IESO_PRO_0728 PUBLIC Market Manual 7: System Operations Part 7.12: Available Transfer Capability Implementation Document Issue 3.0 This document explains how the TTC and the ATC are calculated at the IESO. Public Disclaimer The posting of documents on this Web site is done for the convenience of market participants and other interested visitors to the IESO Web site. Please be advised that, while the IESO attempts to have all posted documents conform to the original, changes can result from the original, including changes resulting from the programs used to format the documents for posting on the Web site as well as from the programs used by the viewer to download and read the documents. The IESO makes no representation or warranty, express or implied, that the documents on this Web site are exact reproductions of the original documents listed. In addition, the documents and information posted on this Web site are subject to change. 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Document ID IESO_PRO_0728 Document Name Part 7.12: Available Transfer Capability Implementation Document Issue Issue 3.0 Reason for Issue Incorporated into Market Manual 7.0 for Baseline 27.1 Effective Date June 6, 2012 Part 7.12: Available Transfer Capability Implementation Document Document Change History Document Change History Issue Reason for Issue Date 1.0 First release February 10, 2011 2.0 Changes to Sections 5, 6 and 7 February 22, 2012 3.0 Issue released for Baseline 27.1 June 6, 2012 Related Documents Document ID Document Title IESO_PRO_0729 Market Manual 7.11: Transmission Reliability Margin Implementation Document IMP_POL_0002 Market Manual 7.4: IESO Controlled Grid Operating Policies Issue 3.0 – June 6, 2012 Public Part 7.12: Available Transfer Capability Implementation Document Table of Contents Table of Contents Table of Contents ...................................................................................................... i List of Tables ............................................................................................................ ii Table of Changes .................................................................................................... iii 1. Introduction.................................................................................................... 1 1.1 1.2 Reliability Standards Addressed in this Procedure ..................................................... 1 Acronyms Used in this Procedure ............................................................................... 1 2. Total Transfer Capability .............................................................................. 3 2.1 2.2 Computing Total Transfer Capability ........................................................................... 3 2.1.1 Base Case ....................................................................................................... 3 2.1.2 Pre-contingency Criteria .................................................................................. 4 2.1.3 Post-contingency Criteria ................................................................................ 4 2.1.4 Contingencies .................................................................................................. 4 2.1.5 Outages ........................................................................................................... 4 2.1.6 Counterflows and Expected Interchange......................................................... 4 Publishing Total Transfer Capability ........................................................................... 5 3. Available Transfer Capability ....................................................................... 6 3.1 3.2 Computing Available Transfer Capability .................................................................... 6 Publishing Available Transfer Capability ..................................................................... 6 4. Background Information ............................................................................... 7 4.1 4.2 Transmission Service in Ontario ................................................................................. 7 ATCID NERC Definitions ............................................................................................ 7 References ................................................................................................................ 1 Issue 3.0 – June 6, 2012 Public i List of Tables IESO_PRO_0728 List of Tables Table 1-1: NERC Standards Applicable to Available Transfer Capability ............................... 1 Table 1-2: List of Acronyms .................................................................................................... 1 Table 4-1: ATCID NERC Definitions ....................................................................................... 7 ii Public Issue 3.0 – June 6, 2012 Part 7.12: Available Transfer Capability Implementation Document Table of Changes Table of Changes Reference (Section and Paragraph) Entire Document Description of Change Incorporated into Market Manual 7.0: System Operations as Part 7.12. Issue 3.0 – June 6, 2012 Public iii Part 7.12: Available Transfer Capability Implementation Document 1. 1. Introduction Introduction The IESO is responsible for reliably operating the Ontario Bulk Electric System. We facilitate the wholesale energy market and schedule imports and exports across each of Ontario’s external interfaces, which include ties to New York, Michigan, Quebec, Minnesota, and Manitoba. The Available Transfer Capability Implementation Document (ATCID) was created in compliance with NERC standard MOD-001-1a: R3. The ATCID describes the methodology used by the IESO to compute the Total Transfer Capability (TTC) and Available Transfer Capability (ATC) for Ontario’s external interfaces, as part of the IESO’s responsibilities as a Transmission Service Provider (TSP) and a Transmission Operator (TOP) in the province of Ontario. 1.1 Reliability Standards Addressed in this Procedure In compliance with NERC standard MOD-001-1a: R1 which requires all TOPs to select a methodology for calculating ATC, the IESO has chosen to adopt the standard MOD-029-1a: Rated System Methodology. . Table 1-1: NERC Standards Applicable to Available Transfer Capability Standard ID Title MOD-001-1a Available Transmission System Capability MOD-029-1a Rated System Path Methodology 1.2 Acronyms Used in this Procedure Table 1-2: List of Acronyms Acronym Definition ATC Available Transfer Capability ATCID Available Transfer Capability Implementation Document CBM Capacity Benefit Margin DSO Dispatch Scheduling and Optimization ERAG Eastern Interconnection Reliability Assessment Group ETC Existing Transmission Commitment LSE Load-Serving Entity MMWG Multi-regional Modeling Working Group NERC North American Electric Reliability Corporation Issue 3.0 – June 6, 2012 Public 1 1. Introduction IESO_PRO_0728 Acronym Definition SAA System Adequacy Assessment SS-37 System Studies-37 SSR System Status Report TOP Transmission Operator TRM Transmission Reliability Margin TSP Transmission Service Provider TTC Total Transfer Capability – End of Section – 2 Public Issue 3.0 – June 6, 2012 Part 7.12: Available Transfer Capability Implementation Document 2. Total Transfer Capability 2. Total Transfer Capability Total Transfer Capability (TTC) is the amount of electric power that can be transferred over an interconnection in a reliable manner while meeting all of specific set of defined pre and post contingency system condition. This transfer capability depends on generation dispatch, system load level, load distribution in the network, power transfer between areas, and the limits imposed on the transmission system due to thermal, voltage, and stability consideration. These limits are determined for one or both directions of flow, as necessary. 2.1 Computing Total Transfer Capability NERC Standard MOD-029-1a: Rated System Path Methodology, R1, R2, R3, R4 Generally, the transmission interface limits are computed to satisfy pre- and post-contingency criteria considerations, such as: • Steady state damping stability and damping factor, • Line and equipment loading must not exceed their ratings, • Relay margins are within defined bounds, • Voltage declines must not exceed certain limits, • Generators must remain in synchronism, AND • Voltages are stable (V-Q sensitivity is positive). Details are provided in “IMP_POL_0002 Market Manual 7.4: IESO-Controlled Grid Operating Policies”, Appendix B.3.2.” In order to compute a TTC, one often makes a number of assumptions, such as target years, seasons, load type, statuses of generation, and available transmission facilities as stated in Internal Manual 7.4 Section 5.2.2. The assumptions used in determining a TTC are consistent with those applied when computing system operating limits. The assumptions used in computing the TTCs are no more limiting than the assumptions used for planning studies. 2.1.1 Base Case On an annual basis, the System Studies-37 (SS-37) group develops a library of solved load flow cases and associated dynamic data and submits them to the Multi-regional Modeling Working Group (MMWG) under the Eastern Interconnection Reliability Assessment Group (ERAG). MMWG is responsible for developing and maintaining the library of power flow and dynamic cases. Regional Coordinators (i.e., NPCC) are responsible for submitting the initial changes to each case of these cases. The MMWG base cases are an amalgamation of inputs from each of the areas within the Reliability Coordinators footprint. The IESO base cases include external system models and data from the MMWG case. The base case generation dispatch for external areas is based on the MMWG case. The phase shifters are modeled as per what would be expected for the time frame being studied. There setting and status may be adjusted depending on the specific requirements of the study. Issue 3.0 – June 6, 2012 Public 3 2. Total Transfer Capability IESO_PRO_0728 The master base cases include all connection assessment projects that are approved, including those that did not require a formal connection assessment study. Local area details are added as appropriate. Information regarding base cases can be found on the IESO's Forecasts webpage. 2.1.2 Pre-contingency Criteria In deriving the total transfer capabilities, the IESO-controlled grid must meet the pre-contingency criteria listed in “IMP_POL_0002 Market Manual 7.4: IESO-Controlled Grid Operating Policies”, Appendix B, section B.3.1. 2.1.3 Post-contingency Criteria In deriving the total transfer capabilities, the IESO-controlled grid must meet the post-contingency criteria listed in “IMP_POL_0002 Market Manual 7.4: IESO-Controlled Grid Operating Policies”, Appendix B, section B.3.2. 2.1.4 Contingencies The total transfer capabilities shall be calculated based on the contingencies listed in “IMP_POL_0002 Market Manual 7.4: IESO-Controlled Grid Operating Policies”, Appendix B, section B.2. 2.1.5 Outages The following criteria are applied when considering the impact of outages: • For daily TTC computations, outages more than 15 minutes are included in the TTC. • For monthly TTC computations, outages more than 7 days are included in the TTC. • For annual TTC computations, outages more than 30 days are included in the TTC. For external outages, the TTC may be determined from coordinated studies with neighbouring jurisdictions and/or operating study reports that state the revised interface limitation. Information on outages that could impact Ontario’s external interfaces is exchanged with neighbouring Transmission Owners and/or Reliability Coordinators. Reciprocal agreements are in place whereby Ontario’s neighbours also provide the IESO with any outage information that would affect the TTC on tie lines. The IESO has Operating Agreements with all neighbouring TOPs and TSPs (i.e., New York ISO, TransÉnergie, Midwest ISO, ITC, Manitoba Hydro, and Minnesota Power). For the purposes of outage co-ordination, the IESO exchanges critical outage information with NYISO, MISO, and TransÉnergie. 2.1.6 Counterflows and Expected Interchange A portion of scheduled flows to Michigan appear on the New York ties and vice versa. The TTC is published without taking this coupling into account. The TTC for each of the paths (with flows in both directions) is the capability of the interface based on voltage, stability, and thermal requirements. The New York / Michigan coupling is factored into the scheduling limit when the Dispatch Scheduling and Optimization (DSO) tool determines the amount of coincident flows on both interfaces. Due to the dynamic nature of loop flows, their 4 Public Issue 3.0 – June 6, 2012 Part 7.12: Available Transfer Capability Implementation Document 2. Total Transfer Capability corresponding values are only considered in real time operations and do not affect the ATC or TTC limits that are published. The need to couple the Michigan and New York TTCs will expire when all Michigan ties have operating phase shifters. The net interchange schedule is the sum of all imports (positive) and exports (negative). The IESO limits the net change from hour-to-hour to 700 MW, unless respecting this limit would negatively impact reliability. Import and export schedules are adjusted accordingly during real time operations to ensure that this limit is not violated. 2.2 Publishing Total Transfer Capability The base quantity for each TTC is published in the Ontario Transmission System document. This value refers to the TTC with all elements in service. – End of Section – Issue 3.0 – June 6, 2012 Public 5 3. Available Transfer Capability IESO_PRO_0728 3. Available Transfer Capability 3.1 Computing Available Transfer Capability NERC Standard MOD-029-1a: Rated System Path Methodology, R7, R8 Requirements R7 and R8 of MOD-029-1a necessitate that the ATC should be calculated as follows: ATC = TTC – ETC – CBM – TRM + Postbacks + counterflows F F F F ATC = TTC – ETC – ETC – CBM – TRM + Postbacks + counterflows NF F NF S U NF F The IESO does not have provisions for the purchase and sale of firm and non-firm transmission services. Hence in the context of MOD-029-1a, the IESO does not draw any distinctions between firm and non-firm ATC. In Ontario, the values for ETCF, ETCNF ,CBM, PostbacksF, PostbacksNF and counterflowsF are set to zero. Therefore, in the context of the Ontario market the ATC = TTC – TRM. The TRM values applied to the interties for the monthly and annual ATC can be found in “IESO_PRO_0729 Market Manual 7.11: Transmission Reliability Margin Implementation Document”. There is no process to allocate transfer or flowgate capability among multiple lines as the IESO is the only Transmission Service Provider for Ontario. 3.2 Publishing Available Transfer Capability The IESO uses its DSO tool to produce its advisory dispatches for the day-ahead period (first published at 11:00 for the following day) up to one hour in advance of real-time. The pre-dispatch scheduling limits used for the DSO are posted as the short-term ATC. This report can be accessed at: http://reports.ieso.ca/public/PredispIntertieSchedLimits/PUB_PredispIntertieSchedLimits.xml The short-term ATC is published in the System Status Report (SSR), the Daily System Adequacy Assessments (SAA) and the Weekly SAA report. The SSR covers days 0-2 while the Daily SAA Report details days 3-14. They are published once a day or at any time when there is a material change to the system. The monthly and annual ATCs are published as part of the Transmission Rights auction process; the monthly ATCs in the next two months are covered through the Short Term Auction, and the annual ATCs for the whole year are covered in the Long Term Auction. – End of Section – 6 Public Issue 3.0 – June 6, 2012 Part 7.12: Available Transfer Capability Implementation Document 4. Background Information 4. Background Information 4.1 Transmission Service in Ontario Ontario’s market design does not allow for the purchase and/or sale of any firm or non-firm transmission services. There is no system of advance reservations, physical rights and point to point service. In order for an import/export to be scheduled, it must compete on economics with internal generation that is dispatched in an economic security constrained manner. If a transaction is successfully scheduled, the IESO will provide that market participant with access to the transmission system provided that there is availability on the transmission path to accommodate the transfer. The Ontario market does not have provisions for point to point service. However the market framework in Ontario allows fair, open and non-discriminatory access to Transmission service subject to the imports/exports being competitive in the energy market. 4.2 ATCID NERC Definitions Table 4-1: ATCID NERC Definitions Term NERC Definition ATC “A measure of the transfer capability remaining in the physical transmission network for further commercial activity over and above already committed uses.” Equation: ATC = TTC - TRM - CBM - ETC CBM “The amount of firm transmission transfer capability preserved by the transmission provider for Load-Serving Entities (LSEs), whose loads are located on that Transmission Service Provider’s system, to enable access by the LSEs to generation from interconnected systems to meet generation reliability requirements.” TRM “The amount of transmission transfer capability necessary to provide reasonable assurance that the interconnected transmission network will be secure. TRM accounts for the inherent uncertainty in system conditions and the need for operating flexibility to ensure reliable system operation as system conditions change.” When calculating a TRM value, the following factors should be considered to account for uncertainties in system conditions: • Aggregate load forecast error • Load distribution error • Variations in facility loading • Uncertainties in system topology • Simultaneous transfers and parallel path flow • Variations in generation dispatch • Calculation inaccuracies • Short-term operator response factor • Short-term vs. long-term timeframes Issue 3.0 – June 6, 2012 Public 7 4. Background Information Term TTC IESO_PRO_0728 NERC Definition “The amount of electric power that can be moved or transferred reliably from one area to another area of the interconnected transmission systems by way of all transmission lines (or paths) between those areas under specified system conditions. ” – End of Section – 8 Public Issue 3.0 – June 6, 2012 Part 7.12: Available Transfer Capability Implementation Document References References Document Name Ontario Transmission System Document ID IESO_REP_0265v20.0 http://www.ieso.ca/imoweb/pubs/marketReports/OntTxSystem _2011nov.pdf Daily System Advisory/Summary Report (SSR) http://reports.ieso.ca/public/SSR/PUB_SSR.htm Weekly Security and Adequacy Assessment Report (SAA) http://reports.ieso.ca/public/SAAWeekly/PUB_SAAWeekly.ht m Market Manual 7: System Operations Part 7.4: IESO Controlled IMP_POL_0002 Grid Operating Policies http://ieso.ca/imoweb/pubs/systemOps/so_GridOpPolicies.pdf Market Manual 7: System Operations Part 7.2: Near-Term Assessments and Reports IMP_PRO_0033 http://www.ieso.ca/imoweb/pubs/systemOps/so_NearTermAsse ssReport.pdf NERC Standard MOD-001-1a: Available Transmission System Capability http://www.nerc.com/files/MOD-001-1a.pdf NERC Standard MOD-029-1a: Rated System Path Methodology http://www.nerc.com/files/MOD-029-1a.pdf NERC Glossary of Terms http://www.nerc.com/files/Glossary_of_Terms.pdf Short Term Transmission Right Auction http://reports.ieso.ca/public/TRAPreauctionMCPST/ Long Term Transmission Right Auction http://reports.ieso.ca/public/TRAPreauctionMCPLT/ – End of Document – Issue 3.0 – June 6, 2012 References–1