No, a self scheduled CCA-Test can only be used to verify the asset can meet or beat the current claimed capability. The results will be a pass, in which the asset will maintain its current claimed capability or a fail, in which ISO-NE will de-rate the asset to the demonstrated amount.

A CCA-Restore is the proper test request when you want to get the capability of the asset back up to capability that was previously claimed sometime over the past 2 like demonstration periods. Typically this is due to a recent de-rate to the asset due to a failed test. A CCA-Establish is the proper test request when you want to increase the capability to something greater than has been claimed over the previous 2 like demonstration periods. Typically a CCA-Establish is requested due to some modification or improvement to the generator which would result in a greater capability.

ISO-NE must receive the request to audit a run of an asset by 5:00 PM on the second working day after the day when the run took place.

A gas turbine has a temperature curve, which allows you the option of increasing the summer and/or winter capability any time of the year.

Diesel, Fossil, Nuclear, Pumped Storage, and Hydro-Conventional Weekly assets can only increase their summer capabilities during the summer demonstration period, which goes from June 1st through September 15th.

Diesel, Fossil, and Nuclear assets can increase their winter capabilities any time of the year.

With access to the SMD Applications you can select Bids and Offers and the Generation tab. In the Generation area you can submit up to 10 Ramp rates on a daily basis.

The Day-Ahead Market uses a weighted average of the of all ramp rates that are submitted as part of the Resource's Supply Offer.

The Real-Time Energy Market utilizes the ramp rate for the MW segment being dispatched.

Resources must have a RIG to be considered dispatchable in Real-Time. Resources without a RIG cannot bid as a dispatchable, and must submit EcoMin and EcoMax values that are equal.

You would call the generator coordinator in the ISO New England Control Room and request a Self Schedule, if approved - you would be paid the Real-Time LMP.

The essentials for scheduling of any testing or maintenance activity is to ensure that approval is obtained through the NEPOOL Operating Procedure 5 protocols and that the data submitted into the Market for the resource supports the activity.

Generator owners are required to schedule any testing or maintenance activity that can impact normal operation or expected availability of their resource(s). NEPOOL Operating Procedure 5 describes in detail the rules and requirements for the scheduling of generator tests, reductions or outages.

Generator owners are also responsible for submitting bids and offers that reflect or support the testing or maintenance activity being performed. For example, if an owner has scheduled a test that requires that the generator operate at half load from 10:00 to 12:00, then the generator must submit the following:

A self-schedule with an EcoMin value set to half load for hours ending 11 and 12. A self-schedule ensures that the generator will not be dispatched economically below the half load level or EcoMin ensuring that the test can be performed. When self-scheduling, the generator must recognize the generator parameters, such as minimum runtime, that were submitted to ISO-NE.

An EcoMax value set to half load for hours ending 11 and 12. This ensures the unit will not be dispatched economically above the half load level or EcoMax ensuring that the test can be performed. It also ensures that ISO-NE does not rely on reserve capability above the half load level during the testing activity.

Combined Cycle generating stations are typically comprised of multiple GTs generators (2 to 3) and a single steam generator. These stations can be operated in several different configurations. Each configuration is represented by its own set of operating limits and characteristics, and costs. These include the following:

I cannot effectively reflect the operating characteristics of the individual generators within the CC station. As a result, the SMD software has dispatched these generators at output levels that the unit's cannot achieve. At times, the Real-Time dispatch will issue 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 my resource being flagged for not following DDPs.

Unit Commitment takes into account all of the costs of producing the energy, including no load costs and startup costs. At the same time, it respects each resource's characteristics such as minimum up time, minimum down time.

Parameters Used in Unit Commitment

• Incremental Energy Offer Curves
• Startup Costs $ (Hot, Cold, Intermediate)
• Costs incurred per startup of the resource
• Type of start is based upon number of hours down since previous run
• No Load Costs $
• Fixed cost that is incurred every hour the resource is running
• Minimum Run Time (in hours or fractions of hours)
• Minimum Down Time (in hours or fractions of hours)
• Economic Minimum and Economic Maximum

Participation in the Forward Reserve Market (FRM) begins by clearing a portfolio of MW's in the Forward Reserve auction in a reserve category (TMOR or TMNSR) to meet either zonal or system wide reserve requirements.

Once the offer has cleared, the reserve obligation must bid above the threshold price then be met by assigning MW's to a specific unit(s). MR-1, Section III.9.5.1 describes the criteria for eligibility for both online and offline units to be designated to cover FRM obligations. An online unit must have a dispatchable range of MW's available within the timeframe of the assigned FRM obligation. An offline unit must be a fast start generator with established CLAIM10 or CLAIM30 values.

A fast start generator is defined in Manual 35 as follows:

Fast Start Generator shall mean a generating unit that the ISO may dispatch within the hour through electronic dispatch and that meets the following criteria: (i) minimum run time does not exceed one hour; (ii) minimum down time does not exceed one hour; (iii) time to start does not exceed 30 minutes; (iv) available for dispatch and manned or has automatic remote dispatch capability; (v) capable of receiving and acknowledging a start-up or shut-down dispatch instruction electronically (vi); and has satisfied its minimum down time.

You can request that the output from the test be the cap value for either the CLAIM10 or CLAIM30.

If you unit does not meet the expected MWs you the clock gets reset. You will need to request another test. If for example you request both CLAIM10 and CLAIM30 and demonstrate that the unit can only meet the CLAIM30, you could retest for the CLAIM10 or cap the value that was demonstrated.

Yes if the resource has demonstrated in the current capability period those values will carry over to the next capability period.

If your unit is capped as "0" values for either/or CLAIM10 and/or CLAIM30 you will need to request a CLAIM10 and/or CLAIM30 test.

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 provides that ISO-NE "will consider all available explanations of behavior that are based on a Participant's cost of providing any market product, including [a]ny relevant opportunity costs." This information can be incorporated in Reference Price determination as specified in Appendix A, Section 5.6.1.b.iii. This requires that the unit owner contact ISO-NE 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 is to manage availability for dispatch through the use of Maintenance Outage for economic reasons per Operating Procedure 5 Generator and Dispatchable Asset Related Demand Maintenance and Outage Scheduling processes. In short, generators can be granted approval to an outage that is for economic reasons provided there is sufficient generation available to meet capacity requirements. If a request of this type is approved by ISO-NE, the Participant is obligated to make best efforts to restore the Generator to service as requested by ISO-NE in the event of an actual or anticipated OP 4 Action During a Capacity Deficiency implementation.

Regarding clarification of DDP tolerance:

Generators with an Economic Max less than or equal to 50 MWs are considered to be following a dispatch instruction if the actual output of the generator is not greater than 5 MWs above its desired dispatch point and is not less than 5 MWs below its desired dispatch point for each interval in the hour. If the generator violates this criterion in any interval during the hour, the generator is considered to be not following dispatch instructions for the entire hour.

With regard to how qualifying MW's are calculated for the Locational Forward Reserve market, these are calculated using real-time offer parameters, as noted in Market Rule 1, section III.9.6.4:

"On-line qualifying megawatts: is the capability that is less than or equal to the Economic Maximum Limit and above the Economic Minimum Limit that is offered at or above the applicable Forward Reserve Threshold Price by an on-line generating Resource..."

Here's an example of this calculation:
Qualifying MW Upper Limit (Ecomax) - Qualifying MW Lower Limit (Ecomin)

Forward Reserve Obligation: 15 mw. Eco Max 47(Bid Parameter) - Eco Min 37(Bid Parameter) = 10.0 Qualifying MW. This results in a failure to reserve penalty of 5 mw.

Generator owners should bid in the RegHi value to the highest MW level that the resource can regulate (must be less than or equal to the EcoMax), and should bid in the RegLo value to the lowest level that the resource can regulate (must be greater than or equal to the EcoMin). Generators with multiple AGC ranges should bid in the RegHi of the highest range and the RegLo from the lowest range. Based on actual loading in Real-Time, redeclarations of the RegHi and RegLo values should be submitted by the Designated Entity to the ISO-NE System Operator to effect operation within any prescribed ranges the resource may be physically capable of operating within. Redeclaration of the limits is allowed provided that the new values stay within the boundaries of the initial RegHi and RegLo limits.

Regulation High and Regulation Low limit is determined as follows:

The Regulation High Limit is the maximum amount of energy that a generating unit can reliably produce when that unit is providing Regulation. The Regulation High Limit may be less than or equal to the unit's Economic Maximum Limit.

The Regulation Low Limit is the minimum amount of energy that a generating unit can reliably produce when that unit is providing Regulation. The Regulation Low Limit may be greater than or equal to the unit's Economic Minimum Limit.

Example:
EcoMax 700 MW
EcoMin 300 Mw
Response Rate 8 Mw/Min
Manual Response Rate 40 mw

ISO New England manual M-11, Section 3.2.1 (3)(b) Regulation Capability will be calculated automatically as the lesser of 5 times the Automatic Response Rate and one-half of the difference between the Regulation High Limit and the Regulation Low Limit.

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:

Hourly regulation clearing price * integrated regulation capability while regulating * time on in minutes during the hour/ 60 minutes.

1 * hourly regulation clearing price *AGC service

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 Self-Scheduled for regulation generator will not get paid opportunity cost. So if you are requesting a Self-Scheduled for generation status, you'll be accepted for it unless there are transmission or other reliability concerns, of its larger Self-Scheduled for regulation generators have met the full requirements. Note: that your regulation bid, when Self-Scheduled for regulation, is treated as a zero regulation bid.

Regulation Service Credits = your Regulation Service MW x the greater of the RCP or Offer x 0.1 (Q factor)