The Standard Market Design (SMD) commitment software does not automatically recognize a generator’s start-up and shut-down profiles. Instead, the software considers a generator available for dispatch at or above its economic minimum (ecomin) (i.e., the minimum megawatt amount of electric energy available from a generating resource for economic dispatch), from the first hour it is scheduled to be on line to the last hour scheduled on line. To ensure that generators are committed in accordance with the physical constraints inherent in their design, the generator owners must adjust the generator parameters to recognize start-up and shut-down profiles.
A resource can clear in the Day-Ahead Energy Market economically in the first hour of operation at amounts up to the greater of 1) their manual response rate multiplied by 60, or 2) their ecomin. Initially, the first hour of operation in clearing the day-ahead market is converted into a start-up time, and the last hour is converted into a shut-down time. These times do not include any start-up or shut-down profiles. After the close of the day-ahead market, the lead market participant or designated entity (DE) must review the schedules for their resources and submit any start-up or shut-down profiles to the forecaster. The forecaster will consider these values, along with the cleared day-ahead market schedules, and commit additional resources as required to meet capacity needs. Forecasters will advise the lead market participants or DEs of the intended commitments for generators committed as a result of the Reserve Adequacy Analysis (RAA) process and will request the start-up and shut-down profiles for these resources. These values will be incorporated in the RAA commitment to ensure that the software can consider all the generator outputs in the solution.
The definitions for specific generator parameters used for commitment purposes are as follows:
Notification time: The minimum time required for a generator to come on line from the time it receives the order from the ISO to the time the generator synchronizes to the system. A participant can submit three different notification times (i.e., hot, intermediate, and cold) to allow for reflecting the difference in the length of time needed to come on line for each condition.
Start-up time: The total time required from the time the generator synchronizes to the system to the time the generator is released to the ISO for dispatch. A participant can submit three different start-up times (i.e., hot, intermediate, and cold) to the ISO to allow for reflecting the difference in the length of time for each condition.
Start-up profile: This hourly profile describes the megawatt-hours of output expected during each of the hours in the start-up time. When a resource is committed in the Day-Ahead Energy Market or as a result of the Reserve Adequacy Analysis, the generator owner is required to report to the ISO the megawatt-hours expected for each of the hours, from the time the generator synchronizes to the system to the time the generator is scheduled to be released to the ISO for dispatch. These megawatt-hour values should match the applicable hot, intermediate, or cold start times submitted. If the generator’s start time is 30 minutes or less, the owner should not need to submit a start-up profile.
Shut-down profile: This hourly profile describes the megawatt-hours of output that normally occurs in each hour from the time a generator is released by the ISO for shut down from ecomin to the time the generator desynchronizes from the system. The owners of resources that can desynchronize from ecomin in less than 30 minutes should not submit a shut-down profile to the ISO.
Hot to cold time: The time from desynchronization that cold conditions apply.
Hot to intermediate time: The time from desynchronization that intermediate conditions apply.
Minimum run time: The minimum number of hours of operation at or above a generator’s ecomin that the generator owner requires the ISO recognize when committing the resource. The minimum run time is from the point when the generator is scheduled to be released to the ISO for dispatch from ecomin to the point when the ISO releases the generator for shut down from ecomin. Generator owners should exclude the start-up profile hours (start-up time) and shut-down profile hours from the minimum run time to ensure that the software recognizes all the generator’s constraints associated with cycling the resource in the commitment process. Resources clearing in the day-ahead market will have schedules for consecutive hours equal to or greater than the minimum run time.
Minimum down time: The minimum number of hours a generator owner requires between the time the ISO releases the generator for shut down and the time the generator is scheduled to be released for dispatch to the ISO. Generator owners should include the shut-down profile hours and the start-up profile (start time) hours in the minimum down time to ensure that the software recognizes all the generator’s constraints associated with cycling the resource in the commitment process. Resources clearing in the day-ahead market will have schedules that do not violate the minimum down time.
No-load cost: The cost associated with a generation resource that is an on line but not supplying electric energy to the system. It is the dollar per hour amount that participants with an ownership share in a generating unit scheduled in the New England wholesale energy market must be paid. The no-load cost is an additional payment to the start-up fee and price offered to supply electric energy for each hour.
Claim 10 and claim 30: The generation output levels, expressed in megawatts, a resource can reach within 10 or 30 minutes, respectively, from an off-line state after receiving a dispatch instruction. Claim-10 and claim-30 values also represent the amount of reduced consumption, expressed in megawatts, a dispatchable asset-related demand (DARD) resource can reach within 10 or 30 minutes after receiving a dispatch instruction). These values must be part of the generator's offer data and are used by the ISO to evaluate the generator in meeting NEPOOL's operating and replacement reserve requirements.
Claimed capability: A generator’s maximum production or output
Claimed-capability audit (CCA): Establishes the winter and summer seasonal claimed capability (SCC) values of a generator.
Establish claimed-capability (ECC) audit: A resource audit conducted in accordance with Market Rule 1, Section III.1.5.1.2, to establish its commercial capability.
Economic minimum (ecomin): The minimum amount of electric energy (in megawatts) available from a generating resource for economic dispatch.
Economic maximum (ecomax): The highest unrestricted level of electric energy (in megawatts) a generating resource is able to produce, representing the highest megawatt output available from the resource for economic dispatch.
Seasonal claimed capability (SCC): A generator’s maximum production or output during a particular season, adjusted for physical and regulatory limitations.
References:
Generators must meet a number of the eligibility requirements contained in Market Rule 1 and the ISO Manuals to become active in the ISO markets. The basic technical requirements can be found in Operating Procedure No. 14. Generators must meet pass the following tests and audits:
VAR test—To test a qualified reactive resource’s capability of producing reactive power voltage support for the New England transmission system for participating in the VAR compensation program
Black-Start Test: Process Black Start Unit Testing SOP-RTMKTS.0180.0080 — to test whether a resource is capable of starting and remaining energized without support from off-site power
Claimed-capability audits (CCAs)—to establish the seasonal claimed capability (both winter and summer) of a generator.
References:
Claimed-capability audits are conducted to establish the winter and summer seasonal claimed capability (SCC) values of a generator asset and to comply with NPCC Regional Reliability Reference Directory # 9 Verification of Generation Gross and Net Real Power Capability.
Market Rule 1, Section III.1.5.1, Claimed-Capability Audits, and ISO Operating Procedure No. 23 are the two principal governing documents. On September 1, 2013, the claimed-capability audit tool (CCAT) on the SMD Applications homepage became the sole means of requesting, submitting, and reviewing CCAs.
To coordinate demonstrations with the ISO New England Control Room (i.e., to self schedule a CCA for requesting an increase in an asset’s capability, consult the ISO’s M-RPA Registration and Performance Auditing.
Users must:
View additional CCA training materials on the Training Materials page.
The lead market participant must submit a completed audit request through the CCAT by 5:00 p.m. on the fifth business day following the day on which the generator asset demonstrated its capability.
Seasonal claimed-capability audits and establish claimed-capability audits can be performed anytime during a given capability demonstration period, provided that certain requirements are met per the ISO’s Manual for Registration and Performance Auditing (Manual M-RPA). A generator asset’s summer and winter SCC values are the minimum of the “establish” and SCCA values. Refer to Market Rule 1, Section III.1.5.1, Claimed-Capability Audits, for more details.
A generator asset’s summer and winter SCC values are the minimum of the establish and SCCA values. If the SCCA value is less than the establish value, a participant’s seasonal audit of a self-scheduled run may result in an increase in the SCC value, provided the SCCA value is greater than the existing value in the CCAT.
The lead market participant of a generator asset may perform as many SCCAs as it wishes during a given capability demonstration year, with the subsequently approved audit overwriting the previous audit value. Depending on the result of an audit, the new SCCA value could increase or decrease the generator asset’s SCC value.
The SCC value is ultimately limited by the network resource capability (NRC) value, which is published annually in the CELT Report. The NRC value may change, however, before the next annual publication of the CELT report. If the NRC value increases, the SCC value could go higher, if demonstrated.
Generator owners can check the claimed-capability auditing tool to determine the limiting value, and then conduct the appropriate audit type—establish or seasonal—for the generator asset.
In the CCAT, the lead market participant can directly submit a request for a seasonal claimed-capability audit, but must request an audit to establish an asset’s claimed capability (i.e., an “establish” claimed-capability audit).
With access to the SMD applications, lead market participants can select “Bids and Offers” and the “Generation” tab. In the Generation area, they can submit up to 10 ramp rates per day.
The Day-Ahead Energy Market uses a weighted average of all the ramp rates submitted as part of the resource's supply offer. The Real-Time Energy Market uses the ramp rate for the megawatt segment being dispatched.
Yes, losses occur. The ISO models generators less than 55 MW against an existing load (LD) node and settles it at the zone level. Losses are calculated as part of the locational marginal price (LMP) at the zone. For generators greater than 5 MW, the ISO engineers a unique node and settles it at the pricing node (pnode). Losses are calculated at the pnode.
Reference: Pricing-Node Table.
Resources must have a RIG to be considered dispatchable in real time. A resource without a RIG cannot bid as a dispatchable resource and must submit equal values for its economic minimum (ecomin) and economic maximum (ecomax) (i.e., The ecomin and ecomax values for nondispatchable units must be equal; they do not have a dispatchable range).
The participant would call the generator coordinator in the ISO New England Control Room and request a self-schedule. If approved, the generator would be paid the real-time LMP.
Generator owners are required to schedule any testing or maintenance activity that can have an impact on normal operations or the expected availability of their resource(s). The ISO’s Operating Procedure No. 5 (OP 5) describes in detail the rules and requirements for scheduling generator tests, reductions, or outages. Receiving approval through these protocols for scheduling any testing or maintenance activity is essential for generator owners.
Generator owners are also responsible for submitting bids and offers into the market that reflect or support the testing or maintenance activity being performed. For example, if an owner has scheduled a test that requires the generator to operate at half load from 10:00 a.m. to 12:00 noon, the generator must submit the following:
A self-schedule with an ecomin value set to half load for hours ending 11:00 a.m. and 12:00 noon (the preceding hourly periods, 10:00 a.m. to 11:00 a.m. and 11:00 a.m. to 12:00 noon). A self-schedule ensures that the generator will not be dispatched economically below the half-load level or ecomin and that the test can be performed. When self-scheduling, the generator must recognize the generator parameters, such as minimum runtime, submitted to the ISO.
An ecomax value set to half load for hours ending 11:00 a.m. and 12:00 noon. This ensures the unit will not be dispatched economically above the half-load level or ecomax and also that the test can be performed. It also ensures that the ISO will not need to rely on reserve capability above the half-load level during the testing activity.
The Control Room Operating Procedure, CROP.36003, Commitment Decommitment Self-Scheduling, Sections 2, 6, and 7, state that the designated entity should allow 30-minutes notice when requesting a change to its self-schedule so that the ISO can evaluate system conditions.
Combined-cycle generating stations typically consist of multiple gas turbine (GT) generators and a single steam generator. These stations can be operated in several different configurations, each one represented by its own set of operating limits, characteristics, and costs, including the following:
The lead market participant cannot effectively reflect the operating characteristics of the individual generators within the CC station. As a result, the SMD software dispatches these generators at output levels the units cannot achieve. At times, the real-time dispatch will issue desired dispatch points (DDPs) that toggle between a single GT output and a multiple GT output. These DDPs cannot be reached simply because of physical station limitations and can lead to a resource being flagged for not following DDPs.
Unit commitment takes into account all the costs of producing the energy, including no-load costs and start-up costs. At the same time, it respects each resource's characteristics, such as minimum up time and minimum down time. The parameters used in unit commitment are as follows:
Participation in the Forward Reserve Market (FRM) begins by clearing a portfolio of megawatts in the Forward Reserve Auction in a reserve category (30-minute operating reserve [TMOR] or 10-minute nonspinning reserve [TMNSR]) to meet either zonal or systemwide reserve requirements.
After the offer has cleared, the lead market participant must make a bid for the reserve obligation above the threshold price, which it must meet by assigning megawatts to a specific unit(s). Market Rule 1, Section III.9.5.1, describes the criteria for on-line and off-line units to become eligible to cover FRM obligations. An on-line unit must have a dispatchable range of megawatts available within the timeframe of the assigned FRM obligation. An off-line unit must be a fast-start generator with established claim-10 or claim-30 values. These values must be part of the generator's offer data, which the ISO uses to evaluate the generator in meeting operating and replacement reserve requirements. Refer to ISO New England Manual 35 for additional information.
Manual 35 defines a fast-start generator as a generating unit the ISO may dispatch within the hour electronically that (i) has a minimum run time that does not exceed one hour; (ii) has a minimum down time that does not exceed one hour; (iii) has a time to start that does not exceed 30 minutes; (iv) is available for dispatch and staffed or has automatic remote dispatch capability; (v) is capable of receiving and acknowledging a start-up or shut-down dispatch instruction electronically, and (vi) has satisfied its minimum down time.
The ISO Control Room will not necessarily acknowledge a unit changing its characteristics or bidding parameters to reflect its being fast-start unit. For a unit to be considered a fast-start unit or be removed from fast-start status, the lead market participant must submit a formal request via “ASK ISO” using an updated NX-12 form. A subsequent process will follow before the ISO will change the unit’s fast-start status or recognize it for dispatch.
All NX-12 submissions should be sent to opanx12@iso-ne.com.
FI_UNITOPER reports are not generated for units that have been designated as fast-start resources; they are only generated for all other units.
To establish a unit with either or both claim-10 or claim-30 eligibility, the resource must have already have been established as a fast-start unit. The lead market participant or designated entity must submit the request to Participant Support and Solutions at askiso@iso-ne.com. The request should include the asset name and number and the expected megawatt values to be performed during the claim-10 and claim-30 audits.
Reference: SOP-RTMKTS.0180.0030 Audit Resource Parameters
The only seasonal claimed-capability audit types for which lead market participants can submit claim-10 or -30 audit and CCA requests simultaneously are those that do not include an advanced notice of the start time. A CCA test may not be used for auditing claim-10 or claim-30 parameters; a CCA-Establish, CCA-Retest, and CCA-Restore may be used for auditing claim-10 or claim-30 parameters. The ISO New England Manual for Installed Capacity, M-20, Appendix D, Section 3.2, contains additional information on CCA types.
Lead market participants can submit a request to test for either or both a new claim-10 or claim-30 value at any time to Participant Support at askiso@iso-ne.com. The request should include the asset name and number and the expected megawatt values perform during the audits.
Reference: ISO New England Manual M-11, Market Operations, Section 2.6, Resource Performance Audits.
Lead market participants can request that the output from the test be the cap value for either the claim-10 or claim-30 value.
If a unit does not meet the expected megawatts, the clock gets reset and the generator owner will need to request another test. If for example a tested unit demonstrates that it can only meet the claim-30 test and not the claim-10 test, the unit can be retested for the claim-10 value, or the value that was demonstrated can become the unit cap.
Yes, the claim-10 and claim-30 values that resources have demonstrated in the current capability period will carry over to the next capability period.
If a unit is capped at a "0" value for either claim 10 or claim 30, the generator owner will need to request a claim-10 or claim-30 test as applicable.
These parameters are important for the following reasons:
System Operation Impact
The ISO New England Control Room uses this information on the megawatt amount the system dispatch can count on as being available from an off-line state within 10 minutes or 30 minutes of a dispatch Instruction.
Market Operations Impact
An off-line resource requires a claim-10 or claim-30 value greater than zero to be eligible to receive a reserve-shortage opportunity cost.
The Forward Reserve Market uses claim-10 and claim-30 values to measure the delivered forward reserve of off-line forward-reserve resources. A zero value represents an inability to satisfy North American Electric Reliability Corporation (NERC) and Northeast Power Coordinating Council (NPCC) criteria for providing either 10-minute or 30-minute nonsynchronous operating reserve from an off-line state (see Market Rule 1, Sections 3.3.5, and 3.3.7.1, and examples in Section 3.3.7.4). Therefore, a zero claim-10 or claim-30 value will result in nonpayment and potential penalties in the Forward Reserve Market.
ISO New England strongly suggests that participant generation owners review the data parameters for their generating units’ claim-10 and claim-30 offers. The current values can be seen in the “Unit Manager” screen in eMarket. Only the lead market participant can request a change to the parameters listed with zero values caused by an audit failure, which they can initiate via a call to ISO New England's Control Room.
The lead market participant can initiate the change process via an email or telephone call to ISO New England's Participant Support Department at askiso@iso-ne.com or 413-540-4220 or through eMarket. A DE can initiate the redeclaration process through Operations. The lead market participant or DE are responsible for the accuracy of these parameters, as well as any impacts to the market settlements that occur as a result of these values.
These parameters are subject to audit and redeclaration by the ISO or the DE under Manual 11. In addition, Manual 11 provides, in cases where no amount was submitted, for a default value of zero.
Units that have limits on start-ups (or total generation during the year or portion of the year) may reflect the associated opportunity costs in their offers as appropriate. Market Rule 1, Appendix A, Section 3.1.2, requires the ISO to consider all available explanations of behavior that are based on a participant's cost of providing any market product, including any relevant opportunity costs. This information can be incorporated into the determination of the reference price, as specified in Appendix A, Section 5.6.1.b.iii. This requires that the unit owner contact the ISO in advance of submitting such an offer to ensure that it is included in the unit's reference price. Inclusion of opportunity costs, either in the submitted start-up cost or energy offer, ensures that the market dispatch software dispatches the unit appropriately.
Another option for a lead market participant is to manage a unit’s availability for dispatch through the use of a maintenance outage for economic reasons, per the maintenance and outage scheduling processes of Operating Procedure No. 5 for generators and dispatchable asset-related demand resources. In short, generators can be granted approval for an outage that is for economic reasons provided sufficient generation is available to meet capacity requirements. If the ISO approves such a request, the participant is obligated to make its best efforts to restore the generator to service as requested by the ISO in the event of a real or anticipated need to implement Operating Procedure No. 4, Action during a Capacity Deficiency.
Resources that wish to retire must do the following:
Resources seeking to retire that are currently listed as capacity resources in the FCM must submit either a permanent delist bid or a retirement delist bid. See the FCM Participation Guide for more details.
For energy-only facilities (those resources or assets not currently listed as capacity resources), the lead market participants are responsible for ensuring that their obligation(s) in any of the ISO New England markets in which these facilities participate have been satisfied.
For more details on resource retirement rules, see the ISO Tariff, Section III.13.2.5.2.5.3, Retirement and Permanent Delisting of Resources.
A generator’s regulation high limit is the maximum amount of electric energy the generating unit can reliably produce when it is providing regulation. The regulation high limit may be less than or equal to the unit's ecomax limit.
A generator’s regulation low limit is the minimum amount of electric energy the generating unit can reliably produce when it is providing regulation. The regulation low limit may be greater than or equal to the unit's ecomin limit.
Lead market participants should bid in a RegHi value to the highest megawatt level the resource can regulate (less than or equal to the ecomax) and a RegLo value to the lowest level the resource can regulate (greater than or equal to the ecomin). Generators with multiple AGC ranges should bid in the RegHi of the highest range and the RegLo of the lowest range. To affect operations within any prescribed ranges that the resource may be physically able to operate in, designated entities should submit to the ISO system operator redeclarations of the RegHi and RegLo values based on actual loading in real time. Redeclaration of the limits is allowed provided that the new values stay within the boundaries of the initial RegHi and RegLo limits.
For example, assume the following:
Manual M-11, Section 3.2.1 (3)(b) states that the regulation capability is calculated automatically as the lesser of five times the automatic response rate or one-half of the difference between the RegHi and RegLo limits.
Using the above example:
Automatic Response Rate (8 MW) × 5 = 40 MW/mim
{RegHi (700 MW) – RegLow (300 MW)}/2 = 200 MW
Thus, the regulation capability would be 40 MW
If a generator is self-scheduled for regulation for any portion of an hour, it is ineligible to receive opportunity cost payments. It will be paid a capacity reservation payment equal to the following:
Hourly regulation clearing price × integrated regulation capability while regulating × time on (in minutes) during the hour/60 minutes.
It will also receive a service or mileage payment equal to the following:
1 × hourly regulation clearing price × AGC service,
where the AGC service is computed as the absolute value of the output changes requested, assuming a response without delay at the claimed rate of response and without overshoot.
When a generator has requested to be self-scheduled for regulation, its ranking price, except for a tiebreaker, is zero. Energy bid blocks are not considered at all in the ranking because a generator self-scheduled for regulation will not get paid an opportunity cost. So a lead market participant’s request for a self-scheduled-for-generation status will be accepted, except if there are transmission or other reliability concerns or if its larger self-scheduled-for-regulation generators have met the full requirements. Note that a regulation bid, when self-scheduled for regulation, is treated as a zero-regulation bid.
An asset must meet a few requirements to qualify as a nondispatchable asset-related demand asset. Manual 28, Section 12.3.5.3 details the following requirements for an asset’s registration process flow:
The asset must be an individual end-use metered customer or firm that purchases products for its own consumption and not for resale (i.e., an ultimate customer)
The end-use customer’s peak load must be 5 MW or greater during the 12 months preceding enrollment. The host participant assigned meter reader must evaluate new end-use customer loads without 12 months of history to determine whether the anticipated load will meet the 5 MW threshold.
End-use customer loads cannot be aggregated to meet the 5 MW threshold.
Operating Procedure No. 18 specifies the criteria for metering and telemetering.
Dispatchable asset-related demand asset requirements include all the requirements for the nondispatchable asset-related demand asset, but DARD assets also must be able to receive and follow electronic dispatch (ED) instructions. To meet this requirement the DARD assets must comply with the technical requirements for generation, dispatchable asset-related demands, and interruptible loads specified in Operating Procedure No. 14, which were reviewed at the May 2, 2013 Reliability Committee meeting. The electronic dispatch requirements include, but are not limited to, the installation and operation of a Remote Interface Gateway (RIG) for the identification of a designated entity.
