coordinator shall ensure that all Transmission Operators, Balancing Authorities, Generator Operators, Transmission Service Providers, Load‐Serving Entities, and Purchasing‐Selling Entities operate to prevent the likelihood that a disturbance, action, or non‐
action in its Reliability Coordinator Area will result in a SOL or IROL violation in another area With the exception of R14, which requires the TSP to take action, these are obligations for the RC. It must coordinate actions to ensure that GOPs and the TSP (and others as required) are aware of, and that the RC take actions to mitigate potential and actual SOL Bulk; for D5A intertie facilities designated Bulk by HQCMÉ and IESO when exporting to Ontario and H9A being an intertie with another jurisdiction. With respect to the interties, these requirements relate to taking “real time” action as directed by the RC and ensuring the limits used for an See NERC Glossary of terms; Interconnection means: When capitalized, any one of the three major electric system networks in North America: Eastern, Western, and ERCOT (also includes Québec now). 6
‐ 9 ‐ of the Interconnection. In instances where there is a difference in derived limits, the Reliability Coordinator and its Transmission Operators, Balancing Authorities, Generator Operators, Transmission Service Providers, Load‐Serving Entities, and Purchasing‐Selling Entities shall always operate the Bulk Electric System to the most limiting parameter. R14. Each Reliability Coordinator shall make known to Transmission Service Providers within its Reliability Coordinator Area, SOLs or IROLs within its wide‐area view. The Transmission Service Providers shall respect these SOLs or IROLs in accordance with filed tariffs and regional Total Transfer Calculation and Available Transfer Calculation processes R17. When an IROL or SOL is exceeded, the Reliability Coordinator shall evaluate the local and wide‐area impacts, both real‐time and post‐
contingency, and determine if the actions being taken are appropriate and sufficient to return the system to within IROL in thirty minutes. If the actions being taken are not appropriate or sufficient, the Reliability Coordinator shall direct the Transmission Operator, Balancing Authority, Generator Operator, or Load‐Serving Entity to return the system to within IROL or SOL. or. IROL, in another area of the Interconnection (jurisdiction). Typically this is with respect to interconnections between jurisdictions e.g. Ontario/Québec and the transfer capabilities of those tie lines for real time operations unless point to point transmission service is also used. R13 require all entities to use the most limiting parameter if there is disagreement on limit values. intertie is the most limiting, based on current configuration of the networks. Non‐Bulk for all other facilities and limited to the interconnection with HQT for local area SOL limits and net energy injections; which is the limit of HQCMÉ’s purview as the RC for Lièvre’s Installation with respect to managing facilities within their ratings. Responsibility to manage Lièvre’s other facilities, within their respective facility ratings lies within Lièvre’s purview. The Measures of the standard with Note: version 2 of the standard is in effect and the exception of M14 and to some should be applicable rather than version 1 degree M13, all relate to the RC’s HQCMÉ listed. obligations to show it did what was required. The requirement of entities to follow the RC directives is covered elsewhere (see IRO‐001, IRO‐004 and TOP‐001). MOD‐006‐0 Procedures for the Use of Capacity Benefit Margin Values TSP‐2 R1. Each Transmission Service Provider shall document its procedure on the use of Capacity Benefit Margin (CBM) (scheduling of energy against a CBM reservation). The procedure shall include the following three components: R1.1 to R1.3 R2. Each Transmission Service Provider shall make its CBM use procedure available on a web site accessible by the Regional Reliability Requires the TSP to document its procedure for making use of the firm transmission service capability it has specifically set aside (reserved) as CBM through commercial agreements, for a specific LSE load within the TSP’s jurisdiction to enable that LSE to access generation it has available in another jurisdiction. To be only used by the LSE in times of ‐ 10 ‐ Bulk, but NA: The applicability of these standards relate to the calculation and posting on OASIS of total transfer capability (TTC) and available transfer capability (ATC) that is used for the purposes of selling transmission service over an entities (Lièvre’s) transmission system for point to point and interchange transactions. Specifically with respect to Lièvre’ procedure for making use of CBM that it has sold, as a TSP, sold or reserved Organizations, NERC, and transmission users emergency generation deficiency of the LSE’s own generation resources. for an LSE. Lièvre does not employ CBM (that is CBM is equal to 0) on its intertie with Ontario, since it is the sole entity that can transact on those interties. The same can be said with respect to its interconnection with HQT. We are unable to understand how these standards relate to Lièvre’s Installation and its interconnection with HQT. . MOD‐007‐0 Documentation of the Use of Capacity Benefit Margin TSP‐2 R1. Each Transmission Service Provider that uses CBM shall report (to the Regional Reliability Organization, NERC and the transmission users) the use of CBM by the Load‐Serving Entities’ Loads on its system, except for CBM sales as Non‐Firm Transmission Service. (This use of CBM shall be consistent with the Transmission Service Provider’s procedure for use of CBM.) Requires the TSP to report and post when and how CBM was used by a LSE. Bulk, but NA: see explanation in MOD‐006 above R2. The Transmission Service Provider shall post the following three items within 15 calendar days after the use of CBM for an Energy Emergency. This posting shall be on a web site accessible by the Regional Reliability Organizations, NERC, and transmission users. R2.1. Circumstances. R2.2. Duration. R2.3. Amount of CBM used. MOD‐010‐0 Steady‐State Data for Transmission System Modeling and Simulation TO‐3, GO‐3 R1. The Transmission Owners and Generator Owners, (specified in the data requirements and reporting procedures of MOD‐011‐0_R1) shall provide appropriate equipment characteristics, system data, and existing and future Interchange Schedules in compliance with its respective Interconnection Regional steady‐state modeling and simulation data requirements and reporting procedures as defined in Reliability Standard This standard requires submissions of steady data for its facilities to the NERC and the RE (NPCC) typically via the RC. ‐ 11 ‐ Bulk; for D5A intertie facilities designated Bulk by HQCMÉ and IESO when exporting to Ontario and H9A being an intertie with another jurisdiction. Non Bulk otherwise Required for HQT, HO and IESO models respectively and will depend on model granularity requirements of HQT, HO and IESO and HQCMÉ for the NERC TPL‐001 to TPL‐004 standards. MOD‐011‐0_R 1. R2. The Transmission Owners and Generator Owners (specified in the data requirements and reporting procedures of MOD‐011‐0_R1) shall provide this steady‐state modeling and simulation data to the Regional Reliability Organizations, NERC, and those entities specified within Reliability Standard MOD‐011‐
0_R 1. If no schedule exists, then these entities shall provide the data on request (30 calendar days). The extent to which modeling data is required by HQCMÉ as RCs and HQT’s as PC and TP or IESO7 as RC, PC and TP to maintain its models current need to be established jointly and the standard applicability applied accordingly. Processes are currently in place that has met HQCMÉ`s and HQT’s requirements to‐date. Those deemed for “Bulk” needs and those for the interties will be managed accordingly under the future QCMEP. MOD‐012‐0 Dynamics Data for Modeling and Simulation of the Interconnected Transmission System TO‐3, GO‐3 R1. The Transmission Owners, Transmission Planners, Generator Owners, and Resource Planners (specified in the data requirements and reporting procedures of MOD‐013‐0_R1) shall provide appropriate equipment characteristics and system data in compliance with the respective Interconnection‐wide Regional dynamics system modeling and simulation data requirements and reporting procedures as defined in Reliability Standard MOD‐013‐0_R1. This standard requires submissions of Dynamic data for its facilities to the NERC and the RE (NPCC) typically via the RC. Non Bulk otherwise The extent to which modeling data is required by HQT and HQCMÉ to maintain its models and those of the IESO and HO current need to be established jointly and the standard applicability applied accordingly. R2. The Transmission Owners, Transmission Planners, Generator Owners, and Resource Planners (specified in the data requirements and reporting procedures of MOD‐013‐0_R4) shall provide dynamics system modeling and simulation data to its Regional Reliability Organization(s), NERC, and those entities specified within the applicable reporting procedures identified in Reliability Standard MOD‐013‐0_R 1. If no schedule exists, then these entities shall provide data on request (30 calendar days). PRC‐001‐1 System Protection Coordination GOP‐2 R1. Each Transmission Operator, Balancing Authority, and Generator Operator shall be Bulk; for D5A intertie facilities designated Bulk by HQCMÉ and IESO when exporting to Ontario and H9A being an intertie with another jurisdiction. Processes are currently in place that has met HQCMÉ’s and HQT`s requirements to‐date. Those deemed for “Bulk” will be managed accordingly under the future QCMEP. Each facility owner is required to be familiar with its facility Bulk; for D5A intertie facilities designated Bulk by HQCMÉ and IESO when exporting to The obligation to provide the IESO with sufficient model information for the interties lies with HQCMÉ as the RC. 7
‐ 12 ‐ familiar with the purpose and limitations of protection system schemes applied in its area. R2. Each Generator Operator and Transmission Operator shall notify reliability entities of relay or equipment failures as follows: R2.1. If a protective relay or equipment failure reduces system reliability, the Generator Operator shall notify its Transmission Operator and Host Balancing Authority. The Generator Operator shall take corrective action as soon as possible. R3. A Generator Operator or Transmission Operator shall coordinate new protective systems and changes as follows. R3.1. Each Generator Operator shall coordinate all new protective systems and all protective system changes with its Transmission Operator and Host Balancing Authority. protection systems and the implications when such protection systems fail for notifying the RC. Further is required to coordinate applicable protection systems with its TOP. For Lièvre’s installations this should apply at the interconnections with HQT and the Ontario systems. Ontario and H9A being an intertie with another jurisdiction. Non‐Bulk; for all other facilities See detailed response in RFI question 5.5 In a broader sense, Lièvre needs to ensure coordination internally with respect to its generation, loads and transmission elements for its own system reliability. R5. A Generator Operator or Transmission Operator shall coordinate changes in generation, transmission, load or operating conditions that could require changes in the protection systems of others: (Includes sub‐Requirement 5.1) PRC‐004‐1 Analysis and Mitigation of Transmission and Generation Protection System Mis‐operations TO‐3, GO‐3 R1. The Transmission Owner and any Distribution Provider that owns a transmission Protection System shall each analyze its transmission Protection System Misoperations and shall develop and implement a Corrective Action Plan to avoid future Misoperations of a similar nature according to the Regional Reliability Organization’s procedures developed for Reliability Standard PRC‐003 Requirement 1. Investigation and reporting protection mis‐operations R2, The Generator Owner shall analyze its generator Protection System Misoperations, and shall develop and implement a Corrective Action Plan to avoid future Misoperations of a similar nature according to the Regional Reliability Organization’s procedures developed for PRC‐
‐ 13 ‐ Bulk; for D5A intertie facilities designated Bulk by HQCMÉ and IESO when exporting to Ontario and H9A being an intertie with another jurisdiction. Non‐Bulk for all other facilities Lièvre has its own internal processes for investigation of potential protection mis‐
operation and implement mitigating actions, as required, based on the findings to prevent re‐
occurrences. 003 R1. R3. The Transmission Owner, any Distribution Provider that owns a transmission Protection System, and the Generator Owner shall each provide to its Regional Reliability Organization, documentation of its Misoperations analyses and Corrective Action Plans according to the Regional Reliability Organization’s procedures developed for PRC‐003 R1. PRC‐018‐1 Disturbance Monitoring Equipment Installation and Data Reporting TO‐3, GO‐3 R1. Each Transmission Owner and Generator Owner required to install DMEs by its Regional Reliability Organization (reliability standard PRC‐002 Requirements 1‐3) shall have DMEs installed that meet the following requirements: R1.1. Internal Clocks in DME devices shall be synchronized to within 2 milliseconds or less of Universal Coordinated Time scale (UTC) R1.2. Recorded data from each Disturbance shall be retrievable for ten calendar days. R2. The Transmission Owner and Generator Owner shall each install DMEs in accordance with its Regional Reliability Organization’s installation requirements (reliability standard PRC‐002 Requirements 1 through 3). R3. The Transmission Owner and Generator Owner shall each maintain, and report to its Regional Reliability Organization on request, the following data on the DMEs installed to meet that region’s installation requirements (reliability standard PRC‐002 Requirements1.1, 2.1 and 3.1): Owners required to install DMEs by its Regional Reliability Organization (reliability standard PRC‐002 Requirements 1‐3) shall have DMEs installed that meet specific requirements: These need to be or should be at the interconnection with HQT and Ontario and could be an obligation on either party. Entities may wish to have their own DME installations for their own purposes, which can be used during incident investigation, though not required to meet the specific requirements of this standard. R4. The Transmission Owner and Generator NA; with respect to its interconnection with HQT: It is our view these DME installations, if at all required by HQCMÉ, for “local area” incident reviews, need to be at the interconnections with HQT and installed and owned by HQT as the TO and TOP. Bulk; for D5A intertie facilities designated Bulk by HQCMÉ and IESO when exporting to Ontario and H9A being an intertie with another jurisdiction. However, a similar case can be made for the intertie facilities, with the required DME owned by HO. While, Lièvre have DME equipment in place for its own internal incident investigation, this requirement is subject to discussion with all parties and requirements established in the interconnection agreement between the RCs Owner shall each provide Disturbance data (recorded by DMEs) in accordance with its Regional Reliability Organization’s requirements (reliability standard PRC‐002 Requirement 4). R5. The Transmission Owner and Generator ‐ 14 ‐ Owner shall each archive all data recorded by DMEs for Regional Reliability Organization‐
identified events for at least three years. R6. Each Transmission Owner and Generator Owner that is required by its Regional Reliability Organization to have DMEs shall have a maintenance and testing program for those DMEs that includes: R6.1 and R6.2 TOP‐001‐1 Reliability Responsibilities and Authorities GOP‐2 R3. Each TOP, BA, and Generator Operator shall comply with reliability directives issued by the Reliability Coordinator, and each Balancing Authority and Generator Operator shall comply with reliability directives issued by the Transmission Operator, unless such actions would violate safety, equipment, regulatory or statutory requirements. Under these circumstances the Transmission Operator, Balancing Authority or Generator Operator shall immediately inform the Reliability Coordinator or Transmission Operator of the inability to perform the directive so that the Reliability Coordinator or Transmission Operator can implement alternate remedial actions. R3. Follow the “directives” of the RC and the TOP. R6. Help out to extent possible in an emergency R7. Requirement for GOPs to not remove BES equipment from service if it will impact the BES; A GOP is to notify the TOP if and when doing so. R6. Each TOP, BA, and Generator Operator shall render all available emergency assistance to others as requested, provided that the requesting entity has implemented its comparable emergency procedures, unless such actions would violate safety, equipment, or regulatory or statutory requirements. Bulk; for D5A intertie facilities designated Bulk by HQCMÉ and IESO when exporting to Ontario and H9A being an intertie with another jurisdiction and with respect to the provision of emergency energy in accordance with existing interconnection agreements Non‐Bulk; for all other facilities. With respect to R7; Removal from service of other Lièvre facilities should be limited to those that impact “net energy “exchanges with HQ above a set threshold and not on a unit basis, and those transmission elements that impact SOL’s and contingency limit planning. The specific facilities being established and documented through the existing agreements. These again impact local area operations only. (see worst case contingency, in RFI response to Q 5.7) R7. Each TOP and Generator Operator shall not remove Bulk Electric System facilities from service if removing those facilities would burden neighboring systems unless: R7.1. For a generator outage, the Generator Operator shall notify and coordinate with the Transmission Operator. The Transmission Operator shall notify the Reliability Coordinator and other affected Transmission Operators, and coordinate the impact of removing the Bulk ‐ 15 ‐ Electric System facility R7.3. When time does not permit such notifications and coordination, or when immediate action is required to prevent a hazard to the public, lengthy customer service interruption, or damage to facilities, the Generator Operator shall notify the Transmission Operator, and the Transmission Operator shall notify its Reliability Coordinator and adjacent Transmission Operators, at the earliest possible time. TOP‐002‐2 Normal Operations Planning TSP‐2, GOP‐2 R3. Each Generator Operator shall coordinate (where confidentiality agreements allow) its current‐day, next‐day, and seasonal operations with its Host Balancing Authority and Transmission Service Provider. Each Balancing Authority and Transmission Service Provider shall coordinate its current‐day, next‐day, and seasonal operations with its Transmission Operator. Coordinating generation operation with its BA and TSP through day ahead planning. R12. The Transmission Service Provider shall include known SOLs or IROLs within its area and neighboring areas in the determination of transfer capabilities, in accordance with filed tariffs and/or regional Total Transfer Capability and Available Transfer Capability calculation processes. R13. At the request of the Balancing Authority or Transmission Operator, a Generator Operator shall perform generating real and reactive capability verification that shall include, among other variables, weather, ambient air and water conditions, and fuel quality and quantity, and provide the results to the Balancing Authority or Transmission Operator operating personnel as requested. Bulk; for D5A intertie facilities designated Bulk by HQCMÉ and IESO when exporting to Ontario and H9A being an intertie with another jurisdiction. For coordination and forecasting these requirements are limited to those facilities, defined within the Interconnection Agreements that impact the security of the interties or affect the operating limits of those tie‐lines and those required for interchange transactions between jurisdictions. with respect to R12; Bulk for the interties, when exporting to Ontario and or importing into Québec; to respect the intertie limits at all times, taking into account the the network configuration, though interties are always operated radial and TTC8 based on intertie ratings. with respect to R3, R13, R14 and R15; The need for generator, coordination, capability verifications and forecasting should be limited to those generators under the direct control of the RC and explicitly available to the BA to manage its load/generation balance, for the “area” within its purview. This is not the case TTC ‐ total transfer capability of the intertie. 8
‐ 16 ‐ R14. Generator Operators shall, without any intentional time delay, notify their Balancing Authority and Transmission Operator of changes in capabilities and characteristics including but not limited to: in Québec’s market model. With respect to exports to Ontario, the commercial interchange transaction Lièvre enters into and required to deliver is based on net energy capability available at the time, and not based on generator verification requirements. Changes or limitations to these deliveries are managed accordingly per the interchange standards, through required changes to the e‐tag. R14.1. Changes in real output capabilities. (Effective August 1, 2007) R15. Generation Operators shall, at the request of the Balancing Authority or Transmission Operator, provide a forecast of expected real power output to assist in operations planning (e.g., a seven‐day forecast of real output). Non‐Bulk; for all other facilities with respect to the GOP when interconnected to the HQT network only. Local area implications only. R.18. Neighboring Balancing Authorities, Transmission Operators, Generator Operators, Transmission Service Providers, and Load‐
Serving Entities shall use uniform line identifiers when referring to transmission facilities of an interconnected network. TOP‐003‐1 Planned Outage Coordination GOP‐2 R1. Generator Operators and Transmission Operators shall provide planned outage information. R1. Plan outages that impact the BES. R1.1. Each Generator Operator shall provide outage information daily to its Transmission Operator for scheduled generator outages planned for the next day (any foreseen outage of a generator greater than 50 MW). The Transmission Operator shall establish the outage reporting requirements. R1.3. Such information shall be available by 1200 Central Standard Time for the Eastern Interconnection and 1200 Pacific Standard Time for the Western Interconnection. R.1.1; Notify TOP if NET generation output deviates more than 50 MV from planned production. R2. Plan with and notify TOP if AVR or stabiliser equipments are to be removed from service. R3. Plan with and notify TOP if telemetering or control equipment that affects the BES is to be removed from service. R2. Each TOP, BA, and Generator Operator shall plan and coordinate scheduled outages of system voltage regulating equipment, such as automatic voltage regulators on generators, supplementary excitation control, synchronous condensers, shunt and series capacitors, reactors, etc., among ‐ 17 ‐ Non Bulk: R1: ought to only be applicable from a Net Energy delivery perspective and related to interchange transactions (see INT standards and comments TOP‐002), which is covered by other standards as “Bulk”; and Transmission Line outages from generating plants, for example from High Falls, may need to be identified for local area security analysis, if required by HQT. R2; Non‐Bulk; for the individual generation unit AVR outage coordination perspective; provided sufficient net reactive power (VAR) capability on automatic voltage regulation in voltage control mode for the Installation is available at all times. Bulk, only if in service status of Stabilizers affect IROLs; if SOLs only then non‐Bulk; affected Balancing Authorities and Transmission Operators as required. subject to discussions with HQCMÉ. R3: Non Bulk; would continue to apply for local R3. Each TOP, BA, and Generator Operator shall plan and coordinate scheduled outages of telemetering and control equipment and associated communication channels between the affected areas. area per current practices for outage reporting. Outages affecting intertie facilities related to D5A that are deemed Bulk” and those associated with H9A would be required to be identified to the IESO when making transactions arranging for export to Ontario. Responsibility per the standards for provision of this outage information lies with the TOP and RC. From an IESO planning perspective, Lièvre’s generator outages have no impact on these export transactions since these are commercial transactions based on Lièvre’s available generation capability, taking into account known/planned outages. TOP‐005‐1 Operational Reliability Information PSE R4. Each Purchasing‐Selling Entity shall provide information as requested by its Host Balancing Authorities and Transmission Operators to enable them to conduct operational reliability assessments and coordinate reliable operations. For a PSE this requirement essentially relates to information pertaining to interchange transaction tagging information which, is done through e‐tagging. In Lièvre’s case this would be related to when planning to operated in SMO and when segregated to the Ontario system and with respect to interchange transactions it has entered into with Ontario or elsewhere. TOP‐006 Monitoring System Conditions GOP‐2 R1.1. Each Generator Operator shall inform its Host Balancing Authority and the Transmission Operator of all generation resources available for use. Should only be a need to provide a forecast of net energy available to the BA for its adequacy analysis if so used by the BA for its area load. In the case of generation explicitly used for interchange transactions to other jurisdiction, the ‐ 18 ‐ Subject to the application of standard reliability standard to PSE Bulk; for exchange of e‐tagging interchange transaction information.(energy schedules) With respect to e‐tagging information, this is (may) be a forecast of when planning to operate in SMO and when operating segregated from HQT and identification of planned interchange transactions to other jurisdictions, such as those to New York. In the case of the interties with Ontario, outage requests must be submitted to the IESO and HQCMÉ as RC’s for such operations under TOP‐003 and is therefore covered. Non‐Bulk The need to inform the host BA (HQCMÉ) and TOP (HQT) of generator availability should be limited to those generators under the direct control of the RC and TOP and/or explicitly requirement is limited to the tagging requirements covered by the interchange standards (INT). available to the BA to manage its load/generation balance, for the “area” within its purview (Québec Load), if so used for that purpose and local area security analysis. In the case of Lièvre’s Installation this requirements should be limited to within the context of provision of “net” generation availability at its interconnections with HQT with respect to interchange transactions (e‐tags) it has entered into. VAR‐001‐
1a Voltage and Reactive Control PSE R5. Each Purchasing‐Selling Entity shall arrange for (self‐provide or purchase) reactive resources to satisfy its reactive requirements identified by its Transmission Service Provider. Each PSE is required to acquire Subject to the application of standard reliability appropriate reactive support for all standard to PSE. interchange transactions, as Bulk; for D5A intertie facilities designated Bulk required by the TSP. by HQCMÉ and IESO when exporting to Ontario and H9A being an intertie with another Interties are normally managed at jurisdiction. unity power factor with 0 VAR transfers between jurisdictions. NA elsewhere EBMI as the PSE is responsible for making arrangements with Lièvre as is the GOP to meet the requirements of Lièvre as the TSP and TO to ensure sufficient reactive support is available to maintain voltages on the interties for its interchange transactions. In short obligations are on itself. All transactions on the subject interties are managed in radial mode with required reactive support to maintain voltages provided by Lièvre. VAR‐002‐
1a Generator Operation for Maintaining Network Voltage Schedules GOP‐2, GO‐3 R1: The Generator Operator shall operate each generator connected to the interconnected transmission system in the automatic voltage control mode (automatic voltage regulator in service and controlling voltage) unless the Generator Operator has notified the Transmission Operator. R2: Unless exempted by the Transmission Operator, each Generator Operator shall maintain the generator voltage or Reactive GOP must operate each generator connected to the interconnected transmission system in the automatic voltage control mode (automatic voltage regulator in service and controlling voltage) unless the Generator Operator has notified the Transmission Operator otherwise. Non Bulk: In the absences of commercial arrangements to do otherwise, this ought to be from the ability to assure the availability of sufficient reactive power (VAR) to meet Lièvre’s own requirements; and assure HQT’s interconnection voltage limits, within the objective of maintaining unity power factor, in accordance with existing agreements with HQT ‐ 19 ‐ Power output (within applicable Facility Ratings9) as directed by the Transmission Operator.(Sub‐ Requirements R 2.1 and R2.2) though not within the standards prescribed AVR control mode10 on a unit by unit basis. With the exception of the interties, this is a local R3: Each Generator Operator shall notify its associated Transmission Operator as soon as practical, but within 30 minutes of any of the following (Sub‐ Requirements R 3.1 and R3.2) area reliability requirement only.. Bulk; In the case of the interties, with the objective of maintaining unity power factor at these interties, though still requiring to respect R4. The Generator Owner shall provide the following to its associated Transmission Operator and Transmission Planner within 30 calendar days of a request. (Sub‐ Requirements R 4.1) the voltage limits due to their redial mode of operations and limitations associated with the such facility configurations. With appropriate financial compensation available through the R5. After consultation with the Transmission Operator regarding necessary step‐up transformer tap changes, the Generator Owner shall ensure that transformer tap positions are changed according to the specifications provided by the Transmission Operator, unless such action would violate safety, an equipment rating, a regulatory requirement, or a statutory requirement.( Sub‐ Requirements R 5.1) IESO market rules. All Lièvre’s generation units are currently operated in automatic voltage control mode. A number of standards were excluded in HQCMÉ’s application; of those excluded PRC‐005 is required for local area reliability; PRC 015, PRC‐016 and PRC‐017 do not apply since there is no special protection scheme (SPS) in place; otherwise it would be required for local area reliability, unless designated as a class 1 SPS, in which case it then becomes a Bulk system requirement. Another standard that was not included by
HQCMÉ is the Cyber Security, which requires internal assessment by HQCMÉ.
PRC‐005 Transmission and GO‐3 Generation Protection System TO‐3 R1: System and each Generator Owner that Protection system maintenance owns a generation Protection System shall have programs in place Bulk; For the U/F relays installed on the three (3 ) a Protection System maintenance and testing When a Generator is operating in manual control, reactive power capability may change based on stability considerations and this will lead to a change in the associated Facility Ratings. 10 AVR means; Automatic Voltage Regulator, which can be typically placed in three modes of automatic operation; 1) Control voltage, 2) Power Factor control or 3) VAR control. Each mode provides reactive power support automatically, though control a different parameter 9
‐ 20 ‐ Maintenance and program for Protection Systems that affect the units at high Falls, the transmission facilities Testing reliability of the BES. The program shall include: deemed Bulk on D5A and those associated with R1.1. Maintenance and testing intervals and their intertie H9A being an intertie with another basis. jurisdiction up to Masson Breakers MB2 and R1.2. Summary of maintenance and testing MB3,. procedures. Non Bulk for all other facilities R2: Each Transmission Owner and any Distribution Provider that owns a transmission Protection System and each Generator Owner that owns a generation Protection System shall provide documentation of its Protection System maintenance and testing program and the implementation of that program to its Regional Reliability Organization on request (within 30 calendar days). The documentation of the program implementation shall include: R2.1. Evidence Protection System devices were maintained and tested within the defined intervals. R2.2. Date each Protection System device was last tested/maintained. ‐ 21 ‐