GENERAL

What is an Independent System Operator?

An Independent System Operator (ISO) is sanctioned by the Federal Energy Regulatory Commission (FERC) to manage a transmission system. An ISO controls the power system without special interest, and owns no generation, transmission or load. The ISO oversees and runs the system fairly, for the benefit of all Market Participants.

What is the New York Independent System Operator?

The New York Independent System Operator (NYISO) oversees the state's transmission facilities to maintain reliability. It is responsible for administering the ISO Transmission Tariff and implementing and operating New York's Open Access Same-Time Information System (OASIS). It also runs New York’s power markets.

How is the NYISO governed?

The NYISO is governed by a 10-member Board of Directors, none of who are affiliated with Market Participants (MPs). The Board is responsible for the operation and financial affairs of the NYISO, and may establish committees and subcommittees. These groups are in addition to formal committees that are part of the NYISO’s Shared Governance Structure – made up of the Management Committee (MC), the Operating Committee (OC), the Business Issues Committee (BIC) and a number of subcommittees and working groups.

What is the NYISO’s Shared Governance Structure? How does it work?

The NYISO’s shared governance structure is the process used for making policy decisions that dictate how New York’s electric system and wholesale electricity markets will operate.
Market Participants (companies registered to do business in New York’s power markets ), government officials and public interest groups work together in committees and working groups to forward market improvement recommendations to the Board of Directors.
The Board affirms these recommendations and files jointly with the MPs at the Federal Energy Regulatory Commission (FERC), rejects them, or sends them back to the committee process for further refinement.
The shared governance structure includes three committees that oversee the management, operations and business issues of the NYISO and its power markets.
Management Committee
The Management Committee (MC) supervises and reviews the work of all other NYISO committees, develops recommendations to the Board concerning issues, and prepares budgets for Board review and approval. All parties to the NYISO Agreement (public interest groups and MPs) have voting representation on the Management Committee; a 58% affirmative vote is needed to pass a measure.
Operating Committee
The Operating Committee (OC) establishes and oversees procedures for coordinating New York power system operations.
Business Issues CommitteeThe Business Issues Committee (BIC) establishes procedures for the efficient, non-discriminatory operation of electricity markets coordinated by the NYISO

Who conducts business with the NYISO?

Market Participants (MPs) conduct business with the NYISO. Many MPs are eligible customers – entities qualified to submit schedules to the NYISO and to participate in the NYISO settlement process. Eligible customers include buyers and owners of Transmission Congestion Contracts (TCCs), suppliers, power exchanges, marketers, and load serving entities (LSEs).

Why do I receive the error message” VBScript Error 1B6” when applying for a digital certificate?

There can be two possible reasons for this error message to be generated:

1. While filling out the digital certificate application a comma was inserted in the company field.

2. If punctuation is not placed in the company field and an error message is still generated, then the browser needs to be patched with Microsoft updates.

The xenroll.dll file is the visual basic code file that is responsible for generating this private key based on the three unique fields submitted. The only fix for this situation is to patch this xenroll.dll file by visiting the Microsoft windows update site located at:

Microsoft Windows Update

How do I register to become a NYISO customer?

Obtain the registration form from the NYISO site below. Follow the instructions for the application and mail the completed form to the enclosed address. Please note that no faxes or email messages will be accepted.

NYISO Registration

How do I apply for a Digital Certificate?

To apply for a Digital Certificate access the application form from this link.

Digital Certificate

Please note that we must receive authorization from your organization's MIS Administrator if you did not previously have a Digital Certificate. For additional information on Digital Certificate please refer to Technical Bulletin #1.

Where can I obtain the status of my digital certificate?

Explorer: Tools - Internet Options - Content - Certificates

Where can I find a list of the current NYISO projects?

Visit the NYISO web site at:

Projects

What is meant by a ‘Lumpy’ commitment and how may it affect my transaction or generating unit?

LBMP Prices are determined by an ideal dispatch. In the ideal dispatch, GTs are allowed to be dispatched economically over their entire operating range (0 MWs to Max MWs). The MW schedules are determined in a second ‘blocked’ dispatch. In this dispatch, GTs are dispatched according to their physical generation characteristics. By definition, GTs in this ‘blocked’ dispatch are scheduled at their minimum generation level that translates to their maximum MW limit. As a result, a transaction or generating unit scheduled in the ideal dispatch may have its actual schedule curtailed to compensate for the additional GT scheduled MWs. As an example, assume a transaction has been scheduled at 200 MWs for HB05-HB10 in the ideal dispatch and a 200 max MW GT is dispatched to 0 MWs for HB09-HB10. In the second or ‘blocked’ dispatch the transaction schedule for HB05-HB08 is unaffected. However, for HB09-HB10, the GT must be dispatched to 200 MWs. To compensate for the extra 200 MWs of generation from the GT, other generating units or transactions must be curtailed. For the example here, assume that the 200 MW transaction is the marginal transaction and thus scheduled at 0 MWs.

Sometimes, it is not intuitively obvious that a transaction’s or generating unit’s schedule is reduced due to the dispatch of a GT. Taking the above example, what would happen if reducing the transaction to 0 MWs would create a system constraint? The transaction would be reduced to the lowest MWs without creating a constraint [as an example 100 MWs]. The remaining 100 MWs would be curtailed from the next transaction or generating unit based upon economics [without creating system constraint].

What are some examples where the NYISO may update posted prices?

1. Reserve pick-ups.

This was a problem fixed in 2000. SCD had been incorrectly calculating prices during reserve pick-ups. As a result, prices were reserved and subsequently changed. 2, Discrepancies between proxy bus and load bus prices.

Zonal prices are a weighted average of generator prices in a given zone. At the start of the ISO, price changes that were made to generators did not properly carry over to changes in zonal prices. As a result, zonal prices had to be reserved and changed to reflect the zonal price changes. Technical Bulletin 28 gives more detail on how zonal prices are calculated

3. Missing SCD intervals

The NYISO has a direct metering communication system with generators. One piece of this system in called the “Performance Tracking System” (aka PTS). SCD results are communicated to generators via PTS. Occasionally communication between SCD and PTS fails. As a result, prices don’t post for the “bad” intervals. Prices have to be posted after the fact from a storage database.

4, Dispatch interval type ‘R’

Generators providing reserves have 10 minutes (approx. 2 SCD intervals) to get to their new basepoint. If the unit doesn’t get there, the Performance Tracking System (PTS) will send one more basepoint to the unit. This basepoint is used to determine the unit’s reserve availability payment only; it is not used in LBMP calculations. As a result, that interval needs to be reserved and deleted from the LBMP calc. Originally, prices posted under OASIS did not reflect the price corrections that were made. Now, corrected intervals are flagged under OASIS.

BIDDING SCHEDULING & DISPATCH

How are the Desired Net Interchange (DNI) values derived on the Balancing Market Advisory Summary report?

This summary is first populated with the net MW amounts scheduled for each neighboring control area from the initial Security Constrained Unit Commitment (SCUC) run. The net MWs may be modifies after the Day Ahead check out. The posted Balancing Market Evaluator (BME) schedules will not be used to update the summary. After the hourly Control Area check out is completed, the report is revised again to reflect the “actual” net MW amounts.

How is the congestion component calculated when a Desired Net Interchange (DNI) ramp constraint occurs between the New York Control Area (NYCA) and an outside Control Area?

Just as with other busses, the Proxy busses for the Control Area’s Locational Based Marginal Price (LBMP) congestion component is influenced by NYISO security and line constraints. Unlike other busses the Proxy Bus LBMP is also influenced by the NYCA DNI ramp constraint, which is typically 700 MW. Participants will notice that when the DNI ramp rate constraint is binding, the congestion components of the LBMP are the same for all four proxy busses. Accordingly, if one of the proxy busses has a different number for the congestion component of its LBMP, there is another congestion related cause. If a ramp constraint for the NYCA is binding, the software will look at all four proxies to solve for that constraint. In this way, a transaction on one interface will be affected by transactions on the other three interfaces.

What does it mean when MWs are listed on my Gen bid under 'Scheduled Oper Capacity Reserve MWs'?

These MWs are the result of FRED - Forecast Required Energy for Dispatch. Forecast Required Energy for Dispatch (FRED) represents resources needed to serve

internal load, which did not bid in Day-Ahead, but which is nevertheless forecast by the NYISO. Thus, "FRED" is additional expected energy needed to meet the NYISO forecasted load that is in excess of the sum total of Day-Ahead load bids. For each hour, FRED should at least equal the NYISO NYCA Load Forecast minus the Sum of Day-Ahead Internal Load Bids and Bilateral Schedules with Internal Sinks.

FRED Eligibility - All suppliers bidding into the Day-Ahead and Real-Time Energy

Markets automatically qualify as potential suppliers of FRED (Day-Ahead or

supplemental FRED respectively).

FRED Selection - Day-Ahead FRED will be selected by SCUC. Non-committed

suppliers selected to provide FRED will be notified via the MIS if they are anticipated to start-up during the commitment day but do not receive a forward contract to start-up.

FRED Payment Rules - As with other suppliers, once a FRED supplier is started, it: (1)will be guaranteed recovery of its start-up bid price and minimum generation bid price bid through the remainder of the dispatch day; and (2) may set and will be paid the Real-Time Energy LBMP for actual energy supplied. No availability will be paid for FRED. Furthermore, as is the case for all Real-Time energy suppliers including FRED, an applicable NYISO penalty will be assessed to FRED suppliers for failure to provide energy.

What is Virtual Bidding and is it open to everyone?

Virtual Bidding is the submission of bids for the financial purchase or sale of energy in the NYISO administered energy markets. Virtual Bidding applies only to the day ahead markets and is open to all qualified NYISO customers.

For more information please see technical bulletin #74 #81 and #82.

What is the smallest amount of curtailable load that can be bid?

The minimum amount of curtailable load that can be bid is 1MW, in 1MW increments. A Load Serving Entity (LSE) can aggregate less than 1MW of curtailable load together so that the total is 1MW or greater.

Why is the Security Constrained Dispatch (SCD) not dispatching my generator to its economic base point?

One possibility is that base loaded low cost generators can be backed down because of the block loading of Gas Turbines (GTs). In order to meet the load requirement quickly GTs may be called upon. However GTs are quick start generators and come in increments of blocks of MW. These blocks may exceed the need and therefore require that other unit be back down to match supply with the load.

Please explain how Security Constrained Dispatch (SCD) can move a generator from one interval to the next at a rate that exceeds the generators response rate.

SCD will move the generator for the next interval starting from the previous basepoint, or where the generator is actually operating. The starting point for SCD could be the prior SCD basepoint or the actual generation whichever is lower when SCD is trying to reduce generation output. If the actual generation is less than the previous SCD basepoint then the different between the prior and the new SCD basepoint may appear to be greater than the response rate of the unit.

Some time ago ECA-A and ECA-B were automated. Where is the automation process documented and could you explain the process as well?

The ECA-A and ECA-B were automated effective December 18, 2001. The automation deals with multiple ISO systems. The automation is consistent with the ECA-A and ECA-B documentation under OASIS/ECA and the FRS used to implement ECA-A and ECA-B. The original ECA’s can be found at:

ECA

The details of the End-State ECA automation were included in a Software Release Notification on December 7, 2001. The details are listed below.

Day-Ahead Settlements

Differences between an LBMP transaction’s Day-Ahead bids and schedules and Hour-Ahead schedules will settle with the BME-determined external LBMP if the corresponding external interface or Desired Net Interchange is binding. If the external interface or Desired Net Interchange is not binding, the SCD-determined LBMP will be used. Hour-Ahead Billing

Hour-Ahead originated LBMP transactions scheduled by BME will settle with the BME-determined external LBMP if the corresponding external interface or Desired Net Interchange is binding or the SCD-determined external LBMP if it is not binding.

Failed Transactions

Export transactions that fail the Hour-Ahead checkout process or are curtailed by the neighboring control areas will settle their energy charges or transmission usage charges with the lower of the BME-determined or SCD-determined external LBMP.

Curtailment Settlement

For NYISO directed curtailments; transactions will settle the resulting schedule differences for energy charges or transmission usage charges with the BME-determined external LBMP. Import transactions will receive a supplemental payment equal to the difference between (a) BME-determined external LBMP and (b) BME-bid price, subject to a lower limit of zero.

PLANNING

What is a capability period?

A Capability Period is a six-month time frame established by the Operating Committee of NYISO to facilitate the TCC and Installed Capacity Markets. It also serves as the standard testing periods for maximum generation output. TCC and ICAP are also bought and sold based on these six month procurement periods. There are two capability periods each year. A Summer Capability Period and a Winter Capability Period which together are called a "Capability Year".

· Summer Capability Period - May 1 through October 31 · Winter Capability Period - November 1 through April 30

What is On-Peak and Off-Peak period?

On-Peak is the hours between 7am and 11pm inclusive, prevailing Eastern Time, Monday through Friday, except for NERC -defined holidays.

Off-Peak period is the hours between 11pm and 7am, prevailing Eastern Time, Monday through Friday, and all day Saturday and Sunday, and NERC - defined holidays.

Explain the Difference between ICAP and UCAP?

ICAP (Installed Capacity) represents generating capacity that is physically on the ground and has a defined value determined by a valid DMNC test or other approved evaluation method. Example - a generating unit with a face value of 100 MWs undergoes a DMNC test. According to the test results the unit can only produce 98 MWs. The NYISO will rate this unit at 98 MWs for ICAP purposes. UCAP (Unforced Capacity) represents the amount of ICAP that is actually available at any given time. It also is the unit used for buying and selling ICAP. UCAP is the percentage of ICAP available after a unit's forced outage rate is calculated. Each month the generating unit submits data that profiles the unit's performance. If a unit was unavailable due to a forced outage (ex: pump failure) for 10% of the hours in a month, the forced outage rate would be 10% and therefore, only 90% of the ICAP would be available. A rolling 12 month average of the monthly forced outage rate is used to determine the amount of ICAP that can be sold in units of UCAP. If the 12 month forced outage rate is 10%, the above unit would only be allowed to sell 88.2 MWs of UCAP in the next monthly ICAP auction. This value may vary on a monthly basis.

Where can I find the UCAP auction deadlines and issues?

Information regarding UCAP can be found in the ICAP Stage 2 Manual, Attachment A on the NYISO web.

ICAP Manuals

What is EDRP and how does it fit into the NYISO operations with SRE?

EDRP is NYISO's Emergency Demand Response Program. As the name states, this is a program designed to reduce load during a declared NYISO emergency, thereby helping to maintain the reliability of the bulk power system. Participation by NYISO customers is voluntary and no penalties are assessed if a customer is not able to respond to the NYISO's call to reduce load.

Customers must register for this program and meet minimum qualifications to be accepted into the program. For example, customers must be able to disconnect from the distribution network or reduce load by a measurable and verifiable amount. They must reduce a minimum of 100 kV/Zone and be able to respond within 2 hours of the notice from the NYISO.

How do the participants benefit? For an emergency lasting 4 or more hours, participants will receive the higher of $500/MWh or the Real-Time Zonal LBMP during the emergency state. For an emergency lasting less than 4 hours, participants will be paid the prices above for a minimum of 2 hours up to the duration of the event (4 hours).

SRE's, Supplemental Resource Evaluation, are called whenever there are not enough generation bids provided to serve the forecasted load or if system conditions change that would cause the original dispatch to be insufficient to serve load. This does not necessarily translate to an emergency state. SRE's may be called for the DAM or HAM market. Bids are selected based upon the lowest cost solution and payments are made via the calculated LBMP's at the appropriate gen bus.

In an emergency state an SRE may be called as well as a call to participants in the EDRP program.

I am a NYCA ICAP supplier. What do I do if I am not able to generate due to a transmission system outage?

As a NYCA ICAP supplier, the Market Participant has the obligation to bid the Installed Capacity Equivalent (ICE) of the UCAP (Unforced Capacity) sold into the Day-Ahead Market 24/7. If a transmission outage is scheduled for a future date that will prevent the generator from delivering power to the transmission system, the unit should NOT submit Day-Ahead bids for the hours of the known transmission outage. During this time the unit will be considered in a ‘reserve shutdown’ state. Technical Bulletin #44 describes the responsibility of the generator to notify both the TO and the NYISO. In addition, the Market Monitoring Unit must also be contacted. The current procedure for contacting Market Monitoring is under review. The recommended advice is to contact your Customer Relations Representative or the Help Desk at 518-356-6060. When submitting the GADS data, use the appropriate code for the reserve shutdown status for the hours in question. Also, include a brief description of the reason for not submitting bids. This will insure that the unit’s EFOR’d (Forced Outage Rate) will be calculated appropriately.

I am a NYCA ICAP supplier. What happens if I was not selected in the Day-Ahead Market and I subsequently sold my capacity to an external control area in real time, but now, due to system conditions, my capacity is being recalled?

All Unforced Capacity that is not out of service, or scheduled to serve the Internal

NYCA Load in the Day-Ahead Market may be scheduled to supply energy for use in

external transactions provided, however, that such external transactions shall be subject to curtailment within the hour, consistent with ISO Procedures. Such curtailment shall not exceed the Installed Capacity Equivalent committed to the NYCA.

If an Installed Capacity Supplier’s Exports are Curtailed in-hour to resolve a New York reserves shortage, the Transmission Customer scheduling such Exports shall be paid, for the remainder of the hour, the higher of the Real-Time LBMP at the New York proxy bus associated with the Exports, or the real-time price at the relevant proxy bus used by the External Control Area for Transactions with New York.

For more info, please refer to section 5.12.10 Curtailment of External Transactions In-Hour in the Market Services Tariff.

I am having some difficulty having Multi-Block Transactions scheduled as I intended?

There are four main rules to keep in mind when bidding a Multi-Hour Block Transaction (MHBT):

1) The MWs must be the same for all hours of the transaction

2) The bid price must be the same for all hours of the transaction

3) When specifying the min runtime of your transaction, the hours must be consecutive.

4) When a transaction is bid up to and including HB23, the min runtime will be ignored by SCUC.

For example, assume that a transaction is bid with a min runtime of 24 hours i.e. HB00 through HB23. If SCUC determines the transaction is NOT economic for start hour HB00, the transaction will be rejected. Since the min runtime will take the transaction past midnight, it is ignored. Therefore, SCUC will evaluate it again for starting hour HB01, but with a runtime of 23 hours. Let’s assume that the process continues and the transaction is not economic until it is evaluated for starting hour HB20. SCUC will then schedule the transaction for HB20-HB23 or 4 hours.

If the transaction must run the min time specified or not run at all, then do not specify a bid for HB23. Assume that a transaction is bid for HB00 through HB22 with a min runtime of 18 hours. SCUC will evaluate for starting hour HB00 and schedule based on economics. If HB00 is not economic, SCUC will evaluate it for starting hour HB01, then HB02, HB03, HB04, and HB05. However, if the transaction has not been started when the evaluation for HB06 begins, the transaction will be rejected for the remainder of the day. The min runtime specified is 18 hours and the last hour bid is HB22. Starting at HB06 and running through HB22 is only 17 hours.

In this case the Market Participant is saying that the starting hour is not important. What is important is that the transaction must run for 18 hours.

My Daily and or Hourly billing statements are not posted on the web site. Where can I find them?

When Customer Settlements reruns the Daily/Hourly billing statements, sometimes not all the days in a month are run. As a result, if the day in question is not run, it will not be posted to the web site in the main listing. The current version can still be found in the Zip file at the bottom of the page.

GENERATION

Changes were made to both SCD and BME in an effort to have prices calculated by each program converge. In addition, SCD may now dispatch generation more effectively in NYC by 'seeing' the 138 KV transmission lines. Both of these changes should result in less OOM calls in NYC, yet OOM calls are still being made.

While the changes made have allowed SCD to more accurately dispatch generation in NYC, there are still differences between BME and SCD that may result in OOM generation calls. One of the primary reasons is that SCD may not start a 30 minute GT while BME can. If it is determined in-hour that a 30 minute GT needs to be started, the unit will be dispatched OOM until the unit can be picked up in the next BME evaluation. Sometimes BME will turn the unit off even though it is still needed due the remaining differences with SCD. As a result, the unit will be kept on OOM until it is no longer needed or until the BME evaluation will keep it on. This issue is being investigated to further reduce the OOM calls for 30 minute GTs. Since the software has been activated, the number of OOMs has been reduced significantly.

My generator has a schedule through the remaining hours of today’s Day Ahead Market (DAM) and a minimum down time of 24 hours. How did it receive a schedule in tomorrow’s DAM that starts the unit hour beginning 18?

When Security Constrained Unit Commitment (SCUC) initializes at 5:00 AM, it must assume what the unit’s status will be (off or on) at the very beginning of the next day’s evaluation period. If the unit is not running at the time SCUC initializes, SCUC assumes the unit will be offline, even though the unit has a DAM accepted schedule through the end of today. Once SCUC assumes that the unit if off at the beginning of the evaluation period, it is not capable of knowing how long the unit has been off.

How do I implement direct communication of my generator?

Direct Generator Communications (DGC) is now available to communicate generation control commands directly from the NYISO control computer system to the unit, plant, or the control computer system of a generation owner or operator without passing the signals through the control computer system of a Transmission Owner (as is now done). This capability is offered to all generation owners and operators. The DGC scheme will not replace the existing telemetry between generators and Transmission Owners. For information to obtain DGC please click on the site link below.

Direct Generator Communications

If a Market Participant submits a Supplemental Resource Evaluation (SRE) bid after the Day Ahead Market closes can it still be accepted by the NYISO?

Yes, the bids would be accepted. Bids submitted at the request of NYISO would be evaluated with the remaining unexpired/unaccepted day ahead bids.

Can you enter the same value in the field for Minimum Generation (MinGen) (MW) and the field for Upper Operating Limit (UOL)?

To bid your MinGen (MW) the same value as your UOL you must select the Off Dispatch field and cannot enter any values in the bid curve fields. To submit an energy curve/block bid you must select the On dispatch field, enter values in the bid curve fields, and your UOL and MinGen (MW) must be different values. Please refer to Technical Bulletin #12 for further information.

What is a ‘phantom bid’ for a PURPA unit?

The MIS system will automatically generate a ‘phantom’ HAM bid for the unit if the unit is running and no bids have been entered. The generated bid will reflect where the unit is operating. If a bid was entered and the unit is operating off its bid curve the ‘phantom’ bid would be generated to reflect where the unit is. This is the case for PURPA 2 units. If the unit loses its’ PURPA classification, there ‘phantom’ bids will no longer be generated automatically.

What is the current procedure defined for scheduling PARS and can an example be provided?

The current procedure for scheduling PARs in the DAM is described in the Day-Ahead Manual. The process uses the previous "like" day's historical hourly average. Since this process is being run at 5:00 am for the next day, the actual flows are two days behind (i.e. on Tuesday at 5:00 am, Wednesday's DAM is being run and the last 24 hours of PAR flow is from Monday).

The process for scheduling PARS was discussed at the Operating Committee, and the associated presentation material from this meeting is posted on the NYISO website under "Services, Board of Directors..., Operating Committee, July 25, 2002, "Presentation - NYISO PAR Scheduling", or use the following link:

PAR

PAR Schedules are initially based on the prior like day's schedule, as previously described. Then patterns are applied to filter out transient operational flows. The specific pattern utilized was developed based on historical PAR settings. Additionally, schedules are adjusted for any forecasted network outages.

Finally, the Linden Goethals PAR schedule is modified in accordance with the anticipated operation of the Con-Ed – PSEG Wheeling Agreement (presently under negotiation at FERC). This effectively results in the Linden Goethals PAR schedule being capped at 200 MW into NY. The Goethals PAR schedule is limited to 200 MWs flow into New York due to the uncertainty of the actual Goethals PAR loadings and the impact on Staten Island generation.

A spreadsheet showing the methodology used to arrive at a Day-Ahead PAR schedule is provided for your information.

PAR Spreadsheet I

PAR Spreadsheet II

SETTLEMENTS

What is DSS ADD?

DSS ADD (Decision Support System, Alternate Data Delivery) is a new data interface being made available to Market Participants that will publish the existing hourly and daily customer statement files (advisories), and will allow Market Participants to obtain these reports in a more efficient automated data exchange process. DSS ADD is designed to replace the existing static web posting system for both the hourly and daily advisories, and the dynamic MIS upload/download process for the daily advisory.

NOTE: This change is only to the delivery mechanism by which these files are made available to Market Participants, and does not affect existing settlement advisory file layouts or data content. It also does not affect other MIS upload/download data templates.

Why is the current system being replaced?

There are several reasons why DSS ADD offers NYISO Market Participants additional value. DSS ADD is:

Part of the NYISO goal to centralize all customer settlements data and reports, allowing Market Participants to obtain all of their customer settlement data and reports from a single application.

Simplifying the current NYISO customer settlements data versioning scheme, thereby eliminating existing Consolidated Invoice to advisory files version mapping issues.

Providing a foundation for future data automation enhancements, including custom report layouts and a variety of different file formats (i.e. XML).

The DSS ADD Timeline includes the following remaining milestones:

10/01/2004 – Halt existing Static & Dynamic Advisory processes - DSS ADD Official Cutover. Halt processing and posting daily and hourly files to the CSS and BAS FTP site. Eliminate the dynamic MIS upload/download daily settlement statement template. Remove access to daily settlement statement files through the NYISO Marketplace URL.

October 8, 2004 – Remove static website & begin distributing CDs containing historical files

Technical Bulletin 127, “Accessing Customer Statement Files through the Decision Support System (DSS)” has much more information on ADD. It may be found at:

Tech Bulletin 127

The Attachment to this TB has information on using automated systems to pull down your data:

Tech Bulletin 127 Attachment 1

What is the DSS?

The DSS is a suite of tools that provides flexible access to the data stored in the

NYISO Data Warehouse. The Data Warehouse contains data that is extracted,

translated, and loaded (ETL) from many existing NYISO applications. In its initial

release, the DSS supplies a customer settlements Data Mart. The system provides:

• A single source for NYISO-related financial (settlement & invoicing) data currently stored in BAS, MIS, and Consolidated Invoices

• Toolsets to allow users to perform flexible value-added analysis

• Security architecture: users can only see their own data. Access to data is dependent on user log-in. The DSS page on the NYISO web site may be found at:

Market Access

What is the Customer Settlements Data Mart?

Customer Settlements is the first Data Mart introduced as part of the DSS.

The Data Mart provides users with access to the data in a searchable format that

can be viewed at detailed levels by a variety of parameters in a user-friendly manner.

Additionally, the DSS allows the data to be accessed in one location instead of multiple systems. For example, users are able to drill-down from the consolidated invoice to the 5-minute interval-level data.

Will DSS allow Users to query the database directly; ie., can I pass DSS a parameter and have it return the data similar to a query written against MIS?

Access to the DSS is currently limited to Business Objects (BO), so Users will not have direct access to the DSS database. However, there are 71 Corporate Reports (see below) we have built, and there is a fully functional environment that will allow you to build endless ad-hoc queries, with capabilities beyond that of the MIS upload/download process.

What is in the DSS User's Guide and where can I find it?

This DSS User’s Guide is intended for the use of registered NYISO Market

Participants desiring to execute the following functions, among others:

• Power Suppliers: to view, analyze, or download balancing energy and Real-Time (RT) Bid Production Cost Guarantee (BPCG) settlements

• Transaction Customers (TCs): to view, analyze, or download Locational Based Marginal Pricing (LBMP), replacement balancing energy, real time bid production cost guarantee, and Transmission Usage Charge (TUC) settlements

• Load Serving Entities (LSEs): to view, analyze, or download balancing energy settlements

The DSS User’s Guide may be found at:

Market Access

What types of reports are available?

There are currently 71 Corporate documents under the NYISO DSS Page. Corporate documents are documents that have been published and made accessible to users within your corporation or organization. There are 9 categories of Corporate documents:

• Transmission Congestion Contract Settlement Detail Reports (1)

• Transmission Owner Settlement Detail Reports (1)

• Administrative Reports (2)

• Power Supplier Settlement Detail Reports (25)

• Load Serving Entity Settlement Detail Reports (8)

• Virtual Market Settlement Detail Reports (2)

• Settlement Summary Reports (12)

• Transaction Customer Settlement Detail Reports (14)

• DADRP Settlement Detail Reports (6)

DSS Prerequisite Knowledge

• Users should understand the major components of the NYISO settlement process

• Users should be able to use settlement and market reports

• Users should be able to comfortably identify major settlement components.

• Users must be registered Market Participants in the NYISO-administered markets.

DSS Minimum Technical and Browser Requirements

• 1 GB of disk space

• 256k of RAM

• Microsoft Explorer Browser

• Business Objects (see section 7.1.2)

How do I register for access to the NYISO DSS?

Request an account by clicking the 'Account Request' link at:p>

Market Access

How can Market Participants learn more about the DSS?

By taking part in the NYISO DSS Task Force, the link for which may be found at:

Business Issues Committees

under the BIC (Business Issues Committee), Billing and Accounting Working Group.

How do market participants know what Transmission Congestion Contracts (TCCs) are available in the TCC auction, if the offers to buy and sell Transmission Congestion Contracts (TCC’s) are due on the same day?

Once the bids to buy and offers to sell are submitted into the NYISO, they are analyzed via a power flow model. The simultaneous analysis of the offers and bids submitted into the auction simulation, which considers outstanding TCCs as actual power flow, produces new power flows for TCC holders. Therefore there is no need to publicly post what will be offered to sell, because the model analyzes the system in such a way to create paths. An example would be if a TCC was bid from zone J to zone A would reduce the cause of congestion in the model and increase the number of TCCs flowing from zone A to zone J.

Which Transaction charges do I have to pay for imports and exports?

There are three Transaction Charges

TUC's - Transmission Usage Charge (Congestion and Losses) This is a market based charge which includes the congestion and marginal loss component charges.

TSC's - Transmission Service Charge: This is an embedded cost charge which is bases on the Transmission District in which load being served is located.

NTAC - NYPA Transmission Adjustment Charge It's an embedded cost charge to recover NYPA Transmission Revenue Requirement not recovered through TSC.

Transaction Type	LBMPs	TUCs	TSCs	NTAC
Import Transaction	$$	X	X	X
Import Bilateral Transaction	N/A	Trans Owner $	Load $	Load $
Export Bilateral Transaction	N/A	Trans Owner $	Trans Owner $	Trans Owner $
Export Transaction (External Load Bid)	Trans Owner $	Build into the LBMP	Trans Owner $	Trans Owner $
Internal Bilateral Transaction	N/A	Trans Owner $	Load $	Load $
X =  Does not Pay $ =   Pays $$ = Receives

What is a Bid Production Cost Guarantee (BPCG)?

BPCG is the way that the NYISO guarantees suppliers that if a unit is committed, the unit will not incur a net loss, provided the unit's operation and schedule meets the qualifying criteria. BPCG is comprised of the Energy Bid, Minimum Generation cost, and start-up cost less the net Ancillary Services Margin. The BPCG payment made to suppliers is a daily settlement. In order to receive a BPCG payment, the sum of all hourly loss/profit values must result in a net loss.

Is there a bid cost guarantee for transactions?

Import transactions are eligible for a Bid Production Cost Guarantee (BPCG) in the event the LBMP clearing price settles below the accepted bid price. To determine if a BPCG payment is due, a calculation will be performed for each hour of the transaction to determine the hourly loss/profit which represents the daily Real Time BPCG settlement. In order to receive a Real Time BPCG the net amount of all hours over a 24hr day must net to a positive value. If the net total is negative or zero, no BPCG payment will be rendered.

During times of tight supply, reserve prices have spiked even though it appears that enough reserves were available?

These price spikes are the result of the different mechanisms used by SCUC, BME and SCD to schedule reserves and to calculate prices. For example, real time operations counts export transactions as recallable to provide 30 minute operating reserve, however, the DAM and HAM are constrained to only use internal suppliers for 30 minute reserve. As a result, BME selects units and calculates the reserve price with different assumptions of reserve availability. Another factor that results in higher reserve prices is the fact that BME does not 'see' all the units with reserve availability. These 'latent' reserves cannot be scheduled by BME, but SCD will dispatch reserves based upon ramp rate independent of reserve bids. This mismatch results in incorrect price signals. At the December 13, 2001 BIC meeting, a proposal was presented by the NYISO and passed by the Market Participants for the NYISO to implement changes to SCUC, BME, and SCD that will provide as consistent treatment as possible for operating reserves. Specifically, 5 areas are to be addressed:

1) Count export transactions as reserves in both DAM and HAM

2) Model latent reserves such that they will be seen by BME

3) Model downward regulation in both SCUC and BME

4) Model independent ramp rate constraints for reserve and regulation

5) Ensure reserve requirement set in BME matches that set in SCD

With the implementation of these changes, the price signals for operating reserves from SCUC, BME, and SCD should not deviate a great deal and price spikes should be avoided. A longer range project (summer 2003) it scheduled to replace BME and SCD with RTS (Real Time Scheduling) and RTD (Real Time Dispatch).

What is uplift and how is it allocated?

Uplift is the increased cost of generation beyond what has been scheduled by SCUC and BME. The most common cause is the dispatching of uneconomic units to provide locational security or NYISO security. The backing down of a scheduled generating unit also creates uplift as that unit is entitled to receive a Bid Production Cost Guarantee (BPCG). In addition, a generating unit may be OOM (Out of Merit) during a DMNC test resulting in uplift. [Note: The OOM designation is given to a generating unit that for specific reasons is allowed to generate either above or below its' schedule without incurring penalties.] Locational security is usually activated in the NYC area. Due to transmission constraints, it is not always possible to import the most economic energy across the various interfaces. The local TO (Transmission Owner) is responsible for notifying the NYISO of a locational security requirement. NYISO dispatchers will decide which unit or units will be set OOM to solve for the constraint. As a result, selected units within the locality will be designated as OOM and dispatched where needed. These units will not set LBMP, but the increased costs will be passed on to all LSE's WITHIN the locality based upon their share of the load. Should the circumstances call for a unit outside the locality to be backed down as part of the locational security, that unit will receive a BPCG. Those costs will be considered NYISO security and passed on to all LSEs within the state as Statewide Uplift.

Statewide security will be called by the NYISO. Due to a generator trip, line outage or other system event, it may be necessary to dispatch scheduled generators either above or below their schedules or even dispatch new units. These will usually increase the statewide generating costs and will result in uplift charges. These charges will be passed on to the LSE's based upon their ratio share of the load.

Uplift is a significant cost to the LSE's in the NYCA. The NYISO, with input from the Market Participants, is investigating various ways to reduce the OOM requests. One such method to be implemented is for the NYISO to model the 138 kV transmission lines in NYC. With the 138kV transmission system modeled, generation will more accurately be scheduled and dispatched initially, thereby, decreasing the number of units called OOM. This will result in lower uplift charges.

BILLING

How are Transmission Service Charges (TSC) calculated? Will a transmission customer be charged the product of the hourly TSC rate and the number of hours the power is scheduled or by an actual meter read?

The Transmission Service Charge (TSC) rate that is billed to the Market Participant is the product of the TSC rate and the actual energy withdrawal, excluding wheel throughs and exports. In those cases the transmission service charges are applied to the scheduled energy quantities. Imports into the LBMP market are not charged a TSC. It should be noted that the TSC rate for each Transmission Owner is unique. These rates are posted as Transmission Service Charges on the OASIS page under the header Operational Information, or use the link: Market Data

Where on the NYISO billing statement will the Transmission Service Charges (TSC) be calculated?

The NYISO does not charge customers for Transmission Services. Those charges are collected directly by the Transmission Owner (TO), so monthly invoices and billing statements do not include a TSC. However, the NYISO does account for export transmission MW-hr quantities and provides an advisory TSC rates to enable a customer to calculate the transmission service charge. The appropriate Transmission Owner (TO) will send each transmission customer a monthly bill based on that customer’s usage.

TRANSACTIONS

Transaction E-Tagging Basics: (More detailed information is available in Technical Bulletin 27 at Tech Bulletins

or, use the NYISO on-line training resources at

Market Training Online Resources

What is an E-Tag?

A collection of information in the electronic request for an energy schedule and subsequent responses utilized in the electronic Transaction Information System (TIS) implemented by NERC. An E-tag is a document describing a physical interchange transaction and its associated participants. E-tags help security coordinators and control areas assess reliability impacts and curtail transactions when necessary. A Market Participant enters the TagID as part of the transaction bid in the NYISO MIS.

As someone who does not bid directly in NYISO, I am not familiar with term “MIS”. What does that mean?

NYISO’s Market Information System (MIS) is the main application used by Market Participants to submit all NYISO bids and transactions, including internal and external. It is also the system where NYISO schedules are posted and viewed by Market Participants.

What do the all the E-Tagging terms mean?

TagID – An identifier for the E-Tag. TagID is a 4-part code entered into MIS to reference the corresponding E-Tag in a Tagging authority. The TagID is formed by combining a GCA code, a PSE code, an E-Tag Code, and a LCA code.

GCA: Generation Control Area

LCA: Load Control Area

PSE: Purchase Selling Entity

Example TagID:

NYIS _ ABCD1234567_ PJM

GCA (SCA) code PSE code E-Tag Code LCA (RCA) code

Purchase Selling Entity (PSE) – An entity that is eligible to purchase or sell energy or capacity and reserve transmission services. The PSE is the entity that is generally responsible for originating an E-Tag. Note that multiple PSE's can exist for a particular organization. MP’s should communicate all their registered PSE values to NYISO prior to use.

Financially Responsible Party (FRP) – the organization which is financially responsible for NYISO transaction bids in MIS. The FRP is attached to an MIS transaction (and all hourly bids within that transaction). It is usually the same organization that originally created the MIS transaction.

Balancing Market Evaluation (BME) – the NYISO scheduling process that creates

HAM schedules and posts the HAM scheduling results

WebTag – A web based front end for creating E-Tags, provided by OATI.

WebData – A locally (or remotely) hosted database server that communicates all the

E-Tagging activity back to OATI’s central servers over a network. This is meant only for programmatic use.

Curtailment – In the context of OATI, this is a specific type of action that can be taken on E-Tags. It can be initiated by control areas but not by E-Tag authors, (market participants). As per OATI rules, Curtailments go through a simplified approval process (only the GCA and LCA must approve). NYISO will utilize Curtailments in OATI in order to synchronize the E-Tag with MIS schedule changes. Additionally, the E-Tag must be in the Implemented state in order for the Curtailment to take effect (this is an OATI rule).

Passive Approval – Approval state assigned by OATI after the time window allowed by OATI for active approval or denial of an E-Tag has expired. Note that this window is determined by OATI and is relative to the time at which the E-Tag was submitted, usually 20 minutes if the E-Tag was submitted on the day of flow or 2 hours if submitted days ahead of time. Passive Approval will occur for all E-Tags that aren’t explicitly approved or denied (for example, if the request is put in Study status) unless the E-Tag was submitted Late (within 20 minutes of the hour of flow). Only in that case, Passive Denial will be assigned

The PSE in MIS is not a participant in the ETag.

This rule enforces that NYISO will only Approve an E-Tag if the PSE value associated with the Financially Responsible Party (FRP) of the NYISO Transaction is in fact one of the E-Tag participants.

What does the NYISO MIS do with E-tags?

Our new system for electronically processing E-Tags was instituted in early spring, 2004. Upon receiving an E-Tag request, the NYISO MIS will compare the tag to the associated Transaction bid; one of the following statuses will be assigned to the E-Tag Request:

APPROVE- A status of approve is assigned to the E-Tag if it is received before the hourly checkout provided the energy profile of the E-Tag closely matches the Transaction in the MIS. (See the links above for recent changes in accommodating transmission losses).

STUDY – This indicates that the energy profiles of the E-Tag and the Transactions are not close after accounting for losses. The MP should either modify the E-Tag or the Transaction. Any E-Tags which are in the STUDY status at the end of the approval window will be updated to Passive Approval (see above).

DENY – If the E-Tag is submitted after the hourly market close and it doesn’t closely match the Transaction’s energy profile, it will be denied by the NYISO. It will also be denied if is received after the hourly checkout of transactions with neighboring Control Areas.

This is only a high-level view of E-Tagging basics; the reader is strongly urged to consult the links referred to above.

What should I do when a scheduled transaction gets derated?

The NYISO will derate a transaction i.e, reduce the MW amount of the transaction before it is evaluated by Balancing Market Evaluator (BME), to maintain the reliable operation of the New York control area. Quite often the NYISO will derate a transaction based on knowledge provided by a neighboring control area that even if the transaction is accepted in the NYISO Locational Based Marginal Pricing (LBMP) market, the transaction will not flow due to reasons external to New York. When a transaction is derated an automatically generated email is sent to the scheduler of the transaction specifying the New York Control Area (NYCA) identification number with the corresponding MW value, the time of the derate, and the reason for the derate. More detailed information about the real time interface conditions can be obtained by viewing the Operational Announcements link on the OASIS page under Operational Information. To reinstate the transaction, it is the responsibility of the market participant to have the outside Control Area’s dispatcher verbally verify to NYISO Operations that the transaction in question has an accepted schedule in both control areas, and based on system conditions should in reinstated.

Virtual Transaction bids were evaluated and based upon the strike price of the bid and the posted LBMP, the results seem to contradict the market rules that govern the acceptance or rejection of a virtual transaction. This result has been ascribed to the fact that SCUC uses load weighted zonal prices to schedule bids while the billing system uses generated weighted prices calculated from generator weighting factors. As a result, there may sometimes be a small differential between the two prices that results in virtual transactions having the opposite evaluation. What are 'generating weighting factors'?

The NYISO settlement for loads utilizes a single LBMP for each of the eleven LBMP zones. The Security Constrained Dispatch (SCD) software program that is used for the Real-Time Market has the limitation that it can only calculate LBMPs for generators. In order to calculate a zonal load LBMP from the generator LBMPs, the generation weighting factors were created. The generator weighting factors will be used in the NYISO system until SCD is replaced with RTS. The new RTS package and the current SCUC/BME programs can determine a zonal LBMP based on the load distribution not the generation. The intent of the generation weighting factors is to reflect intra-zonal congestion into the zonal LBMP. The zonal LBMP is equal to the sum of the generator's LBMP times the generator's weighting factor for all generators in that zone. For example, two generators at the same bus with the same LBMP would have the same combined contribution to the zonal LBMP if the factors were 0.10 and 0.10 or 0.15 and 0.05 or 0.20 and 0.0. It is also not necessary that all units have a weighting factor.

The factors are created for consistency between the generators location and the distribution of load. When congestion occurs internal to a zone, if there is only 10% of the total zonal load in the congested area with a higher LBMP, then the Zonal LBMP should reflect 10% of the LBMP in the congested portion and 90% in the uncongested portion of the zone. The original factors were developed using a network-reduction-equivalency process. Due to the nature of this methodology, generation at near buses can have different weighting factors.

What charges are assessed to a customer that enters into an internal bilateral transaction (from an internal generator to an internal load)?

Typical charges associated with an internal bilateral are as follows:

a. Under Transmission Customer Data, "Transactions" charges:

Billing Code

504 Hourly Day-Ahead Transmission Usage Charge

508 Hourly Real-Time TUC charges (Losses Congestion

b. Under Transmission Customer Data, Hourly "Ancillary Services" charges: Billing Code

604 NYPA Transmission Access Charge (NTAC)

606 Voltage Support Service (OATT, Rate Schedule 2)

610 Hourly Reserve Charge (OATT, Rate Schedule 5)

611 Residual Adjustment (Part of Rate Schedule 1, S, SC &D)

612 Hourly Regulation Charge (OATT, Rate Schedule 3)

613 Black Start Charge (OATT, Rate Schedule 6)

614 ISO OAT Uplift Charge (Part of Rate Schedule 1,S, SC &D)

c. Under Transmission Customer Data, LSE LBMP Energy charges:

Billing Code

409 Hourly Balancing Energy (OATT, Rate Schedule 4)

d. Under Transmission Customer Data, Daily "Ancillary Services" charges:

Billing Code

812 NYISO-wide Uplift Charge (Part of Rate Schedule 1,S, SC, &D)

Note: Generators are subject to balancing if the generator does not produce enough energy to cover their LBMP energy and Bilateral commitments. This shows up in billing code 209, Hourly Balancing Energy (OATT, Rate Schedule 4). Internal Bilateral transactions are not assessed Transmission Service Charges by the transmission owner (T.O.).

Unit XYZ was bidding into the Hour Ahead Market (HAM) hourly, and has been scheduled for 100 MWs. Based on prices, the unit suspects that it should have been base pointed much higher, to its Upper Operating Limit (UOL). Why wasn't the unit scheduled to its UOL?

Since this unit only bid into the HAM one hour ahead (at a time). BME, seeing no future hour bids, could only schedule this unit to 100 MWs because it knows it may have to ramp the unit off line if the unit does not supply future HAM bids.