NYISO Tariffs --> Open Access Transmission Tariff (OATT) --> 35 OATT Attachment CC - Joint Operating Agreement Among And --> 35.2 OATT Att CC Abbreviations, Acronyms, Definitions and Ru
In this Agreement, the following words and terms shall have the meanings (such meanings to be equally applicable to both the singular and plural forms) ascribed to them in this Section 35.2. Any undefined, capitalized terms used in this Agreement shall have the meaning given under industry custom and, where applicable, in accordance with Good Utility Practices or the meaning given to those terms in the tariffs of PJM and NYISO on file at FERC.
Schedule C to this Agreement contains the Operating Protocol for the Implementation of Con Ed – PJM Transmission Service Agreements. Schedule C was accepted by FERC as a multi-party settlement to a long-running dispute. To the extent Schedule C contains definitions that differ from those set forth below (see, e.g., Appendix 8 to Schedule C), the definitions contained in Schedule C shall supersede the definitions set forth below, for purposes of interpreting Schedule C (including all of the appendices thereto), but shall not be used to interpret any other part of this Agreement.
“AC” shall mean alternating current.
“Affected Party” shall mean the electric system of the Party other than the Party to which a request for interconnection or long-term firm delivery service is made and that may be affected by the proposed service.
“Agreement” shall mean this document, as amended from time to time, including all attachments, appendices, and schedules.
“Area Control Error” or “ACE” shall mean the instantaneous difference between a Balancing Authority’s net actual and scheduled interchange, taking into account the effects of Frequency Bias and correction for meter error.
“Available Flowgate Capability” or “AFC” shall mean the rating of the applicable Flowgate less the projected loading across the applicable Flowgate less TRM and CBM. The firm AFC is calculated with only the appropriate Firm Transmission Service reservations (or interchange schedules) in the model, including recognition of all roll-over Transmission Service rights. Non-firm AFC is determined with appropriate firm and non-firm reservations (or interchange schedules) modeled.
“Available Transfer Capability” or “ATC” shall mean a measure of the transfer capability remaining in the physical transmission network for further commercial activity over and above already committed uses.
“Balancing Authority” or “BA” shall mean the responsible entity that integrates resource plans ahead of time, maintains load-interchange-generation balance within a Balancing Authority Area, and supports interconnection frequency in real-time.
“Balancing Authority Area” or “BAA” shall mean 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..
“Bulk Electric System” shall have the meaning provided for in the NERC Glossary of Terms used in Reliability Standards, as it may be amended, supplemented, or restated from time to time.
“Capacity Benefit Margin” or “CBM” shall mean 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. Preservation of CBM for an LSE allows that entity to reduce its installed generating capacity below that which may otherwise have been necessary without interconnections to meet its generation reliability requirements. The transmission transfer capability preserved as CBM is intended to be used by the LSE only in times of emergency generation deficiencies.
“CIM” shall mean Common Infrastructure Model.
“Confidential Information” shall have the meaning stated in Section 35.8.1.
“Control Area(s)” shall mean an electric power system or combination of electric power systems to which a common automatic generation control scheme is applied.
“Control Performance Standard” or “CPS” shall mean the reliability standard that sets the limits of a Balancing Authority’s Area Control Error over a specified time period.
“Coordinated Transaction Scheduling” or “CTS” shall mean the market rules that allow transactions to be scheduled based on a bidder’s willingness to purchase energy from a source in either the NYISO or PJM Control Area and sell it at a sink in the other Control Area if the forecasted price at the sink minus the forecasted price at the corresponding source is greater than or equal to the dollar value specified in the bid.
“Coordination Committee” shall mean the jointly constituted PJM and NYISO committee established to administer the terms and provisions of this Agreement pursuant to Section 35.3.2.
“Delivery Point” shall mean each of the points of direct Interconnection between PJM and the NYISO Balancing Authority Areas. Such Delivery Point(s) shall include the Interconnection Facilities between the PJM and the New York Balancing Authority Areas.
“DC” shall mean direct current.
“Disclosing Party” shall have the meaning stated in Section 35.8.7.
“Dispute” shall have the meaning stated in Section 35.15.
“Disturbance Control Standard” or “DCS” shall mean the reliability standard that sets the time limit following a disturbance within which a balancing authority must return its Area Control Error to within a specified range.
“Economic Dispatch” shall mean the sending of dispatch instructions to generation units to minimize the cost of reliably meeting load demands.
“Effective Date” shall have the meaning stated in Section 35.19.1.
“Emergency” shall mean any abnormal system condition that requires remedial action to prevent or limit loss of transmission or generation facilities that could adversely affect the reliability of the electricity system.
“Emergency Energy” shall mean energy supplied from Operating Reserve or electrical generation available for sale in New York or PJM or available from another Balancing Authority Area. Emergency Energy may be provided in cases of sudden and unforeseen outages of generating units, transmission lines or other equipment, or to meet other sudden and unforeseen circumstances such as forecast errors, or to provide sufficient Operating Reserve. Emergency Energy is provided pursuant to this Agreement and the Inter Control Area Transactions Agreement dated May 1, 2000 and priced according to Section 35.6.4 of this agreement and said Inter Control Area Transactions Agreement.
“EMS” shall mean the respective Energy Management Systems utilized by the Parties to manage the flow of energy within their Regions.
“External Capacity Resource” shall mean: (1) for NYISO, (a) an entity (e.g., Supplier, Transmission Customer) or facility (e.g., Generator, Interface) located outside the NYCA with the capability to generate or transmit electrical power, or the ability to control demand at the direction of the NYISO, measured in megawatts or (b) a set of Resources owned or controlled by an entity within a Control Area, not the NYCA, that also is the operator of such Control Area; and (2) for PJM, a generation resource located outside the metered boundaries of the PJM Region (as defined in the PJM Tariff) that meets the definition of Capacity Resource in the PJM Tariff or PJM’s governing agreements filed with the Commission.
“FERC” or “Commission” shall mean the Federal Energy Regulatory Commission or any successor agency thereto.
“Flowgate” shall mean a representative modeling of facilities or groups of facilities that may act as potential constraint points.
“Force Majeure” shall mean an event of force majeure as described in Section 35. 20.1.
“Generator to Load Distribution Factor” or “GLDF” shall mean a generator’s impact on a Flowgate while serving load in that generator’s Balancing Authority Area.
“Good Utility Practice” shall mean any of the practices, methods and acts engaged in or approved by a significant portion of the North American electric utility industry during the relevant time period, or any of the practices, methods and acts which, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result consistent with good business practices, reliability, safety and expedition. Good Utility Practice is not intended to be limited to the optimum practice, method, or act to the exclusion of all others, but rather to be acceptable practices, methods, or acts generally accepted by NERC.
“Governmental Authority” shall mean any federal, state, local or other governmental regulatory or administrative agency, court, commission, department, board, or other governmental subdivision, legislature, rulemaking board, tribunal, or other governmental authority having jurisdiction over the Parties, their respective facilities, or the respective services they provide, and exercising or entitled to exercise any administrative, executive, police, or taxing authority or power.
“ICCP”, “ISN” and “ICCP/ISN” shall mean those common communication protocols adopted to standardize information exchange.
“IDC” shall mean the NERC Interchange Distribution Calculator used for identifying and requesting congestion management relief.
“Indemnifying Party” shall have the meaning stated in Section 35.20.3.
“Indemnitee” shall have the meaning stated in Section 35.20.3
“Intellectual Property” shall mean (i) ideas, designs, concepts, techniques, inventions, discoveries, or improvements, regardless of patentability, but including without limitation patents, patent applications, mask works, trade secrets, and know-how; (ii) works of authorship, regardless of copyright ability, including copyrights and any moral rights recognized by law; and (iii) any other similar rights, in each case on a worldwide basis.
“Intentional Wrongdoing” shall mean an act or omission taken or omitted by a Party with knowledge or intent that injury or damage could reasonably be expected to result.
“Interconnected Reliability Operating Limit” or “IROL” shall mean the value (such as MW, MVAR, Amperes, Frequency, or Volts) derived from, or a subset of, the System Operating Limits, which if exceeded, could expose a widespread area of the bulk electrical system to instability, uncontrolled separation(s) or cascading outages.
“Interconnection” shall mean a connection between two or more individual Transmission Systems that normally operate in synchronism and have interconnecting intertie(s).
“Interconnection Facilities” shall mean the Interconnection facilities described in Schedule A.
“Intermediate Term Security Constrained Economic Dispatch” shall mean PJM’s algorithm that performs various functions, including but not limited to forecasting dispatch and LMP solutions based on current and projected system conditions for up to several hours into the future.
“ISO” shall mean Independent System Operator.
“kV” shall mean kilovolt of electric potential.
“LEC Adjusted Market Flow” shall mean the real-time Market Flow incorporating the observed operation of the PARs at the Michigan-Ontario border.
“Locational Marginal Price” or “LMP” shall mean the market clearing price for energy at a given location in a Party’s RC Area, and “Locational Marginal Pricing” shall mean the processes related to the determination of the LMP.
“Losses” shall have the meaning stated in Section 35.20.3.
“M2M” shall mean the market-to-market coordination process set forth in Schedule D to this Agreement.
“M2M Entitlement” shall mean a Non-Monitoring RTO’s share of a M2M Flowgate’s total capability to be used for settlement purposes that is calculated pursuant to Section 6 of Schedule D to this Agreement.
“M2M Event” shall mean the period when both Parties are operating under M2M as defined and set forth in Schedule D to this Agreement.
“M2M Flowgate” shall mean Flowgates where constraints are jointly monitored and coordinated as defined and set forth in Schedule D to this Agreement.
“Market Flows” shall mean the calculated energy flows on a specified Flowgate as a result of dispatch of generating resources serving load within an RTO’s market.
“Market Participant” shall mean an entity that, for its own account, produces, transmits, sells, and/or purchases for its own consumption or resale capacity, energy, energy derivatives and ancillary services in the wholesale power markets. Market Participants include transmission service customers, power exchanges, Transmission Owners, load serving entities, loads, holders of energy derivatives, generators and other power suppliers and their designated agents.
“Metered Quantity” shall mean apparent power, reactive power, active power, with associated time tagging and any other quantity that may be measured by a Party’s Metering Equipment and that is reasonably required by either Party for Security reasons or revenue requirements.
“Metering Equipment” shall mean the potential transformers, current transformers, meters, interconnecting wiring and recorders used to meter any Metered Quantity.
“Monitoring RTO” shall mean the Party that has operational control of a M2M Flowgate.
“Multiregional Modeling Working Group” or “MMWG” shall mean the NERC working group that is charged with multi-regional modeling.
“Mutual Benefits” shall mean the transient and steady-state support that the integrated generation and Transmission Systems in PJM and New York provide to each other inherently by virtue of being interconnected as described in Section 35.4 of this Agreement.
“MVAR” shall mean megavolt ampere of reactive power.
“MW” shall mean megawatt of capacity.
“NAESB” shall mean North American Energy Standards Board or its successor organization.
“NERC” shall mean the North American Electricity Reliability Corporation or its successor organization.
“Network Resource” shall have the meaning as provided in the NYISO OATT, for such resources located in New York, and the meaning as provided in the PJM OATT, for such resources located in PJM.
“New Year Market Flow” shall mean the Market Flow incorporating the transmission topology that includes all pre-existing Transmission Facilities and all new or upgraded Transmission Facilities whose impact on M2M Entitlements has been previously evaluated and incorporated, and all new or upgraded Transmission Facilities whose impact on M2M Entitlements is being evaluated in the current evaluation step.
“Non-Monitoring RTO” shall mean the Party that does not have operational control of a M2M Flowgate.
“Notice” shall have the meaning stated in Section 35. 20.22.
“NPCC” shall mean the Northeast Power Coordinating Council, Inc., including the NPCC Cross Border Regional Entity (“CBRE”), or their successor organizations.
“NYISO” shall have the meaning stated in the preamble of this Agreement.
“NYISO Code of Conduct” shall mean the rules, procedures and restrictions concerning the conduct of the ISO directors and employees, contained in Attachment F to the NYISO OATT.
“NYISO Market Monitoring Plan” shall refer to Attachment O to the NYISO Services Tariff.
“NYISO Tariffs” shall mean the NYISO OATT and the NYISO Market Administration and Control Area Services Tariff (“Services Tariff”), collectively.
“NYSRC” shall mean the New York State Reliability Council.
“NYSRC Reliability Rules” shall mean the rules applicable to the operation of the New York Transmission System. These rules are based on Reliability Standards adopted by NERC and NPCC, but also include more specific and more stringent rules to reflect the particular requirements of the New York Transmission System.
“OASIS” shall mean the Open Access Same-Time Information System required by FERC for the posting of market and transmission data on the Internet websites of PJM and NYISO.
“OATT” shall mean the applicable Open Access Transmission Tariffs on file with FERC for PJM and NYISO.
“Operating Entity” shall mean an entity that operates and controls a portion of the bulk transmission system with the goal of ensuring reliable energy interchange between generators, loads, and other operating entities.
“Operating Instructions” shall mean the operating procedures, steps, and instructions for the operation of the Interconnection Facilities established from time to time by the Coordination Committee or the PJM and NYISO individual procedures and processes and includes changes from time to time by the Coordination Committee to such established procedures, steps and instructions exclusive of the individual procedures.
“Operating Reserve” shall mean generation capacity or load reduction capacity which can be called upon on short notice by either Party to replace scheduled energy supply which is unavailable as a result of an unexpected outage or to augment scheduled energy as a result of unexpected demand or other contingencies.
“Operational Control” shall mean Security monitoring, adjustment of generation and transmission resources, coordinating and approval of changes in transmission status for maintenance, determination of changes in transmission status for reliability, coordination with other Balancing Authority Areas and Reliability Coordinators, voltage reductions and load shedding, except that each legal owner of generation and transmission resources continues to physically operate and maintain its own facilities.
“OTDF” shall mean the electric PTDF with one or more system facilities removed from service (i.e., outaged) in the post-contingency configuration of a system under study.
“Outages” shall mean the planned unavailability of transmission and/or generation facilities dispatched by PJM or the NYISO, as described in Section 35.9 of this Agreement.
“PAR” shall mean phase angle regulator.
“PAR Shift Factor” or “PSF”, shall mean the PAR’s impact on a Flowgate measured as the ratio of Flowgate flow change in MW to PAR schedule change in MW.
“Party” or “Parties” refers to each party to this Agreement or both, as applicable.
“PJM” has the meaning stated in the preamble of this Agreement.
“PJM Code of Conduct” shall mean the code of ethical standards, guidelines and expectations for PJM’s employees, officers and Board Members in their transactions and business dealings on behalf of PJM as posted on the PJM website and as may be amended from time to time.
“PJM Tariffs” shall mean the PJM OATT and the PJM Amended and Restated Operating Agreement, collectively.
“Power Transfer Distribution Factor” or “PTDF” shall mean a measure of the responsiveness or change in electrical loadings on Transmission Facilities due to a change in electric power transfer from one area to another, expressed in percent (up to 100%) of the change in power transfer in the pre-contingency configuration of a system under study.
“Real-Time Commitment” shall mean NYISO’s multi-period security constrained unit commitment and dispatch model, as defined in the NYISO Tariffs.
“Reference Year Market Flow” shall mean the Market Flow based on a transmission topology that includes all pre-existing Transmission Facilities and all new or upgraded Transmission Facilities whose impact on M2M Entitlements has been previously evaluated and incorporated.
“Region” shall mean the Control Areas and Transmission Facilities with respect to which a Party serves as RTO or Reliability Coordinator under NERC policies and procedures.
“Regulatory Body” shall have the meaning stated in Section 35.20.21.
“Reliability Coordinator” or “RC” shall mean the entity that is the highest level of authority who is responsible for the reliable operation of the Bulk Electric System, has the wide area view of the Bulk Electric System, and has the operating tools, processes and procedures, including the authority to prevent or mitigate emergency operating situations in both next day analysis and real-time operations. The Reliability Coordinator has the purview that is broad enough to enable the calculation of Interconnection Reliability Operating Limits, which may be based on the operating parameters of transmission systems beyond any Transmission Operator’s vision.
“Reliability Coordinator Area” shall mean that portion of the Bulk Electric System under the purview of the Reliability Coordinator.
“Reliability Standards” shall mean the criteria, standards, rules and requirements relating to reliability established by a Standards Authority.
“RFC” shall mean ReliabilityFirst Corporation.
“RTO” shall mean Regional Transmission Organization. For ease of reference, the New York Independent System Operator, Inc., may be referred to as an RTO in this Agreement and the NYISO and PJM may be referred to collectively as the “RTOs” or the “participating RTOs.”
“Schedule” shall mean a schedule attached to this Agreement and all amendments, supplements, replacements and additions hereto.
“SDX System” shall mean the system used by NERC to exchange system data.
“Security” shall mean the ability of the electric system to withstand sudden disturbances including, without limitation, electric short circuits or unanticipated loss of system elements.
“Security Limits” shall mean operating electricity system voltage limits, stability limits and thermal ratings.
“SERC” shall mean SERC Reliability Corporation or its successor organization.
“Shadow Price” shall mean the marginal value of relieving a particular constraint which is determined by the reduction in system cost that would result from an incremental relaxation of that constraint.
“Standards Authority” shall mean NERC, and the NERC regional entities with governance over PJM and NYISO, any successor thereof, or any other agency with authority over the Parties regarding standards or criteria to either Party relating to the reliability of Transmission Systems.
“Standards Authority Standards” shall have the meaning stated in Section 35.5.2.
“State Estimator” shall mean a computer model that computes the state (voltage magnitudes and angles) of the Transmission System using the network model and real-time measurements. Line flows, transformer flows, and injections at the busses are calculated from the known state and the transmission line parameters. The State Estimator has the capability to detect and identify bad measurements.
“Supplying Party” shall have the meaning stated in Section 35.8.2.
“System Operating Limit” or “SOL” shall mean the value (such as MW, MVAR, Amperes, Frequency, or Volts) that satisfies the most limiting of the prescribed operating criteria for a specified system configuration to ensure operation within acceptable reliability criteria.
“Target Value” shall have the meaning stated in Section 7.2 of Schedule D to this Agreement.
“Third Party” refers to any entity other than a Party to this Agreement.
“TLR” shall mean the NERC Transmission Loading Relief Procedures used in the Eastern Interconnection as specified in NERC Operating Policies.
“Transmission Adjusted Market Flow” shall mean the result of applying the M2M Entitlement Transmission Adjusted Market Flow Calculation to the New Year Market Flow. The resulting Transmission Adjusted Market Flow is then used as the Reference Year Market Flow in all subsequent, iterative, evaluations.
“Transmission Operator” shall mean the entity responsible for the reliability of its “local” Transmission System, and that operates or directs the operations of the Transmission Facilities.
“Transmission Owner” shall mean an entity that owns Transmission Facilities.
“Transmission System” shall mean the facilities controlled or operated by PJM or NYISO as designated by each in their respective OATTs.
“Transmission Facility” shall mean a facility for transmitting electricity, and includes any structures, equipment or other facilities used for that purpose as defined in the Parties respective OATTs.
“Transmission Reliability Margin” or “TRM” shall mean 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.
“Total Transfer Capability” or “TTC” shall mean 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.
“Voltage and Reactive Power Coordination Procedures” are the procedures under Section 35.11 for coordination of voltage control and reactive power requirements.
In addition to their roles as RTOs/ISOs and Reliability Coordinators, and the functions and responsibilities associated therewith, the Parties agree that each Party participated in the drafting of this Agreement and was represented therein by competent legal counsel. No rule of construction or interpretation against the drafter shall be applied to the construction or in the interpretation of this Agreement.
The Preamble and Recitals of this Agreement are incorporated into the terms and conditions of this Agreement and made a part thereof.
The word “including” shall be understood to mean “including, but not limited to.” The word “Section” refers to the applicable section of this Agreement and, unless otherwise stated, includes all subsections thereof. The word “Article” refers to articles of this Agreement.
All activities under this Agreement will meet or exceed the applicable Standards Authority standards, policies, or procedures as revised from time to time.
Each Party will perform this Agreement in accordance with its terms and conditions with respect to each Control Area for which it serves as ISO or RTO and, in addition, each Control Area for which it serves as Reliability Coordinator.
Effective Date: 12/31/9998 - Docket #: ER14-552-000 - Page 1