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Addendum to: nyiso

Day Ahead Scheduling manual

Compiled: 3 ! 23 ! 2001

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Addendum to: NYISO Day Ahead Scheduling Manual (Compiled: 3.23.01) 2 Table of Contents

Table of Contents to: Day Ahead Scheduling Manual’s Addendum 1.0 Overview: How the NYISO Technical Bulletins Generate Manual Revisions................................................................................................................ 3 2.0 Technical Bulletins Assigned to the NYISO Day Ahead Scheduling Manual ................................................................................................................... 5 #62: Locational Based Marginal Pricing - Meaning and Myths ...................... 6 #51: Security Constrained Unit Commitment and Balancing Market

Evaluation Rules ..................................................................................... 10 #49: Multi-Pass Methodology of Security Constrained Unit Commitment .. 12 #32: Non-Firm Bilateral Transaction Selection Process.............................. 14 #13: MIS Load Modeling and LSE Responsibilities .................................... 17 #6: Load Forecasts for facilities in the Market Information System (MIS).. 18

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Addendum to: NYISO Day Ahead Scheduling Manual (Compiled: 3.23.01) 3 1.0 Overview: How the NYISO Technical Bulletins Generate Manual Revisions

1.0 Overview:

How the NYISO Technical Bulletins Generate Manual Revisions One way the NYISO Manuals can be revised is by merging a relevant Technical Bulletin into a manual. The merging process begins with:

(1) Assigning each Technical Bulletin to specific manual(s) and section(s); (2) Then, creating an addendum – a temporary holding place for the

Technical Bulletins – until the manual can be updated; and (3) Finally, incorporating the Technical Bulletins into the main body of the

manuals. Below, the merging process is described in more detail. The Technical Documents Coordinator (TDC) will assign a Technical Bulletin to be included in a specific manual or manuals. The TDC will also assign a manual section number to each Technical Bulletin, and will specify whether it will be added to an existing section, will require a section to be revised, will become a new section, and/or will eliminate a section. The TDC will then send this list to the appropriate Document Focal Persons for them to review and comment on. After reaching agreement with the DFP(s), the TDC will produce an addendum for a manual to include Technical Bulletins that have been assigned to that manual. The addendum will be a temporary holding place for Technical Bulletins related to the same subject until the manual can be fully revised. Technical Bulletins in an addendum will be labeled with intended section numbers and sorted in the order of these specified manual section numbers. The electronic file for a manual's addendum will be separate from the file for the manual itself so that Market Participants and NYISO Staff can download, save and print the addendum separately (and if the addendum is updated due to new or revised Technical Bulletins, it will not force a simultaneous update of the manual's file). After a Technical Bulletin has been included in a manual addendum, the TDC will also arrange to have the manual title and associated section number added to the individual Technical Bulletin which will continue to remain on the NYISO web-site separately. The TDC will periodically update each manual by moving Technical Bulletins from their addendum into the body of the manual, starting with manuals that have the largest number of tech bulletins to be added. The appropriate Document Focal Person, or another assigned person, may need to help with these revisions, and the draft revisions will be sent to the Document Focal Persons for review and comment. After incorporating agreed upon changes, the TDC or Committee Liaison will have the revised manual placed on the agenda for the next meeting of the appropriate committee(s). The committee will vote to approve, reject or approve

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Addendum to: NYISO Day Ahead Scheduling Manual (Compiled: 3.23.01) 4 1.0 Overview: How the NYISO Technical Bulletins Generate Manual Revisions

with changes to the revised manual. The TDC and/or DFP will attend the committee meeting. If the manual is approved with changes, the TDC and/or DFP will oversee the revision of the manual to reflect those changes. A list of the approved changes and their dates of approval will be compiled into a Revision History Sheet. This sheet will be included in the new manual after the Table of Contents. Once a Technical Bulletin has been updated into the main body of a manual, the individual Technical Bulletin will continue to remain separately on the NYISO web site for an additional three months -- at which time it will then be retired. The Technical Documents Coordinator will keep a status record on each Technical Bulletin as follows: Not Yet - not yet assigned to a manual Assigned - assigned to Manual "X"; Section "Y" Addendum - assigned to addendum of Manual "X" Merged - moved from addendum and merged into revised body of Manual "X", Section "Y" Retired - retired from Technical Bulletin web site (three months after merger proposal).

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Addendum to: NYISO Day Ahead Scheduling Manual (Compiled: 3.23.01) 5 2.0: Technical Bulletins

2.0 Technical Bulletins Listed below are the specific Technical Bulletins assigned to the NYISO Day-Ahead Scheduling Manual.

Legend: Technical Bulletin #; Technical Bulletin Title; Original or Revised Date; Designated Manual; Proposed Manual Section No. (Revised, New and/or Eliminated Section No.)

• #62: Locational Based Marginal Pricing - Meaning and Myths

(09/20/00) - Day-Ahead Manual (Add to Sect. 2.3.4)

• #51: Security Constrained Unit Commitment and Balancing Market Evaluation Rules (05/31/2000) - Separate “SCUC” from “BME”; Place “SCUC” in: Day Ahead Manual (Revise Sect. 3.2); Place “BME” in: Transmission & Dispatch Manual (Revise Sect. 4.1.2)

• #49: Multi-Pass Methodology of Security Constrained Unit

Commitment (06/16/00) - Day Ahead Manual (Revise Sect. 3.3.1)

• #32: Non-Firm Bilateral Transaction Selection Process (04/14/00) - Day Ahead Manual (Sect. 3.3.10)

• #13: MIS Load Modeling and LSE Responsibilities (09/06/99) - Day

Ahead Manual (New Sect. 6.4)

• #6: Load Forecasts for facilities in the Market Information System (MIS) (04/26/99) - Day Ahead Manual (New Sect. 6.4)

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New YorkIndependent System Operator

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Note: The purpose of this Technical Bulletin is to facilitate participation in the NYISO by communicating various NYISO concepts, techniques, and processes to Market Participants before they can be formally documented in a NYISO manual. The information contained in this bulletin is subject to change as a result of a revision to the ISO Tariffs or a subsequently filed tariff with the Federal Energy Regulatory Commission.

Addendum to: NYISO Day Ahead Scheduling Manual (Compiled: 3.23.01) 2.0 Technical Bulletin 62: Locational Based Marginal Pricing – Meaning and Myths

Technical BulletinTechnical BulletinTechnical BulletinTechnical Bulletin #62 #62 #62 #62 9/20/20009/20/20009/20/20009/20/2000 Subject: Locational Based Marginal Pricing – Meaning & Myths A Locational Based Marginal Price (LBMP) consists of an energy, congestion, and loss component relative to a reference bus. LBMPs represent the incremental value of an additional MW of energy injected at a particular location. Meaning of LBMP: In mathematical terms locational prices are calculated using the following equation:

Pi = Pref + LI Pref + Σj Σk SPjk SFjki = Energy + Losses + Congestion where,

Pi = Locational price at Bus i; Li = Marginal loss factor at Bus i; Pref = Locational price of energy at the reference bus; SPjk = Shadow price of constraint j in contingency k; and SFjki; = Shift factor for real load at Bus i on constraint j, in contingency k.

This equation separates the locational price into the price of energy at a reference bus (Pref), the cost of losses relative to the reference bus (LiPref) and the cost of congestion, also relative to the reference bus (Σj Σk SPjk SFjki). As the first term of the equation shows, the locational price of energy at the reference bus is used in calculating the LBMP for all other locations across the state. The loss and congestion components at the reference bus, by definition, are zero. At other buses, the transmission grid determines the losses and transmission constraints determine congestion values. Losses are due to the electrical resistance (otherwise, known as impedance) in transmission lines and transformers. Losses incurred are low for generation that is close to load centers compared to generation in regions furthest from the loads. If there were no constraints in New York then the congestion component would equal zero and price differentials would be due entirely to the cost of losses. Generation that is close to load centers is most valuable at these times as the losses incurred in getting the energy to the customers is very low and in some instances the incremental energy will reduce total system losses. Generation in regions furthest from the loads is worth the least as the losses incurred getting the energy to the loads are large. With no congestion, if the LBMPs were 40 $/MWh in the West and 50 $/MWh in New York City, then a New York City zone generator bid of $50 would be considered equivalent to $40 generator bid in the West zone. This would account for the $10 a megawatt cost in losses to transport the energy from the West.

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Technical Bulletin #62 (continued) Subject: Locational Based Marginal Pricing – Meaning & Myths A constraint occurs when the energy flow on a transmission line is limited due to the generation dispatch pattern or the possible re-routing of energy due to a contingency. When a constraint occurs, energy to serve the load must come from other locations that are not binding. The cost of congestion is determined by the shadow price of the constraint and the real power shift factor on the constraint to serve load. Shadow prices and shift factors are incremental shifts of costs or power for constraints caused by contingencies. The LBMPs represent the incremental value of an additional MW of energy injected at a particular location. In other words, it is the change in total cost (all 3 components) of meeting load when a free MW of energy is provided at that location. Discussion: The following zonal LBMPs show a Central East congestion pattern illustrate by the large price change between the Mohawk Valley (MHK VL) and the Capital (CAPITL) zones. In this interval, Central East is the only constraint that is binding (other interfaces could be binding but are not, and there is no way to exactly tell from the prices if they are or not). Time Stamp WEST GENESE CENTRL NORTH MHK VL CAPITL HUD VL MILLWD DUNWOD N.Y.C. LONGIL H Q NPX O H PJM8/25/00 11:42 38.68 28.32 29.84 (3.00) 6.52 344.79 265.70 263.34 263.15 268.08 268.09 (3.02) 317.10 39.93 53.03

In and of themselves, these prices tell us nothing about the identity of the marginal unit or units. What one can tell is that most likely there were at least two and potentially more than two marginal units in this interval. The marginal unit(s) could have been located in any one of the zones. A $268.08 bid in NYC could be marginal at the same time as a $344.79 bid in the Capital zone or a ($3.00) bid in the North Zone. However it is important to note that there does not have to be a $344.79 bid in the Capital zone for the price to be set that high. In this particular case there were three marginal units, one East of Central East and two West of Central East. The zonal prices above indicate that if 1 MW of generation was injected at locations in the Capital zone spread in proportion to the zonal weights, the total cost of meeting load would decrease by $344.79. The same MW of generation spread around the New York City zone would decrease the total cost of meeting load by $268.08. An injection of generation at a location electrically close to a constraint can have a big impact on the constraint. The electrical proximity of a location to a constraint is reflected in the shift factor of generation or load at that location on the constraint (SFjki). With Central East binding in this interval, locations electrically close to Central East, i.e. Capital zone locations, have the largest shift factors that help to relieve the congestion. Units in NYC have an impact on Central East but they are electrically more distant and their shift factors are correspondingly lower.

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Technical Bulletin #62 (continued) Subject: Locational Based Marginal Pricing – Meaning & Myths A MW of congestion relief provided by units East of Central East is valued by the shadow price of the constraint (SPjk) which represents the incremental value of an additional MW of transfer capability on the transmission facility. In simple terms, how much would the total cost of meeting load change if an additional MW of flow was allowed on the limiting transmission facility. If the shift factor for a unit East of Central East were 0.5 it would take 2 MW of generation at that location to relieve Central East by one MW. This is the source of the price difference between the Capital zone and New York City. The shadow price of Central East was around $500. A shift factor difference between the Capital zone and New York City of 0.16 would correspond to a price differential between the two zones of $80. The price difference between the Capital zone (344.79 $/MWh) and New York City (268.08 $/MWh) is, in deed, around $80. The high price in the Capital zone does not indicate the presence of market power. In fact this price is set by the competitive bidding of units all around the state with shift factors and shadow prices on the binding constraint transforming the marginal bids into LBMPs throughout the state. Note that the locations that push hardest on Central East are those with the lowest prices as a free MW spread around these zones does little to reduce the total cost of meeting load. In this case, the North zone in fact exacerbates Central East to the extent that total cost actually increases by $3. Myths of LBMP: Myth #1: The highest LBMP on the grid indicates the bid of the marginal unit. Once again, an injection of generation at a location electrically close to a constraint can have a big impact on the constraint. With the marginal unit in New York City, the shadow price of Central East around $500, and a shift factor difference between the Capital zone and New York City of .16 then a price differential between the two zones would be $80 - with a higher LBMP in the Capital zone and the marginal unit in New York City. Myth #2: LBMPs that are negative must be incorrect. Negative prices are the results of a few situations. First, a unit may have been dispatched marginally at a negative bid while all other units with higher bid prices were at their lower ramp limits. Units at lower ramp limits set a bound on the price such that the price at that location must be less than or equal to the bid of the incremental bid of that unit at its ramp limit. Secondly, if all units are at their lower ramp limitations then the price is set by the lowest bid of any of the units at the lower ramp limit. In other words, the LBMPs can be equal to the bids of ramp limited units if no other flexible resources are available.

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Technical Bulletin #62 (continued) Subject: Locational Based Marginal Pricing – Meaning & Myths Myth #3: Prices can not excess of the bid cap of $1000/MW. If Central East is binding and we need to dispatch a marginal unit in New York City with a bid of $1000 MW, then the incremental value of a free MW in the Capital zone is going to be worth more than $1000. Hence, in this case, the Capital zone LBMP would be greater than $1000 /MWh. Myth #4: Energy flows from low priced locations to high priced locations. Consider the congestion pattern where the Capital zone LBMP is greater than New York City LBMP. If the statement were true then energy would be flowing from NYC to the Capital zone, which we know is not true. With a single constraint we can say that the energy is flowing from the low priced side of the constraint to the high priced side of the constraint. However, with a group of zones on either side of the constraints the actual direction of the flows are determined by the location of the generators that are online and the location of the loads consuming the energy.

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Addendum to: NYISO Day Ahead Scheduling Manual (Compiled: 3.23.01) 2.0 Technical Bulletin 51: Security Constrained Unit Commitment and Balancing Market Evaluation Rules

Technical BulletinTechnical BulletinTechnical BulletinTechnical Bulletin #51 #51 #51 #51 05/31/0005/31/0005/31/0005/31/00

Subject: Security Constrained Unit Commitment and Balancing Market Evaluation Rules Security Constrained Unit Commitment (SCUC) and Balancing Market Evaluation (BME) use the same software but address different time frames. This results in some differing rules for initialization status, startup time, minimum run time and minimum down time.

Details: SCUC is a day-ahead analysis that results in the economic scheduling of generation for the 24 hours of the next day. BME studies a three-hour window and begins its evaluation 90 minutes before the first hour to be examined. Initialization Status When SCUC initializes at 5:00 a.m. for the following day, the statuses of the units that bid into the Day-Ahead Market (DAM) are based on their current operating mode at the time of initialization, with modifications. The modifications are the projected changes for the remainder of the day from the previous day’s DAM schedules. If a unit is not in the mode that SCUC expects it to be at the time of initialization, the current mode of the unit overrides the projected change. No units are considered must run in SCUC. BME honors all day-ahead commitments of internal generation resulting from SCUC, except for quick-start gas turbines. The unit statuses at the time of initialization are based on the current operating mode at the time of initialization, modified to include projected changes from the previous hour’s evaluation. Startup Time Either a startup versus downtime curve or a notification time can be provided for SCUC. If both are provided, the startup versus downtime curve overrides the notification value. SCUC posts the results for the next day’s DAM at 11:00 a.m. If a unit is down at posting time, the startup time is measured from the time of posting. The unit is recognized as unavailable until the startup notification period has elapsed.

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Addendum to: NYISO Day Ahead Scheduling Manual (Compiled: 3.23.01) 2.0 Technical Bulletin 51: Security Constrained Unit Commitment and Balancing Market Evaluation Rules

Technical Bulletin #51 (continued) Subject: Security Constrained Unit Commitment and Balancing Market Evaluation Rules If a unit is running but projected to come down after posting time, a bid for the unit in SCUC indicates that it is willing to operate. Neither a startup versus downtime curve nor a notification time value is recognized. BME ignores both startup versus downtime curves and notification times. A bid in the Hour-Ahead-Market indicates that a unit is able to operate in that hour if scheduled. Minimum Run Time In SCUC, the minimum run time is honored within the 24-hour evaluation period only; requirements across midnight are not recognized. A unit must bid appropriately to enable commitment in the next day. BME ignores minimum run time. Minimum Down Time SCUC honors the minimum down time within the 24-hour evaluation period only; requirements across midnight are not recognized. A unit must bid appropriately to preclude commitment in the next day. The minimum down time is honored at all times by BME.

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Addendum to: NYISO Day Ahead Scheduling Manual (Compiled: 3.23.01) 2.0: Technical Bulletin 49: Multi-Pass Methodology of Security Constrained Unit Commitment


Subject: Multi-Pass Methodology of Security Constrained Unit Commitment Security Constrained Unit Commitment (SCUC) creates the NYISO Day-Ahead Market by performing three commitment runs and two dispatch runs in sequence.

Details: Pass #1 – Bid Load Commitment The first pass of SCUC solves for supplying the Bid Load and securing against the normal NYISO bulk power system contingency and monitored facilities. Once this commitment run has converged, the market power mitigation evaluation is performed for the energy price caps, including a recommitment/redispatch. This commitment/dispatch is evaluated by security analysis. Additional iterations of unit commitment (with market power mitigation price caps) and security analysis are performed until convergence is again achieved. Pass #2 – Bulk Power System Forecast Load Commitment The next pass solves for supplying the forecast load. At the beginning of this pass, generator limits and commitment statuses are modified to ensure that the units selected in the bid load pass will not be decommitted or dispatched below their pass #1 value. Units selected in the bid load pass can be dispatched higher, and additional units can be committed and dispatched. This pass evaluates for capacity, and therefore uses incremental uplift costs and does not use energy costs. This second commitment supplies the forecast load and secures against the bulk power system contingencies and monitored facilities. Pass #3 – Local Reliability Rules Forecast Load Commitment The final commitment is performed in this pass as an extension of the pass #2. The program secures for the Local Reliability Rules contingency and monitored facilities. Pass #4 – Forecast Load Redispatch In pass #4, the set of generators from the final commitment is dispatched using the original energy bids. The dispatch supplies the forecast load and is limited by the bulk power system constraint set produced in the pass #2 commitment. The unit capacities (energy + 30 minute reserve + regulation) from this dispatch are used to calculate the forecast reserve for economic dispatch. The power flows are created for the transmission providers' review and the interface transfer flows to be evaluated in the non-firm transaction selector.

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Addendum to: NYISO Day Ahead Scheduling Manual (Compiled: 3.23.01) 2.0: Technical Bulletin 49: Multi-Pass Methodology of Security Constrained Unit Commitment

Technical Bulletin #49 (continued) Subject: Multi-Pass Methodology of Security Constrained Unit Commitment Pass #5 – Bid Load Redispatch: In this pass, the final dispatch is to supply the bid load and is limited by the bid constraint set produced in the pass #1 commitment. The quick start units selected in either of the forecast runs will not be dispatched. After this dispatch, the market power mitigation process is run to evaluate reserve price caps.

PASS 1 SCUC Solves for Bid Load • External Bilaterals and internal

Generators are evaluated to determine Gen Set 1.

PASS 5 SCUC Solves for Bid Load • Units in Pass 4 are dispatched to

meet bid load. • Pass 1 GTs are forced on, all other

GTs are forced off (dispatched at zero.)

• Generators dispatched in Pass 4 that are not needed in Pass 5 will be backed down to their min gen and will not be able to set LBMP but will get the Bid Production Cost Guarantee (BPCG)

• Day-Ahead Clearing Prices set.

BID LOAD

PASS 2 SCUC Solves for Forecast Load (without Local Reliability Rules (LRR)) • Gen Set 2 is determined and includes all

units in pass 1 plus additional units to meet forecast load.

PASS 3 SCUC Solves for Forecast Load and LRR • Gen Set 3 is determined and includes

units from Gen Set 2 to meet forecast load and LRR.

• Some units from Gen Set 2 may be turned off and substituted by different units to meet LRR.

PASS 4 SCUC Solves for Forecast Load and LRR • Units committed in Gen Set 3 are

dispatched. • Strike Prices set.

FORECAST LOAD

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Note: The purpose of this “Technical Bulletin” is to facilitate participation in the NYISO by communicating various NYISO concepts, techniques, and processes to Market Participants before they can be formally documented in a NYISO manual. The information contained in this bulletin is subject to change as a result of a revision to the ISO Tariffs or a subsequently filed tariff with the Federal Energy Regulatory Commission.

Addendum to: NYISO Day Ahead Scheduling Manual (Compiled: 3.23.01) 2.0 Technical Bulletin 32: Non-Firm Bilateral Transaction Selection Process

Technical BulletinTechnical BulletinTechnical BulletinTechnical Bulletin #32 #32 #32 #32 04/14/00 04/14/00 04/14/00 04/14/00

Subject: Non-Firm Bilateral Transaction Selection Process An evaluation of non-firm transactions occurs after the Day-Ahead Market (DAM) and Hour-Ahead Market (HAM) have closed. The results of these evaluations are strictly advisory, until the transactions have been confirmed by the NYISO system operator.

Details: The evaluation of non-firm transactions is based on which NERC product level (one to six) the transaction is, its bid time stamp (first in, first evaluated), the associated Congestion costs, and the system’s Available Transfer Capability. Additionally, external non-firm transactions are subject to the maximum hourly change in the NYISO interchange and must be confirmed with the neighboring control areas. Non-Firm Bilateral Transaction Bid Submission and Selection Process:

1. Non-firm transactions are submitted prior to the DAM close 2. The DAM closes 3. The Security Constrained Unit Commitment (SCUC) program is run, without considering

non-firm transactions 4. The non-firm transaction selector program is run using SCUC congestion data 5. A bid status of “Advisory Accepted” or “Advisory Rejected” is assigned to each non-firm

transaction 6. The DAM schedules and non-firm advisory schedules are posted 7. Non-firm transactions are bid into the HAM prior to its close. All valid DAM non-firm

transactions for the HAM hour being evaluated are re-evaluated, regardless of their status from the DAM evaluation

8. The HAM closes 9. The Balance Market Evaluation (BME) is run, without considering non-firm transactions

10. The non-firm transaction selector program is run using BME congestion data 11. A bid status of “Advisory Accepted”, “Bid Accepted”, or “Bid Rejected” is assigned to

each non-firm transaction 12. The HAM schedules and non-firm advisory schedules are posted 13. The external “Advisory Accepted” are sent to the IS+ interchange scheduler for

scheduling and confirmation with neighboring control areas 14. Confirmed internal non-firm transactions will be posted to the Market Information

System (MIS) with “Bid Accepted” status

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Technical Bulletin #32 (continued) Subject: Non-Firm Bilateral Transaction Selection Process

15. As schedules are agreed upon with neighboring control areas, the external non-firm transactions will be updated to the agreed upon level, and transaction status will be posted to the MIS as “Bid Accepted”

16. Non-Firm transmission will be curtailed in real time when congestion occurs and agreement with neighboring control area is reached

Non-Firm Transaction Selector Program Logic:

Non-Firm Transaction Condition Posting

Congestion is negative and ATC is available Advisory Accepted Congestion is negative and ATC is partly available Advisory Accepted* Congestion is zero and ATC is available Advisory Accepted Congestion is zero and ATC is partly available Advisory Accepted* Congestion is zero and ATC is not available Advisory Rejected Non-firm transaction’s congestion is positive Advisory Rejected * Transactions are ranked by NERC product type and then by time stamp. The partly available transaction is

prorated to remaining ATC. Example: Assumptions: The ATC of the interface is 50 MW in both directions

Non-firm transactions A,B,C,D, & E are internal bilateral transactions The Congestion Component of the LBMP is equal in both zones, implying a zero congestion cost

Zone A Zone B A B C D E

Interface

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Technical Bulletin #32 (continued) Subject: Non-Firm Bilateral Transaction Selection Process

Transaction Bid (MW) Time Stamp Priority

After DAM/HAM Evaluation

After System Operator

Confirmation

Scheduled (MW)

A 25 1 AA BA 25 B 20 2 AA BA 20 C 15 3 AA BA 5 D 10 4 AR BR 0 E 10 5 AA BA 10*

* Counter flow transaction (E) does not increase ATC. AA = Advisory Accepted AR = Advisory Rejected BA = Bid Accepted BR = Bid Rejected

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Note: The purpose of this “Technical Bulletin” is to facilitate participation in the NYISO by communicating various NYISO concepts, techniques, and processes to Market Participants before they can be formally documented in a NYISO manual. The information contained in this bulletin is subject to change as a result of a revision to the ISO Tariffs or a subsequent filed tariff with the Federal Energy Regulatory Commission.

Addendum to: NYISO Day Ahead Scheduling Manual (Compiled: 3.23.01) 2.0 Technical Bulletin 13: MIS Load Modeling and LSE Responsibilities


Subject: MIS Load Modeling and LSE Responsibilities The NYISO will model loads in the Market Information System (MIS) for Load Serving Entities (LSE) and the LSEs must accurately forecast, bid, and schedule their loads to reflect their customers.

Details: Each NYISO Customer that has load will inform the NYISO of the load and the load will be modeled in the MIS with a unique ID, a link to an LSE, and a link to one of the ISO sub-zones. These loads must be modeled 30 days in advance of taking service under the ISO. Each LSE has one associated Billing Organization. Bills and invoices are calculated for each Billing Organization and include the settlements for the associated LSE(s) and load(s). If a retail access load customer changes from one LSE to another LSE then it is the responsibility of the LSEs to coordinate the change with themselves and the Transmission Owner (TO) so that each LSE forecasts, bids, and schedules the changed load accurately. Within each sub-zone, the Transmission Owner (TO) must certify that the LSEs have met their requirements and can conduct business in that sub-zone. The ISO will ask for verification that all LSEs, with their associated loads, that are modeled in the MIS are certified by the TO. The load names specified in the NYISO MIS represent the customers that have a certain amount of load (one megawatt or greater - individual or aggregated). Individual retail customers, meters, or accounts are not tracked by the ISO. The ISO does not need to know if accounts or customers switch providers. The ISO only needs to know which providers are certified. The TO and the LSE must coordinate activities when customers switch providers to ensure that the load is not missed or double counted. The following diagram below helps explain how a load change may occur. If load c switches to LSE 4 then:

LSE 2 & 4 coordinate with the TO-LSE 1

Billing Org B receives Load c settlement LSE 4 now forecasts, bids, or schedules

Load c LSE 2 does not forecast, bid, or schedule load c

The ISO only needs to know that LSE 2 & 4 are certified by the TO. If only a partial load is switched then only that amount is coordinated between parties. If load is incorrectly bid or scheduled then, after actual metering is determined, the billing will be adjusted for loads that are off schedule (see Technical Bulletin #6).

LSE 1 (TO)

Bill Org B Bill Org A

LSE 2 LSE 3 LSE 4

a b c d e cLoads:

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Addendum to: NYISO Day Ahead Scheduling Manual (Compiled: 3.23.01) Technical Bulletin 6: Load Forecasts for Facilities in the Market Information System (MIS)

Technical Bulletin Technical Bulletin Technical Bulletin Technical Bulletin #06 4/26/99

Subject: Load Forecasts for Facilities in the Market Information System (MIS) In the Day Ahead Market (DAM), a load forecast for each Load Serving Entity’s (LSE) load should equal the sum of the Bilateral Transactions scheduled to the load, the load’s fixed MW bid, the loads’ Price Capped Loads, and the expected Real-Time Market energy required to serve the remaining load. Hourly Load Forecasts submitted in the DAM can be revised any time up to when billing calculation are performed.

Details: The load forecast predicts the level of Load at a point of withdrawal for each hour. In the Security Constrained Unit Commitment (SCUC) program, the load forecast for all the loads within a zone are summed to determine a zonal forecast which, if deemed credible, would be used in determining a unit commitment schedule. These load forecasts are also used to allocate the metered zonal load among the LSEs for billing calculations. Since the forecasts are used in billing calculations, they can be revised after the real-time dispatch to better approximate meter measurements up to noon the next day when the billing programs are run. Final billing adjustments will be made months later after final meter reading has been reported. If your organization has utilized two loads to schedule energy for your total sub-zonal load but have submitted the load forecast for both loads in only one of the loads then the energy proportioned to each load will not coincide with your Fixed Bids and Bilaterals. If you have scheduled a bilateral into a load without submitting the corresponding forecast then the billing program would assume that the load is off schedule and the bilateral energy is sold back into the LBMP market. If you submit a forecast that includes the load to be served via the Bilateral of another load your bill will show purchases off the LBMP market. The daily bill then accounts for these actions and the adjustments to correct the bill will not be made until actual metered values are received two months later. In order to prevent the need for billing adjustments, Hourly Load Forecasts submitted in the DAM can be revised up until 12:00 NOON of the day following the effective date of the forecast. The MW total of the revised Load Forecasts for the LSEs comprising the sub-zone must equal the gross for the sub-zone.

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Technical Bulletin #6 (continued) Subject: Load Forecasts for Facilities in the Market Information System

For further information on forecasts and metering adjustments, please review the August 20,1998 White Paper by the ISO Retail Access Team on the Retail Access Settlement Process. This document can be found at the URL: http://www.nypowerpool.com/newiso/docdir/retacess.pdf Example 1: An organization's total sub-zonal load for an hour is 2000 MW. The organization is using one load/sink to schedule the energy needed to satisfy the total sub-zonal load. - Organization has entered a load bid of 1500 MW in the DAM (Bid accepted in MIS) - Organization has entered firm transaction #1 for 200 MW (Source confirms schedule & 200

MW scheduled in MIS) - Organization has entered firm transaction #2 for 100 MW (Source confirms schedule &100

MW scheduled in MIS) Forecast 1: 2000 MW Result 1: 1500 MW purchased in the Day Ahead LBMP Market 200 MW purchased in the Real-Time Market 200 MW Purchased in bilateral market with transaction #1 100 MW Purchased in bilateral market with transaction #2 Total 1: 2000 MW Example 2 & 3: An organization's total sub-zonal load for an hour is 2000 MW. The organization is using three loads/sinks to schedule the energy needed to satisfy the total sub-zonal load. - Load/sink #1 has bid 1500 MW in the DAM (Bid accepted in MIS) - Load/sink #2 has an auto-confirm firm transaction for 200 MW (200 MW scheduled) - Load/sink #3 has an auto-confirm firm transaction for 100 MW (100 MW scheduled)

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Technical Bulletin #6 (continued) Subject: Load Forecasts for Facilities in the Market Information System

Forecast 2: Load/sink #1 enters a forecast load of 1700 MW Load/sink #2 enters a forecast load of 200 MW Load/sink #3 enters a forecast load of 100 MW Result 2: Load/sink #1 1500 MW purchased in the Day Ahead LBMP Market 200 MW purchased in the Real-Time Market (RTM) Load/sink #2 200 MW received through firm transaction 0 MW is purchased/sold in the RTM Load/sink #3 100 MW received through firm transaction 0 MW is purchased/sold in the RTM Total 2: 2000 MW Forecast 3: Load/sink #1 enters a forecast load of 2000 MW Load/sink #2 doesn't enter a forecast load Load/sink #3 doesn't enter a forecast load Result 3: Load/sink #1 1500 MW purchased in the Day Ahead LBMP Market 500 MW purchased in the RTM Load/sink #2 200 MW received through firm transaction LSE considered "Off-Schedule", 200 MW sold into RTM Load/sink #3 100 MW received through firm transaction LSE considered "Off-Schedule", 100 MW sold into RTM Total 3: 2000 MW

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