Day-Ahead Scheduling Manual

Day-Ahead Scheduling Manual
MANUAL 11
Day-Ahead Scheduling
Manual
October 2016
Version:
4.4
Effective Date:
10/28/2016
Committee Acceptance:
BIC 10/11/2016
OC 10/13/2016
This document was prepared by:
NYISO Energy Market Operations
New York Independent System Operator
10 Krey Blvd
Rensselaer, NY 12144
(518) 356-6060
www.nyiso.com
Disclaimer
The information contained within this manual, along with the other NYISO manuals, is intended
to be used for informational purposes and is subject to change. The NYISO is not responsible for
the user’s reliance on these publications or for any erroneous or misleading material.
©
Copyright 1999-2016 New York Independent System Operator
NYISO DAY-AHEAD SCHEDULING MANUAL
Table of Contents
Day-Ahead Scheduling Manual ........................................................................................................... i
1.
Introduction ............................................................................................................................1-1
1.1
2.
References ................................................................................................................................ 1-1
Overview .................................................................................................................................2-1
2.1
2.2
2.3
3.
System Components ................................................................................................................. 2-1
LBMP Time Line ........................................................................................................................ 2-4
Day-Ahead Functional Components ......................................................................................... 2-5
2.3.1
Primary Functions ....................................................................................................... 2-5
2.3.2
Supporting Functions .................................................................................................. 2-6
2.3.3
Data Flow .................................................................................................................... 2-8
Bid/Post System ....................................................................................................................3-1
3.1
3.2
3.3
4.
Bid/Post Functions .................................................................................................................... 3-1
Bid/Post Process ....................................................................................................................... 3-1
Bid/Post Interfaces .................................................................................................................... 3-5
3.3.1
SCUC .......................................................................................................................... 3-5
3.3.2
Interchange Scheduler ................................................................................................ 3-5
3.3.3
Real-Time Scheduling ................................................................................................ 3-5
3.3.4
Performance Tracking System ................................................................................... 3-5
3.3.5
Billing & Accounting System ....................................................................................... 3-5
3.3.6
Historical Information Retention.................................................................................. 3-5
3.3.7
OASIS ......................................................................................................................... 3-5
Day-Ahead Scheduling Process ..........................................................................................4-1
4.1
4.2
Day-Ahead Inputs & Outputs .................................................................................................... 4-1
SCUC Initialization .................................................................................................................... 4-2
4.2.1
Day-Ahead Zonal Load Forecast ................................................................................ 4-2
4.2.2
Assemble Day-Ahead Transmission Outages ............................................................ 4-2
4.2.3
Initial Generator Status and Commitment Rules ........................................................ 4-2
4.2.4
Scheduling a “Must Run” Generator ........................................................................... 4-3
4.2.5
Multiple Response Rates for Generating Units .......................................................... 4-4
4.2.6
Day Ahead Reliability Unit (DARU) Commitment ....................................................... 4-5
4.2.7
Phase Angle Regulator Scheduling ............................................................................ 4-6
4.3
Security Constrained Unit Commitment .................................................................................... 4-7
4.3.1
SCUC Stages .............................................................................................................. 4-7
4.3.2
SCUC Components .................................................................................................. 4-10
4.3.3
SCUC Inputs ............................................................................................................. 4-12
4.3.4
Demand Curves ........................................................................................................ 4-14
4.3.5
Constraint Breaking .................................................................................................. 4-15
4.3.6
SCUC Interfaces with Other Systems....................................................................... 4-15
4.4
Bilateral Transaction Evaluations ............................................................................................ 4-15
4.4.1
Firm Bilateral Transactions ....................................................................................... 4-16
4.4.2
Multi-Hour Block Transactions (MHBT) .................................................................... 4-16
4.4.3
Non-Firm Bilateral Transactions ............................................................................... 4-17
5.
Day-Ahead Interface to the Dispatch Day ...........................................................................5-1
5.1
Interchange Schedule Interface ................................................................................................ 5-1
5.1.1
User Interface ............................................................................................................. 5-1
5.1.2
Functional Interfaces .................................................................................................. 5-1
5.2
Generation Schedule Interface ................................................................................................. 5-2
5.3
Ancillary Service Schedule Interface ........................................................................................ 5-2
NYISO Energy Market Operations
Version 4.4
10/28/2016
iii
NYISO DAY-AHEAD SCHEDULING MANUAL
6.
NYISO Load Forecast Process .............................................................................................6-1
6.1
6.2
Load Forecast Overview ........................................................................................................... 6-1
Load Forecast Functions ........................................................................................................... 6-1
6.2.1
Load Forecast Module ................................................................................................ 6-1
6.2.2
Load Forecast Training Module .................................................................................. 6-1
6.2.3
Load Forecast Functional Interfaces .......................................................................... 6-2
6.3
Load Forecast User Interface.................................................................................................... 6-2
7.
SCUC Execution.....................................................................................................................7-1
7.1
7.2
8.
SCUC ........................................................................................................................................ 7-1
SCUC Execution Actions .......................................................................................................... 7-1
Reliability Forecast ................................................................................................................8-1
8.1
8.2
8.3
8.4
Reliability Forecast Requirements ............................................................................................ 8-1
Reliability Responsibilities ......................................................................................................... 8-2
Dealing with Insufficient Bids .................................................................................................... 8-3
Reliability Assessment Processes ............................................................................................ 8-4
9.
Interchange Coordination Procedure ..................................................................................9-1
10.
Supplemental Resource Evaluation One or More Days Ahead ......................................10-1
Attachment A.
Calculation of Incremental Losses .................................................................. A-1
Attachment B.
NYISO Load Forecasting Model ....................................................................... B-1
iv
NYISO Energy Market Operations
Version 4.4
10/28/2016
NYISO DAY-AHEAD SCHEDULING MANUAL
Table of Figures
Figure 2-1: NYISO Bid-to-Bill Process ................................................................................................2-3
Figure 2-2: LBMP Time Line ...............................................................................................................2-4
Figure 2-3: Day-Ahead Scheduling Data Flow ...................................................................................2-5
Figure 4-1: Multi-Pass Solution Process ............................................................................................4-9
Figure 4-2: Transaction Example ..................................................................................................... 4-19
Figure A-1: Incremental Transmission Losses .................................................................................. A-1
Table of Tables
Table 4-1: Non-Firm Transaction Selector Program Logic .............................................................. 4-18
Table 4-2: Transaction Parameters ................................................................................................. 4-19
Table 8-1: Reliability Assessment - Load and Capacity Table ...........................................................8-3
Table B-1: Albany Airport Actual and Forecasted Weather............................................................... B-3
Table B-2: Zonal Share of New York State’s 2010 Population ......................................................... B-4
Table B-3: Weather Station Weights Imputed to Each Zone ............................................................ B-4
NYISO Energy Market Operations
Version 4.4
10/28/2016
v
NYISO DAY-AHEAD SCHEDULING MANUAL
Revision History
Revision
Date
Changes
4.4
10/28/2016
Section 4.3.4
 Updated Demand Curve table to reflect the changes related to
Comprehensive Scarcity Pricing
4.3
04/28/2016
Section 4.3.4
 Updated middle pricing point value of Transmission Shortage Cost
4.2
02/11/2016
Version delayed until 2/11/16 to correspond with NYISO deployment and
activation of the Graduated Transmission Demand Curve software
Global
 Standardized references to NYISO Manuals and User’s Guides
Section 4.3.4
 Updated Demand Curve table to reflect the graduated Transmission
Demand Curve
Section 4.2.7
 Updated the reference to the 5018 transmission line from “BranchburgRamapo Interconnection” to “Hopatcong-Ramapo Interconnection”
4.1
02/01/2016
Section 2.3.3
 Added reference to Southeastern New York reserve requirements
Section 4.3.4
 Updated the table providing parameters of demand curves
implemented by the NYISO
4.0
02/04/2013
Section 4.2.7
 Incorporated Technical Bulletin #26, 32, 49, 65, 71, 86, 135, 152, 182
 Changed The ABC interconnection will be scheduled … plus “an adjustment
of up to 13%”, into “0%” of PJM-NYISO Day-Ahead Market hourly
interchange
 Changed The JK interconnection will be scheduled … plus “an adjustment of
up to 13%”, into “0%” of PJM-NYISO Day-Ahead Market hourly interchange
Section 4.3.3
 Changed The incremental energy bid for a generator is modeled as “a
piecewise linear monotonically increasing cost curve” into “a series of
monotonically increasing constant cost steps”
Deleted Section 6.4 MIS Load Modeling and LSE Responsibilities
Deleted Section 6.5 Load Forecasts for Facilities in the Market Information
System
4.0
08/15/2012
Added Section 1: INTRODUCTION
 1.1 Included References
Re-numbered other sections
Section 2
 Renamed section name from Day Ahead Scheduling to OVERVIEW
Figure 2-1:
 Changed “Hour-Ahead Bids” into “Real-Time Bids”
Section 2.2
vi
NYISO Energy Market Operations
Version 4.4
10/28/2016
NYISO DAY-AHEAD SCHEDULING MANUAL
 Added a paragraph about the daily reliability study over the seven-day
period
Broke “Functions” into Section 2.3.1: Primary Functions and Section 2.3.2:
Supporting Functions
Section 2.3.1
 Deleted “Eligible Customers”
Section 2.3.2
 Deleted Post Unit Commitment (PUC)
 Replaced Performance Tracking System (PTS) with Automatic Generation
Control (AGC)
Section 2.3.3
 Added Automated Mitigation Process (AMP)
 Reserve and Regulation Requirements: Changed “on a Transmission
Constraint Group basis” to “from the Energy Management System”
Section 3.1 2nd paragraph
 Changed “general NYISO status to all Market Participants such as
performing unscheduled commitment” to “generators that are committed for
reliability under Operational Announcements on the ISO website”
Section 3.2
 Changed Bilateral Transactions into External Transactions
 Added a bullet on Prohibited Transmission Paths for Validity Checks
Section 3.3
 Deleted the section LBMP Calculation
 Deleted the section Loss Calculation
Section 4
 Changed Bilateral Transactions into External Transactions
Section 4.1
 Added Validated virtual generation and virtual load bids from the BID/Post
System, and Lake Erie circulation assumptions in Inputs to Day-Ahead
Scheduling
 Added in Outputs from Day-Ahead Scheduling: Non-Firm Available Transfer
Capabilities (ATCs) posted on OASIS, PAR Flows posted on OASIS, DayAhead Limiting Constraints posted on OASIS, Commitment schedule for
External Transactions
Section 4.2
 Changed Preliminary Zonal Load Forecast to Day-Ahead Zonal Load
Forecast
 Moved Assemble Day-Ahead Transmission Outages to section 4.2.2
Section 4.2.3
 Changed Performance Tracking into Automatic Generation Control
 Added: requirements across midnight are not recognized, except to the
extent they are reflected in a late day start Bid
Added Section 4.2.4: Scheduling a “Must Run” Generator
 Incorporated Technical Bulletin #26
 Added Submit a Bid in Self-Committed Fixed Mode
Added Section 4.2.5: Multiple Response Rates for Generating Units
 Incorporated Technical Bulletin #71
 Changed “regulating response rate” into “regulating capacity response rate”
NYISO Energy Market Operations
Version 4.4
10/28/2016
vii
NYISO DAY-AHEAD SCHEDULING MANUAL
 Added “The regulation capacity response rate must not be slower than the
slowest energy or emergency response rate.”
 Changed “Customer Relations” into “Stakeholder Services”
Added Section 4.2.6: Day Ahead Reliability Unit (DARU) Commitment
 Incorporated Technical Bulletin #182
 Added “or for statewide reliability needs as initiated by NYISO,” are known
as Day-Ahead Reliability Units (“DARU”)
 Changed the Generator’s contact may also reach out to inform the NYISO
“at 518-356-6028” into “Grid Operations Department”
 Added: A DARU request by a Transmission Owner “or by the NYISO” may
override a generator’s startup notification time
Section 4.2.7
 Added “The desired flows will be established for the ABC, JK, and 5018
interconnections based on the following, pursuant to OATT Section 35,
Attachment CC – JOA Among and Between NYISO and PJM, Schedule C
and Schedule D” and added scheduling rules for ABC, JK and 5018
 Added the paragraph about scheduling of Northport PAR
Section 4.3.1
 Incorporated changes in Technical Bulletin #49
 Pass #1: Changed the name to Bid Load, “Virtual Load and Virtual Supply”
Commitment
 Changed “solves for supplying the Bid Load” into “commits and schedules
generating units, including units nominated to be Day Ahead Reliability
Units, to supply Bid Load (Physical and Virtual) less Virtual Supply”
 Added “Also, the program secures for certain Local Reliability Rules’
contingencies and monitored facilities”
 Pass #2: Changed “solves for supplying the forecast load” into “commits any
additional units that may be needed to supply the forecast load”
 Added “Load bids (physical and virtual) and Virtual Supply bids are not
considered in Pass #2”
 Added “In Pass #2, only the wind energy forecasts are used for scheduling
intermittent resources that depend on wind as their fuel”
 Changed Pass #3 from “Local Reliability Rules Forecast Load Commitment”
to “Reserved for future use”
 Pass #4: Changed “regulation” to “regulation capacity”
 Pass #5: Added “virtual load and virtual supply (where virtual supply is
treated as negative virtual load)”
 Deleted “After this dispatch, the market power mitigation process is run to
evaluate reserve price caps”
 Forecast Required Energy for Dispatch (FRED)
Changed “Bilateral Schedules with Internal Sinks” into “import transaction
schedules”
 FRED Payment Rules
 Added “subject to mitigation as appropriate”
Section 4.3.2
 Initial Unit Commitment (IUC): Changed “performance tracking system”
into “Automatic Generation Control system”
 Deleted New York Interface constraints
 Changed “An input processor takes the flat files from the Bid/Post system
and load them into the IUC database” into “Bid data is transferred from the
Bid/Post system into the RANGER database”
 Unit Commitment (UC): Changed “calculates the minimum bid price” into
viii
NYISO Energy Market Operations
Version 4.4
10/28/2016
NYISO DAY-AHEAD SCHEDULING MANUAL
“calculates the minimum bid cost schedule”
 Added “Each UC solution is comprised of a physical dispatch and an ideal
dispatch. The ideal dispatch allows for GTs to be dispatched across their
entire operating range. The LBMPs are determined from this dispatch. The
physical dispatch uses blocked bid limits for GTs modeling the physical
manner in which GTs operate. The generation schedules are determined
from this dispatch.
 Infeasible Handling: Changed “it automatically ceases to be enforced in a
hard manner and is permitted to be violated” into “the constraint is relaxed,
and solved for,”
Section 4.3.3
 Production Bid: Changed “bid operating costs” into “incremental energy,
minimum generation … costs”
 Operating Bid: Changed “incremental operating bid” into “incremental energy
bid”
 Added: The first segment is “determined by the minimum generation cost
and” defined by the no-load cost axis intercept ($/hr) and a slope ($/MWh).
The “11 incremental energy” segments …
 Startup Bid: Changed the generator has been “down” to “off line”
 Reserve Bid: Changed regulation “cost” into “bid”
 Added: “It is given by a regulation available capacity (MW), a regulation
capacity cost ($/MW) and regulation movement cost ($/MW)”
 Changed: For off-line and non-dispatchable generators, “the reserve bid is
given by a reserve availability cost ($/MW)”
 Incorporated TB135. Added the paragraphs about Losses
 Reserve Profile: Changed “Regulation” into “Regulation capacity”
 Added: Regulation “available is limited by the regulation capacity response
rate” and spinning reserve “is” determined by …
Added Section 4.3.4: Demand Curves
Section 4.3.5
 Changed “1. Interruptible transactions” into “1. Regulation and reserve
constraints”
 Changed “2. Export constraints” into “2. Transmission constraints”
 Changed “3. Import constraints” into “3. Interchange ramp constraints”
 Deleted “4. Reserve constraints”
 Changed “5. System generation requirement” into “4. System Demand”
 Changed “Soliciting additional bids” into “Dispatching generators to
emergency upper operating limits”
 Deleted: “Requesting the” cancellation or rescheduling of outages
Section 4.3.6
 Bid/Post System: Deleted “and Penalty Factors”.
 Added: “Later SCUC provides the Bid/Post System with accepted generator,
transaction, and load bids, clearing prices, etc. This information is also
passed on to the Real-Time Commitment process during the Dispatch Day.”
 Delete the bulletin on “Performance Tracking System”
 Changed “Outage Scheduler” into “Energy Management System (EMS)”
 Added “reserve and regulation requirements, unit status history and
contingency definition”.
 Changed “OS function” into “EMS”
 Changed “Post Unit Commitment” into “Load Forecaster”, and the paragraph
into:
 “The SCUC function receives the load forecast for the Day-Ahead study
NYISO Energy Market Operations
Version 4.4
10/28/2016
ix
NYISO DAY-AHEAD SCHEDULING MANUAL
period from the Load Forecasting program.”
Added Section 4.4.2: Multi-Hour Block Transactions (MHBT)
 Incorporated Technical Bulletin #86
Deleted Section 4.5: Post Unit Commitment (UCP)
Deleted the original Section 5: Transmission Constraint Group (TCG)
Assembly
 TCG is an obsolete process. The data that previously in the TCG file was
the regulation and reserve requirements, which has been incorporated into
other parts of the manual.
Section 5.1.2
 Changed “Balancing Market Evaluation” into “Real-Time Market
Evaluation”
 Added “along with available Real-Time transaction bids are passed”
 Added: “The final Desired Net Interchanges for the NYCA and neighboring
Control Areas are passed from the IS+ function to the Real-Time Dispatch (RTD)
function through the Bid/Post System.”
Section 5.3
 Deleted “which then passes the information on to the BME process during
the Dispatch Day”
 Added: “The Ancillary Services are evaluated again as part of the Real-Time
Scheduling systems solutions and the accepted Ancillary Service schedules
are passed to the Bid/Post System.”
Section 6.1
 Incorporated Technical Bulletin #65
 Added: each of the “eleven” NY Control Area Zones “and at the statewide
level”
 Added: “The Load Forecast function uses a combination of advanced neural
network and regression type forecast models to generate its forecasts.”
Section 6.2
 Deleted the bulletin “Study Load Forecast Module”
Section 6.2.1
 Added: “A single Load Forecast Module is used to produce the load
forecasts for all the scheduling systems. The program automatically
generates the 5 minute forecasts used by RTS. The hourly forecasts
required for SCUC are published on demand for the current day and up to
six days for each Zone. The published forecast is posted to the NYISO
website by 08:00 a.m. every day, or as soon thereafter as is reasonably
possible.”
 Added: “The forecasts that are produced for the scheduling systems
represent only the expected demand usage and do not include transmission
losses. The transmission losses are specifically computed as part of the
scheduling systems’ functionality.”
Deleted Section 6.2.2: Study Load Forecast Module
Section 6.2.2
 Added: This module allows the generation of load forecasts models for each
Zone “and for the New York Control Area”
Section 6.2.3
 Changed “Bid/Post System” into “Oracle Information Storage and
Retrieval (OISR) System”
 Added: with the “NYCA and Zonal hourly loads for storage”
 Added: “The MIS, SCUC and RTS systems can then retrieve the most up to
x
NYISO Energy Market Operations
Version 4.4
10/28/2016
NYISO DAY-AHEAD SCHEDULING MANUAL
date load forecast available.”
 Changed “Historical Data File” into “Historical Load Data”
 Deleted “and weather” data
 Changed “from the historical data file maintained from actual data retrieved
from the on-line EMS” into “from the EMS through its PI Historical data”
 Changed “Weather Forecast File” into “Weather Data”
 Added: retrieves weather forecast “data and historical weather” data
 Changed “from the weather forecast data files maintained from data
received from the weather service” into “from files received from the weather
service”
Section 6.3
 Changed: Initial forecasting is completed “by 6AM” to “prior to initializing
SCUC”
 Deleted: “considered to be a working environment”
 Changed “The required files as input to the program as well as output of the
program are in ASCII format which can be generated from other database
tables for the input files, and be ported to other database tables for the
output files” into “The required files as input to the program are in .csv
format.”
 Changed “export a load forecast file in the format required for the multi-area
Unit Commitment package to utilize” into “publish the load forecast data to
OISR for the SCUC package to utilize”
 Deleted: “The exported areas can be specified to be either individual
forecast areas or super zones.”
 Added: By 08:00 a.m., “or as soon thereafter as is reasonably possible”, the
NYISO develops and posts its statewide Load forecast on the OASIS.
Added Section 6.4: MIS Load Modeling and LSE Responsibilities
Added Section 6.5: Load Forecasts for Facilities in the Market Information
System
Section 7
 Changed “Security Constrained Unit Commitment” into “SCUC”
Section 7.1
 Changed “NYISO Operations Planning” into “Energy Market Operations”
 Changed “after the pre-UC process” into “after MIS DAM Market closing
process has completed”
 Changed “S.P.I.D.E.R. workstation” into “RANGER system”
Section 7.2
 Changed “1. …Bid/Post” into “1. … MIS”
 Changed “2. Acquire current Security Constrained Unit Commitment history”
into “2. Transfer data from the EMS / Real Time server”
 Changed “3. Retrieve the TCG file” into “3. Perform the SRE end of the day
fill in process”
 Deleted “7. Assemble output SCUC file”
 Changed “8. … SCUC output file” into “8. … SCUC output data”
 Deleted “9. Send SCUC information to the Historical Information System”
Section 8.1
 NYISO Actions: 1). Deleted “(using LSE forecast data, where appropriate)”
Section 8.3
 The Need for Bids: Changed “order on resources” into “commit resources
in the DAM”
NYISO Energy Market Operations
Version 4.4
10/28/2016
xi
NYISO DAY-AHEAD SCHEDULING MANUAL
Broke the end of Section 8.3 into a new section as 8.4 Reliability
Assessment Processes
 Added: “The NYISO continually re-evaluates the reliability of the NYCA.
There are several reliability assessments of any given Operating Day
performed over various time horizons. The sequences of these evaluations
are described next.”
 Real-Time Reliability
 Added: the NYISO shall commit all bid resources “subject to network
security constraints;”
Section 10
 Removed the original contents in this section, and referred to Transmission
and Dispatch Manual section 5.7.5 through 5.7.12
Attachment B
 Renamed the section to “NYISO Load Forecasting Model”
 Renamed “top/down – bottom/up” approach to “bottom/up”
 Changed: peak load and energy at “the NYCA and” zone level into “and
obtains the NYCA level by summing over the zones”
 Added: “Once the peak load and daily energy are obtained, a series of
hourly interval models are determined, comprised of four fifteen-minute
interval models for each hour of the day.”
 Changed: The model’s structure flows from daily peak and energy at the
“system (NYCA) level” into “zonal level”
 Deleted “to hourly loads at the system level, to daily energy at the zone
level”
 Deleted: “The bottom/up component comes from using zone hourly loads
and the zone’s share of load in an adjustment process that takes advantage
of high quality information at the NYCA level to adjust the zone hourly loads.
The next paragraphs clarify this approach.”
 Updated data in Table B-2: Zonal Share of New York State’s 2010
Population
Deleted the paragraphs in the section “Using the Model”
3.0
05/06/2003
Section 1




Replaced BME with RTC
Replaced SCD with RTD
Changed BSYS to Bid/Post System
Changed UCP to PUC
Section 2




Replaced BME with RTC
Replaced SCD with RTD
Corrected inaccurate information
Changed UCP to PUC
Section 3




Revised 3.3.1 with TB#49
Revised 3.4.2 with TB#32
Changed BSYS to Bid/Post System
Changed UCP to PUC
Section 4
 Replaced BME with RTC
Section 6
xii
NYISO Energy Market Operations
Version 4.4
10/28/2016
NYISO DAY-AHEAD SCHEDULING MANUAL
 Created 6.4 with TB#13
 Created 6.5 with TB#6
 Changed BSYS to Bid/Post System
Section 7
 Question
Section 8
 Replaced BME with RTC
Section 9
 Question
Section 10
 Replaced BME with RTC
 Replaced SCD with RTD
Attachment A
 Replaced BME with RTC
Attachment B
 Removed NYPP
 Improved Exhibit titles and references
2.0
06/12/2001
Sect. 1.1.1, The Day-Ahead Subsystem Bullet 3
 Delete: Step 1: Commits Generators (Set 1) based on Load Serving Entity
bids, firm Bilateral Transactions, reserve requirements, and regulation
requirements. The Load in this step is referred to as the First Settlement
load.
 Step 2: Commits additional Generators (Set 2) as required in the event that
the New York Independent System Operator load forecast is greater than
the First Settlement load in Step 1.
 Step 3: Security Constrained Dispatch: based on the First Settlement load
from Step 1 and the Generators from Sets 1 and Set 2.
Sect. 1.3, Functions
 Delete: Network Sensitivity (NS) — The Network Sensitivity function
provides the transmission loss Penalty Factors for use by the Security
Constrained Unit Commitment program.
Sect. 1.3, Data Flow
 Delete: b. Penalty Factors — The BSYS function retrieves penalty factors
from the Network Sensitivity function.
 h. Outage Scheduler to SCUC — SCUC retrieves the TTCs for the transfer
of energy between the Zones and Area to Area export limits.
Sect. 3.1, Inputs to Day-Ahead Scheduling
 Delete last bullet: all-lines-in DFAX
Sect. 3.1, Outputs from Day-Ahead Scheduling
 Delete first bullet:
 facility outages to the Real-Time Security Analysis (RTSA) model
Sect. 3.2.1
 Delete first bullet:
 preparation of a path-oriented TTC flat file for SCUC input which is stored on
the Transmission Constraint Group (TCG) file
Sect. 3.2.3
 Add “and commitment rules” to the end of the subsection’s title
NYISO Energy Market Operations
Version 4.4
10/28/2016
xiii
NYISO DAY-AHEAD SCHEDULING MANUAL
Sect. 3.2.3, 2nd paragraph
 Replace “these” before “statuses” with “generating unit”
Sect. 3.2.3, 2nd paragraph
 Delete 2nd sentence
Sect. 3.2.3After 2nd paragraph, add:
Initialization Status
 When SCUC initializes, 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.
 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.
Sect. 3.2.4, #2
 Replace “contingencies occur” with “maintenance facility outages are
scheduled”
Sect. 3.2.4
 Delete # “4) Interface schedule and actual flows will be posted.”
Sect. 3.3.1
 Insert new # “4) Committing sufficient Capacity to meet the ISO's Load
forecast and Local Reliability Rule requirements.” And renumber remaining
item in list.
xiv
NYISO Energy Market Operations
Version 4.4
10/28/2016
NYISO DAY-AHEAD SCHEDULING MANUAL
Sect. 3.3.1
 Paragraph after #5, Revise to read as follows: “To meet the above
requirements, the SCUC algorithm is a five pass process in which three
security constrained commitment passes and two security constrained
dispatch passes are executed in sequence as follows:”
Delete:
 Step 1: SCUC with Bid Load - A First SCUC will be based on day-ahead
firm bilateral transaction schedule requests, supplier bids, and LSE load
bids. This will result in Generator Set #1, and LBMPs that will be used in the
Second SCUC.
 Step 2: SCUC with Forecast Load - A Second SCUC will result in an
additional Generator Set #2. This SCUC run will use:
 a. The NYISO forecasted load.
 b. Committed generators from the First SCUC (Gen Set #1) with their startup and minimum generation price bids set to zero for the hours they were
committed, and minimum generation limit set to the First SCUC dispatch
level. Additionally, their incremental energy price bids will be set equal to
zero.
 c. Other bid generators that were not committed in the First SCUC. For the
Second SCUC, the bids for the previously non-committed generators will be
adjusted in the two following ways to select Gen Set #2:
 1. Each will have its Min Gen Price Bid reduced by its Min Gen Bid multiplied
by LBMP from the First SCUC. For example, if a non-committed generator
had a $4,000/hr Min Gen Price Bid with a Min Gen Bid of 100 MW, and
LBMP from the First SCUC for a specific hour was $30/MWh, then that
generator's Min Gen Price Bid for that hour will be set equal to ($4,000 (100 x $30)) = $1,000/hr.
 2. Each will have its incremental energy price bid set equal to zero (this is
intended to minimize the cost of providing additional operating reserves for
the non-bid portion of the ISO's total load forecast, but not necessarily
minimizing the cost of energy to serve that non-bid load).
 Step 3: SCUCD Ideal Dispatch to Set Preliminary Day-Ahead Schedule Following completion of the two sets of SCUC, a first Day-Ahead hourly
Security Constrained Unit Commitment Dispatch (SCUCD) will be performed
to produce First Settlement LBMPs. This first "ideal" SCUCD will use:
 a. The Load Bids from the First SCUC.
 b. In the interim: the committed generators from Gen Set #1 (including Gen
Set #1 committed Quickstart generators) using their actual bid data and
prices, with the exception that Gen Set #1 Quickstart generators will have
minimum operating levels of 0 MW and maximum operating capabilities
equal to their maximum bid MW.
 Ultimately: the combination with or without any or all Quickstart generators
from Gen Set #1 which yields the least expensive dispatch will be passed to
Step #4 below.
 c. The committed generators from Gen Set #2 (excluding Gen Set #2
committed Quickstart generators) using their actual bid data and prices.
 If Quickstart generators in the first "ideal" SCUCD are dispatched to their
maximums, they will set LBMP. Thus, a Gen Set #1 Quickstart generator will
set LBMP only when it is needed to economically serve load.
 Step 4: SCUCD Real Dispatch to Set Day-Ahead Schedules and LBMPs
 In the Interim: SCUCD will be run a second time with the same parameters
as the first SCUCD except that all Gen Set #1 generators and all Gen Set #2
generators (excluding Gen Set #2 Quickstart generators) will be run at least
at minimum
 Ultimately: All generators in Step #3 that were dispatched above zero will be
run at least at minimum.
NYISO Energy Market Operations
Version 4.4
10/28/2016
xv
NYISO DAY-AHEAD SCHEDULING MANUAL
 This second "real" SCUCD will be performed to produce generator
schedules and load schedules to be used for First Settlement forward
contracts.
 Note: Commitment means to start-up a generator to run at or above its
minimum generation level. Therefore, if a Quickstart generator is shown to
be needed in the first SCUCD, it is scheduled on-line to run at maximum by
the second SCUCD because the minimum level for a Quickstart generator is
typically the same as its maximum level. Quickstart generators have start-up
times of one hour or less.
Sect. 3.3.1
 Insert material from Tech Bulletin #49
Sect. 3.3.2
 Under “Initial Unit Commitment (IUC):” delete last bullet: “penalty factors”
Sect. 3.3.3, Under “Startup and Shutdown Constraints”
 Delete 2nd paragraph: Conflicts between these limits and generator
maintenance schedules are resolved using the constraint breaking rules
established by the NYISO.
Sect. 3.3.3, Under “Penalty Factors”
 Delete 1st paragraph: “Transmission loss Penalty Factors are input for each
generator. The Penalty Factors multiply the generation operating bid cost
during the schedule and dispatch optimization. A single set of Penalty
Factors is used for each SCUC execution.” And replace with “The SCUC
application uses the ABB Security Analysis (SA) module to generate delivery
factors for each time step in the commitment period. The delivery factors for
each time step reflects the network topology expected for that time period
and the generation dispatch from the Unit Commitment (UC) module.”
Sect. 3.3.5
 Delete section: “NYISO Operator User Interface – Operator Participation,
Operator participation is a feature of the Unit Commitment that enables the
operator to override the UC solution with direct instructions as to how
specific generators are to be loaded and/or dispatched. The costing and
dispatching algorithms of UC are then rerun to implement these instructions.
 Operator participation is a “total” override capability. That is, the operator
must tell whether a generator is to be ON during a specified amount of time,
and if so whether it is to be ON at a specified MW level or at a level dictated
by economics (economically dispatched). Also, if a generator is specified to
be ON, whether it contributes toward reserve as usual or whether it does not
contribute to reserve at all.
 It is necessary to emphasize here that the original commitment sequence of
generators remains unchanged unless modified by the operator. When
running under the operator participation mode, the commitment optimization
algorithms are not re-executed. A consequence of this is that constraints
such as minimum uptime and downtime may be violated based on operator
directives.
 Minimum up and downtime, ramp rate, start-up and shutdown constraints
are checked and violations are reported.
Sect. 3.4.2
 Delete material after 1st paragraph and replace with new material.
5.3, Replace current #3
Determine the zonal load forecast.
 The state-wide load forecast used in SCUC is based on a summation of the
zonal load values. The ISO Services tariff requires that the LSE load
forecasts be considered in the development of the state-wide forecast when
it is consistent with the ISO forecast. The LSE zonal load forecast is
xvi
NYISO Energy Market Operations
Version 4.4
10/28/2016
NYISO DAY-AHEAD SCHEDULING MANUAL
considered to be consistent with the ISO forecast when the sum of the LSE
zonal load forecasts on a control area basis is less than 105% of the ISO
forecast on a state-wide basis and when the LSE forecast is within 100% to
105% of the ISO forecast on a zonal basis. Therefore, if the sum of the LSE
zonal load forecasts is not consistent with the ISO state-wide forecast, then
the LSE zonal load forecasts are not considered. Additionally, if a LSE zonal
load forecast is not consistent with the ISO zonal forecast, then the LSE
zonal load forecast is not considered. Therefore, the zonal load values used
in SCUC are determined using the following rules:
The Bid Load plus Bilateral contracts zonal value is used as the zonal load
value when:
 a) the Bid Load plus bilateral contracts zonal value is greater than the ISO
zonal load forecast and,
 b) the Bid Load plus bilateral contracts zonal value is greater than the LSE
zonal load forecast, when determined to be consistent with the ISO forecast.
The ISO zonal load forecast is used as the zonal load value when:
 a) the ISO zonal load forecast is greater than the Bid Load plus Bilateral
contracts zonal load value and,
 b) the ISO zonal load forecast is greater than the LSE zonal load forecast,
when determined to be consistent with the ISO forecast.
The LSE zonal load forecast, when determined to be consistent with the
ISO forecast, is used as the zonal load value when:
 a) the LSE zonal load forecast is greater than the ISO zonal load forecast
and,
 b) the LSE zonal load forecast is greater than the Bid Load plus bilateral
contracts zonal value.
1.0
09/03/1999
Exhibit 3.1
 New Exhibit
Attachment A
 Addition of last 2 paragraphs of Attachment A.
Sect. 3.2.4 Page 4
 Phase Angle Regulator (PAR) Scheduling
Sect. 3.3.1 Page 6, 7
 SCUC Stages
NYISO Energy Market Operations
Version 4.4
10/28/2016
xvii
NYISO DAY-AHEAD SCHEDULING MANUAL
Initial
Release
xviii
06/05/1998
Information on the following topics was added
 1. Negative Congestion and Non-Firm Transmission Service
 a. Non-Firm transmission service that encounters negative congestion will
not be curtailed.
 b. Non-Firm transmission service that encounters negative congestion will
not be paid for the negative congestion.
 2. Supplemental Resource Evaluation (SRE) Process
 3. Security Constrained Unit Commitment (SCUC) Algorithm to be
implemented
 4. Phase Angle Regulator (PAR) Scheduling in Security Constrained Unit
Commitment (SCUC)
 5. Minimum run times Extending Past the Commitment Period
 a. The Tariff specifically precludes committed generators from remaining
on-line past the end of the Dispatch Day to fulfill minimum run time
requirements.
 b. A generator which needs to remain on-line past the end of the Dispatch
Day or Dispatch Hour to fulfill its minimum run time will have the
responsibility to structure its bid in such a way as to continue to be economic
as evaluated by SCUC or BME so it is scheduled to remain on-line.
 6. Dealing with the Potential for Insufficient Bids
 The NYISO will perform a reliability assessment to determine if projected
Operating Reserves over an upcoming period will be adequate and will take
certain steps if deficiencies are anticipated.
 7. FRED: Forecast Required Energy for Dispatch
 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 and scheduled
bilateral loads. 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
 8. Data Requirements for Bilateral Transaction Requests
NYISO Energy Market Operations
Version 4.4
10/28/2016
NYISO DAY-AHEAD SCHEDULING MANUAL
1.
I NTRODUCTION
This NYISO Day-Ahead Scheduling Manual is one of a series of manuals within the Operations
Manuals. This Manual focuses on describing each of the Day-Ahead scheduling processes that
are facilitated and/or controlled by the NYISO.
The NYISO Day-Ahead Scheduling Manual consists of eleven sections and two attachments as
follows:
 Section 1: Introduction
 Section 2: Overview
 Section 3: Bid/Post System
 Section 4: Day-Ahead Scheduling Process
 Section 5: Day-Ahead Interface to the Dispatch Day
 Section 6: NYISO Load Forecast Process
 Section 7: SCUC Execution
 Section 8: Reliability Forecast
 Section 9: Interchange Coordination Procedure
 Section 10: Supplemental Resource Evaluation
 Attachment A: Calculation of Incremental Losses
 Attachment B: NYISO Load Forecasting Model
1.1
References
The references to other documents that provide background or additional detail directly
related to the NYISO Day-Ahead Scheduling Manual are:
 NYISO Emergency Operations Manual
 NYISO Accounting & Billing Manual
 NYISO Transmission & Dispatching Operations Manual
 NYISO Market Participant User’s Guide
 New York ISO Tariffs
 NYSRC Agreement
 NYSRC - Reliability Rules Manual
NYISO Energy Market Operations
Version 4.4
10/28/2016
1-1
NYISO DAY-AHEAD SCHEDULING MANUAL
This page intentionally blank.
1-2
NYISO Energy Market Operations
Version 4.4
10/28/2016
NYISO DAY-AHEAD SCHEDULING MANUAL
2.
O VERVIEW
This section describes the overall Locational Based Marginal Pricing (LBMP) process, which
sets the stage for the Day-Ahead activities.
2.1
System Components
The overall Bid-to-Bill Process from the time Bids are received to the time that payments
are made consists of the following major components:
 Bid/Post System
 Day-Ahead Subsystem
 Real-Time Scheduling (RTS) Subsystem
•
Real-Time Commitment (RTC)
•
Real-Time Dispatch (RTD)
 Settlement Subsystem
Additionally, the Historical Information Retention system and the Supervisory Control and
Data Acquisition (SCADA) subsystem provide services to these major components.
Bid/Post System
The purpose of the Bid/Post System is to:
 Accept generator and load bids and schedules for External Transactions
 Post the public results of the Day-Ahead Market, Real-Time Commitment (RTC),
and Real-Time Dispatch (RTD).
Day-Ahead Scheduling Subsystem
The Day-Ahead scheduling process consists of the following principal functions:
 Assemble Day-Ahead Transmission Outages; Update Total Transfer Capabilities,
constraints and the Security Constrained Unit Commitment (SCUC) model; post
updated Total Transmission Capability on the Open Access Same Time Information
System.
 Produce NYISO Day-Ahead Zonal Load Forecast, based on weather forecasts and
the load forecast model.
 Perform SCUC and scheduling.
 Tabulate and Evaluate Non-Firm Transactions; In the event that there is no
congestion, the non-firm transactions are scheduled in sequence up to the Available
Transfer Capabilities of the NYS Transmission System.
 Perform Automated Mitigation of generator offers.
Real-Time Scheduling Subsystem
Approximately every 15 minutes, a Real-Time Commitment (RTC) evaluation takes place
to ensure that the schedules meet all of the reliability requirements. Each Real-Time
NYISO Energy Market Operations
Version 4.4
10/28/2016
2-1
NYISO DAY-AHEAD SCHEDULING MANUAL
transaction is evaluated independently against the Day-Ahead transactions and Generator
Bids, using the RTC program. Any new firm External Transactions will be scheduled by
RTC, which could displace some of the Day-Ahead non-firm transactions. If necessary, 10
and 30-minute resources will also be scheduled. The results are then posted every 15
minutes.
Approximately every 5 minutes, the Real-Time Dispatch (RTD) uses Bid curves of the New
York Control Area (NYCA) generators to dispatch the system to meet the load while
observing transmission constraints. Bid curves will consist of a combination of incremental
bid curves provided by generators bidding into the LBMP market and decremental bid
curves provided by generators serving Bilateral Transactions.
Settlement Subsystem
During each hour of operation, the results of SCUC, RTS and Automatic Generation
Control (AGC) are captured and stored for later use by the Billing subsystem. The NYISO
will have all the information necessary to determine all of the charges and payments, which
must flow between the NYISO and the Market Participants.
2-2
NYISO Energy Market Operations
Version 4.4
10/28/2016
NYISO DAY-AHEAD SCHEDULING MANUAL
Day -Ahead Bids
Schedules and
Forecasts
Load Forecasts
Transaction
Schedules
BID/POST
System
Energy Bids
Power
Exchange
Security
Constrained
Unit Commitment
(SCUC)
LSE
GENCO
Posting of
Day -Ahead
Schedules
Direct ISO Customers
LSE
Real -Time
Bids and
Proposed Transactions
GENCO
Committed
Day -Ahead
Schedule
Real -Time
Commitment
(RTC)
Base Points
to Generators
Posting Updated for
Real -Time Schedules
Real -Time
Dispatch
(RTD)
Settlement Statements
to all market participants
Posting of
LBMP Results
LBMP's , Base Points
and Telemetry
Committed Day -Ahead
Schedules plus
Accepted Real -Time
Schedules
Billing
and
Accounting
Figure 2-1: NYISO Bid-to-Bill Process
NYISO Energy Market Operations
Version 4.4
10/28/2016
2-3
NYISO DAY-AHEAD SCHEDULING MANUAL
2.2
LBMP Time Line
The sequence of events for the implementation of LBMP is shown in Figure 2-2.
Figure 2-2: LBMP Time Line
Finalized Day-Ahead bids must be submitted by 05:00 a.m. (or by 4:50 a.m. for some
External Transaction bids pursuant to MST Section 4.2.1.1) on the day prior to the Dispatch
Day for the full commitment period.
By 11:00 a.m. on the day prior to the Dispatch Day, the ISO shall complete the Day-Ahead
scheduling process and post on the Bid/Post System the Day-Ahead schedule as per section
4.2.5 of the Market Services Tariff. LBMPs are posted on the Bid/Post System as public
data and commitment schedules are posted on the Bid/Post System as private data.
2-4
NYISO Energy Market Operations
Version 4.4
10/28/2016
NYISO DAY-AHEAD SCHEDULING MANUAL
Day-Ahead bids are locked for the Day-Ahead period while under evaluation and when
accepted. Bids may be left standing or withdrawn if not accepted. Standing bids may be
used in Supplemental Resource Evaluation (SRE).
In accordance with section 4.2.4 of the Market Services Tariff, each day a reliability study
is run over the seven (7)-day period that begins with the next Dispatch Day. This study
evaluates if resources with longer start-up times are required to meet forecasted Load and
reserve requirements. Units that are committed are guaranteed a minimum generation bid
cost recovery pursuant to the provisions of Attachment C of the Market Services Tariff.
2.3
Day-Ahead Functional Components
The following figure shows the interaction and data flow between the various functional
components that involve the Day-Ahead process. Each of the blocks and major data flows
is described after the figure.
Automatic
Generation
Control
(AGC)
Weather
Forecast
Day-Ahead
Automated
Mitigation Process
NYISO Load
Forecast
Reserve &
Regulation
Requirements
4
Eligible
Customer
1
Bid/Post System
(BSYS)
SCUC & Non-Firm
Transaction
Interchange
Scheduler (IS+)
1
Real-Time
Commitment
(RTC)
OASIS
Billing &
Accounting
System (BAS)
Historical
Information
Retention
Outage Scheduler
(OS)
2
3
2
4
4
4
No.
Other NYISO Manuals
1
2
3
4.
MPUG
Accounting & Billing Manual
Outage Scheduling Manual
Transmission & Dispatching
Operations Manual
3
Figure 2-3: Day-Ahead Scheduling Data Flow
2.3.1
Primary Functions
The following is a brief summary of each primary function block (solid line) shown in
Figure 2-3:
NYISO Energy Market Operations
Version 4.4
10/28/2016
2-5
NYISO DAY-AHEAD SCHEDULING MANUAL
Weather Forecast – The Load Forecast function retrieves weather forecast data from the
Weather Forecast data file maintained from data received from the weather service.
Load Forecast (LF) – The Load forecast function is used by the NYISO to forecast loads
for each Zone in the NY Control Area. The LF function uses historical load and weather
data information for each Zone to develop forecast models. These models are then used
together with Zonal weather forecast to develop a NYISO-based Zonal load forecast for the
next seven days. This forecast is used in the reliability passes in SCUC.
Reserve & Regulation Requirements – The following requirements are passed on to the
SCUC program:
 Operating Reserve requirement for each category
 Regulation requirement
Bid/Post System (BSYS) – See NYISO OATT Section 1 Definitions and Section 3 this
manual.
Functionally, the Bid/Post System allows Market Participants to review results of the DayAhead and Real-Time scheduling and dispatch processes including accepted and rejected
bids, generation schedules, and clearing prices. Confidential data is restricted to those
entities that have authorized access.
The Bid/Post System provides the Day-Ahead scheduling information to the Real-Time
Scheduling Subsystems.
Security Constrained Unit Commitment (SCUC) – The SCUC produces the generating
unit commitment schedule and Firm Transaction schedules for the next day’s operation.
Factors considered by SCUC are:
 Current generating unit operating status
 Constraints on the minimum up and down time of the generators
 Generation and start up bid prices
 Plant-related startup and shutdown constraints
 Minimum and maximum generation constraints
 Generation and reserve requirements
 Transmission facility maintenance schedules
 Transmission constraints
 Phase angle regulator settings
 Transaction bids
Non-Firm Transactions Evaluation – These transactions are not willing to pay congestion
charges and therefore, they will not be scheduled if there is congestion. If there is no
congestion these transactions are scheduled in NERC priority sequence within the
Available Transfer Capabilities of the NYS Transmission System.
2.3.2
Supporting Functions
The following is a brief summary of each supporting function block (dashed line) in Figure
2-3.
2-6
NYISO Energy Market Operations
Version 4.4
10/28/2016
NYISO DAY-AHEAD SCHEDULING MANUAL
Historical Information Retention – Data required for archiving, billing and accounting, as
well as information required to support auditing, is saved. Data that is stored includes
results of the Day-Ahead scheduling study, interchange schedule information, RTD
calculated base points for every dispatch execution, equipment outage schedule
information, zonal marginal prices, transmission rights information, actual reserves and
reserve requirements, and actual system conditions.
OASIS – See the NYISO Market Participant User’s Guide (available from the NYISO Web
site at the following URL:
http://www.nyiso.com/public/markets_operations/documents/manuals_guides/index.jsp) for
details.
Billing & Accounting System (BAS) – The BAS function itemizes those data elements
stored or generated by the various subsystems so that line item settlement statements can be
calculated after the fact on a monthly basis. Billing information is limited to those market
systems that are in place for the initial LBMP implementation. Data is captured for every
dispatch cycle and saved for off-line calculation of pertinent billing information. All
consolidated billing information is stored in the historical archives for subsequent
processing. See the NYISO Accounting and Billing Manual (available from the NYISO
Web site at the following URL:
http://www.nyiso.com/public/markets_operations/documents/manuals_guides/index.jsp) for
details.
Outage Scheduler (OS) – The Outage Scheduler function is used by the NYISO to keep
track of scheduled equipment outages in the NY Control Area. The OS provides a user
interface for entering equipment outage schedules, as well as reviewing existing schedules.
Additionally, the OS records the actual status changes of the network equipment regardless
of whether its status change was scheduled. See the NYISO Outage Scheduling Manual
(available from the NYISO Web site at the following URL:
http://www.nyiso.com/public/markets_operations/documents/manuals_guides/index.jsp) for
details.
Automatic Generation Control (AGC) Function– The AGC monitors the SCADA
database for the on-line status of generating units and, when generating, the on/off status of
their Automatic Voltage Regulator (AVR) equipment. It also monitors control performance.
See NYISO OATT Section 1 Definitions. Also see the NYISO Transmission & Dispatching
Operations Manual (available from the NYISO Web site at the following URL:
http://www.nyiso.com/public/markets_operations/documents/manuals_guides/index.jsp) for
details.
Interchange Scheduler (IS+) – The IS+ function allows NYISO personnel to monitor
ongoing energy transactions. These transactions are bids accepted in either the Day-Ahead
scheduling process or the Real-Time scheduling and dispatch process. This program
provides facilities for reviewing existing transaction information and for adjusting
transactions in real-time to address security problems. The IS+ function produces the NY
Control Area Desired Net Interchange (DNI). See the NYISO Transmission & Dispatching
Operations Manual (available from the NYISO Web site at the following URL:
http://www.nyiso.com/public/markets_operations/documents/manuals_guides/index.jsp) for
details.
NYISO Energy Market Operations
Version 4.4
10/28/2016
2-7
NYISO DAY-AHEAD SCHEDULING MANUAL
Real-Time Commitment (RTC) – After the Day-Ahead schedule is published and no later
than 75 minutes before each hour, Customers may submit Real-Time Bids into RTC for
real-time evaluation. The Day-Ahead scheduled transactions and the candidate Real-Time
transactions are evaluated to assure that the interface Total Transfer Capability (TTCs) are
respected. In addition, candidate External transactions are evaluated for LBMP economics
against their decremental bids. See NYISO OATT Section 1 for definition. See the NYISO
Transmission & Dispatching Operations Manual (available from the NYISO Web site at
the following URL:
http://www.nyiso.com/public/markets_operations/documents/manuals_guides/index.jsp) for
details.
2.3.3
Data Flow
The following is a brief description of the data flow between the various Day-Ahead
functions.
Bid Information – The Bid information that is passed to the Bid/Post System from the
Market Participants is listed in the NYISO Market Participant User’s Guide.
Posts Billing Information – The Bid/Post System is required to pass all schedules, pricing,
and results to the Billing & Accounting System, on a daily basis.
Posts User Activities – All user access to the Bid/Post System function is logged and stored.
Any data items entered or changed with the associated timing information, are stored for
future tracking and auditing purposes. A complete duplicate of Bid/Post System
information is retained.
Security Constrained Unit Commitment – The SCUC saves the hourly output of each
generator for energy, reserves, and regulation.
Bid/Post System to SCUC – The SCUC program requires all of the validated bid
information from the Bid/Post System. External Transactions are treated in the base case as
generators and loads.
Automated Mitigation Process (AMP) – Automated mitigation relies on a second SCUC
evaluation pass to assess the impact of mitigation; and a third SCUC pass to produce a final
schedule. Thus, three SCUC pass evaluations are required. The first, pass 1A, determines
the prices and schedules that would occur with the original set (Base-Set) of bids and offers.
The second, pass 1B, determines the prices and schedules that would occur with conduct
failing bids replaced with reference bids (Ref-Set). Differences between Base-Set and RefSet are used to determine price impact. The third Unit Commitment, pass 1C, determines
final prices and schedules using mitigated bids and offers (Mit-Set) when both conduct and
impact warrant mitigation.
Reserve and Regulation Requirements – The SCUC function obtains the following hourly
requirements for NYCA, Eastern New York, Southeastern New York and/or Long Island
from the Energy Management System:
 Spinning 10-minute reserve
 Total 10-minute reserve (includes the spinning 10-minute reserve)
 Total operating reserve (includes the total 10-minute reserve and 30-minute reserve)
2-8
NYISO Energy Market Operations
Version 4.4
10/28/2016
NYISO DAY-AHEAD SCHEDULING MANUAL

Regulation capacity
AGC to SCUC – The AGC function prepares a list of information that contains every
generator and its last change of state.
Bid/Post System to Interchange Scheduler – The Bid/Post System function provides
evaluated transactions to the IS Plus function.
SCUC to Bid/Post System – SCUC data is provided to the Bid/Post System, which then
passes the information on to the Real-Time Commitment (RTC).
NYISO Energy Market Operations
Version 4.4
10/28/2016
2-9
NYISO DAY-AHEAD SCHEDULING MANUAL
This page intentionally blank.
2-10
NYISO Energy Market Operations
Version 4.4
10/28/2016
NYISO DAY-AHEAD SCHEDULING MANUAL
3.
B ID /P OST S YSTEM
This section describes the Bid/Post System and its interfaces to other functions. See NYISO
OATT Section 1 Definitions.
3.1
Bid/Post Functions
The Day-Ahead scheduling process begins when the Eligible Customers submit their Bids
through the Bid/Post System. Eligible Customers provide bidding information to the
NYISO for generation, load, and transactions; and review the posted results such as
accepted bids, generation schedules, and clearing price information.
The primary data exchanges of the Bid/Post System for the Day-Ahead scheduling function
include the following:
 Eligible Customers enter Day-Ahead bids
 NYISO posts accept/reject information of bid data for Day-Ahead scheduling.
 NYISO posts marginal pricing information
 NYISO posts historical results (limited capability)
 NYISO posts the list of generators that are committed for reliability under
Operational Announcements on the ISO website
 NYISO posts current operating parameters in the hour of use
 Market participants review and revise operating information
NYISO posts audit trail of information by user and time stamp.
3.2
Bid/Post Process
The following classifications of data exist for the Bid/Post System:
 Generator, LSE, and Bus Data (Private)
 Bid Data (Private)
 Posted Schedules/Other (Private)
 Posted Prices/Other (Public).
For consideration of confidential information, the first three types of data have access
limited to registered Market Participants who have a right to review such information. The
fourth type of data is accessible to all the registered users of the Bid/Post System.
Data Classifications
Detailed data tables of each parameter of the four data types are included in the NYISO
Market Participant Users Guide.
 Generator, LSE, and Bus Data – Certain unit information such as upper operating
limits, minimum generation levels, and normal and emergency response rates require
NYISO confirmation to become valid. The parameters, to be entered by the NYISO
into the Bid/Post System, may require supporting information such as certification
NYISO Energy Market Operations
Version 4.4
10/28/2016
3-1
NYISO DAY-AHEAD SCHEDULING MANUAL










3-2
and testing. The NYISO provides status flags for the unit indicating what types of
bids the unit has been qualified to submit.
LSE information required is similar to the ownership requirements of a generator and
is supplied by a LSE's designated administrator and the NYISO. The NYISO
provides the bus, sub-zone, and Zone identifications for the LSE territory, which the
LSE serves.
Bus data includes information supplied by the NYISO, including reference names,
numbers, sub-zone, Zone, and other designations used by Market Participants to
identify a bus.
Almost all of the above data is considered static, in that it is not expected to change
frequently and certain pieces require different levels of NYISO certification or user
verification to enter and change.
Bid Data – LBMP Market Participants enter bid data parameters for generators,
External Transactions, and load for the Day-Ahead Market. Users may change data
already validated or submit new data for validation up to the close of the market
period when evaluation of validated bids starts. Authorized users have the capability
to review and modify current operating parameters (Real-Time Market) in the hour
of use.
Bid data includes timing information such as when a bid becomes valid and when it
expires.
Posted Schedules/Other (Private) – The sets of schedules and prices posted under
LBMP result from SCUC and RTS. As schedule information is considered
confidential in nature, only registered users with authorization have the right to
review their schedules or rejection notices associated with their bids.
In general, after completion of the Day-Ahead scheduling process; generation
schedules, load forecasts, day-ahead LBMP prices (including congestion and loss
components) for each load zone in each hour of the upcoming day, and scheduled
External Transactions are posted to bidders.
In RTC, updated load forecasts, and additional External Transactions are evaluated.
In the Bid/Post System, generator schedules are posted and LBMP bus prices
calculated by RTC for the next hour are advisory in nature only. Prices used in
billing are determined in the real-time market by RTD. RTC posts accepted External
Transactions for the next hour also.
Posted Prices/Other (Public) – Data that is posted as public implies that any user of
the Bid/Post System is able to access the information (unregistered users do not have
access to the Bid/Post System).
The bus and zonal LBMP prices are posted after Day-Ahead commitment, after
RTC, and hourly RTD results. Clearing prices for reserves are posted, and advisory
NYISO load forecasts are also posted. The Bid/Post System retains this information
for Market Participant review for a specified period of time (initially, 15 days). After
expiration of the time interval, the Bid/Post System audit data will be only accessible
through the Historical Information System. The daily Bid Production Cost Guarantee
(BPCG) in aggregated total dollars from both the Day Ahead and Real-Time Markets
is posted as Public Data.
NYISO Energy Market Operations
Version 4.4
10/28/2016
NYISO DAY-AHEAD SCHEDULING MANUAL

The Bid/Post System provides capability for issuing general messages from the
NYISO, such as when the NYISO is performing a supplemental commitment.
Validity Checks
The data submitted to the Bid/Post System is checked for validity with bidder notification
that a bid has been validated as soon as possible. If a bid is rejected because part of the data
is not valid, a posting for the bidder indicates the problem and gives an opportunity to
resubmit a modified bid providing the market has not closed.
Bid validity is broken into the following different types of validation checks:
 Ownership (O) – Ownership recognizes the bidder as having the authority to bid a
particular service, such as owner of a generating plant bidding energy services.
 Completeness (C) – Completeness indicates that the bidder has entered all the
required parameters for a particular bid to be evaluated, such as regulation bids
providing regulation response rate, available capacity, and dollars per MW
availability.
 Individual Data Checks (I) – Individual data checks look at constraints placed on
individual data parameters either universally applied to a given field or constrained
by qualification data, such as upper operating limit (energy bid) not exceeding the
maximum operating limit of a unit.
 Relationship (R) – Relationship checks look at the interdependence of certain
parameters supplied to the Bid/Post System.
 Special Relationship (SR) – Special relationship checks look at bid parameters
relative to other parameters that have not been supplied with a particular bid, such as
External Transaction waiting for other party confirmation, or real-time energy
market bid price not exceeding Day-Ahead bid for portion committed.
 Prohibited Transmission Paths – Prohibited transmission paths checks filter out
External Transaction schedules submitted over the eight prohibited circuitous
scheduling paths. See OATT Attachment J, Section 16.3.3.8 for definitions of those
scheduling paths.
Notifications
There are many different types of notifications that the Bid/Post System provides to users
concerning the status of a particular bid. The currently defined notifications are as follows:
 Validation – Data entered through the Bid/Post System is identified as being either
validated, rejected with message indicating why rejected, or a status of the validation
process. For validated bids the status message is VALIDATION PASSED. For
invalid bids the status indication is VALIDATION FAILED, with a message
indicating reason for failure, such as one of the validation rules. The status of the
validation process is only used in a special case and discussed as the next type of
message notification.
 Confirmation – When the validation process cannot be continued because
information is needed that is not submitted with part of a particular bid (e.g. certain
Special Relationship checks), the indication would be WAITING
CONFIRMATION. Confirmation messages identify the organization required to
NYISO Energy Market Operations
Version 4.4
10/28/2016
3-3
NYISO DAY-AHEAD SCHEDULING MANUAL


supply the necessary information needed for the validation process such as
confirmation of an External Transaction. It is important to note that some of the
Special Relationship checks, performed during the Day-Ahead and Real-Time
Commitment evaluation periods, are not considered part of the validation procedure.
Rather, these are identified as acceptance criteria and used with acceptance
notification. For a bid or offer to be evaluated by Day-Ahead or Real-Time
Commitment, it must have a status of VALIDATION PASSED.
Acceptance – During the time that the NYISO is using bids to perform commitment
or real-time market evaluation, the status of a bid is shown as EVALUATING. After
evaluation is complete, the results are posted and the status of the bid is tagged as
BID ACCEPTED, MODIFIED, CONDITIONALLY ACCEPTED, BID
REJECTED, or ADVISORY ACCEPTED. In the event that a supplemental resource
evaluation is required, bids that have not reached expiration time will be considered
available for evaluation and will not be allowed to expire. For example, a bid to
supply energy is due to expire at 11:00 p.m. The NYISO begins an SRE at 10:40
p.m. to address an energy concern at 07:00 a.m. the following day. The bid would be
utilized in the SRE evaluation.
Result Posting – All accepted bids will have resulting schedules posted. The
Bid/Post System clearly identifies bids that have forward contracts and those that are
advisory. Included in the results posting is the ability for the user to review the past
bids and results for Day-Ahead Unit Commitment, supplemental unit commitments,
Real-Time Commitment, and actual operating results for a specified period of time.
Tracking & Auditing
Tracking and auditing serves the NYISO and the Market Participants. All information in the
Bid/Post System is retained for auditing purposes. Limited information from the Bid/Post
System on past bids and results is available to the Market Participants. All inserts, updates,
and deletions to the Bid/Post System are tagged with date, time, and user identification. The
audit trail is provided with table log files.
User Interface
Not all Market Participants have the same capabilities and needs for interfacing with the
Bid/Post system. In order to provide convenient interface options, a number of methods for
supplying data and also for reviewing results are supported. The following describes these
interface methods.
 World Wide Web – The Bid/Post System is accessible through public Internet Web
pages, utilizing hardware and software similar to that used for the OASIS System.
Market Participants are able to submit data and review postings through Web pages
using this method.
 Upload/Download – Upload and download file capabilities are provided to Market
Participants, utilizing hardware and software similar to that used for OASIS. File
formats or templates for these files are supplied to Market Participants.
3-4
NYISO Energy Market Operations
Version 4.4
10/28/2016
NYISO DAY-AHEAD SCHEDULING MANUAL
3.3
Bid/Post Interfaces
The data exchange for each application is outlined as follows.
3.3.1
SCUC
The SCUC program has all the validated bid information when the Day-Ahead market
closes. The schedules resulting from Unit Commitment are sent back to the Bid/Post
System. The Bid/Post System and SCUC exchange information bi-directionally.
3.3.2
Interchange Scheduler
The Bid/Post System sends approved transactions to the IS+ package. When there is a
change in transactions the IS+ updates the Bid/Post System.
3.3.3
Real-Time Scheduling
The Real-Time Scheduling requires all new market bid information from the Bid/Post
System and approved schedules from SCUC. The results of RTS are sent back to the
Bid/Post System. Data exchange is bi-directional between the Bid/Post System and RTS.
3.3.4
Performance Tracking System
The Performance Tracking System provides hourly performance measurements to the
Bid/Post System. When available, Data exchange is uni-directional from the PTS to the
Bid/Post System.
3.3.5
Billing & Accounting System
The Bid/Post System is required to pass all schedules, pricing, and results to the Billing &
Accounting System. Data exchange is uni-directional from the Bid/Post System to the BAS.
The Billing & Accounting (BAS) function itemizes those data elements stored or generated
by the various subsystems, from which line item settlement statements are calculated. Refer
to the NYISO Accounting & Billing Manual (available from the NYISO Web site at the
following URL:
http://www.nyiso.com/public/markets_operations/documents/manuals_guides/index.jsp) for
a detailed description.
3.3.6
Historical Information Retention
All relevant Bid/Post System information is saved.
3.3.7
OASIS
Refer to the NYISO Market Participant User’s Guide for a description of the interface.
NYISO Energy Market Operations
Version 4.4
10/28/2016
3-5
NYISO DAY-AHEAD SCHEDULING MANUAL
This page intentionally blank.
3-6
NYISO Energy Market Operations
Version 4.4
10/28/2016
NYISO DAY-AHEAD SCHEDULING MANUAL
4.
D AY-A HEAD S CHEDULING P ROCESS
This section focuses on the Day-Ahead scheduling process for the LBMP implementation. The
Day-Ahead scheduling process establishes Day-Ahead schedules including External Transaction
schedules. This is accomplished by the following procedures:
 Assembly of the Day-Ahead outages
 Production of a preliminary NYISO zonal load forecast
 Execution of SCUC
 Tabulation and evaluation of transactions.
4.1
Day-Ahead Inputs & Outputs
Inputs to Day-Ahead Scheduling
The primary inputs to the Day-Ahead scheduling process are:
 Transmission outage list from the Energy Management System (EMS)
 Weather forecasts
 Load forecast model
 Validated firm External Transaction requests from the Bid/Post System (converted to
generation and load)
 Operating Reserve and Regulation requirements from the EMS
 Validated Day-Ahead generator bid data from the Bid/Post System
 Validated Day-Ahead load bids from the Bid/Post System
 Price capped load bids from the Bid/Post System
 Validated non-firm External Transaction requests from the Bid/Post System
 Validated virtual generation and virtual load bids from the Bid/Post System
 Lake Erie circulation assumptions
Outputs from Day-Ahead Scheduling
The primary outputs from the Day-Ahead scheduling process are:
 Updated Total Transfer Capabilities (TTCs) posted on OASIS
 Firm and Non-Firm Available Transfer Capabilities (ATCs) posted on OASIS
 PAR Flows posted on OASIS
 Day-Ahead Limiting Constraints posted on OASIS
 Commitment schedule for generation and load resources, operating reserves,
regulation, External Transactions and bid load posted on the Bid/Post System for
First Settlement
 Market Clearing Prices for operating reserves and regulation posted on the Bid/Post
System
 First Settlement LBMPs posted on the Bid/Post System
NYISO Energy Market Operations
Version 4.4
10/28/2016
4-1
NYISO DAY-AHEAD SCHEDULING MANUAL

4.2
Zonal load forecast posted on the Bid/Post System.
SCUC Initialization
The next subsections describe the initialization that is performed in preparation for SCUC.
4.2.1
Day-Ahead Zonal Load Forecast
The NYISO prepares a Day-Ahead zonal load forecast. This NYISO forecast is
independent of the LSEs’ forecast. The procedure for NYISO forecasting is as follows:
 Retrieval of actual and historical weather data and weather forecasts obtained from
the weather service
 Retrieval of historical load data
 Execution of the load forecast program
 Transferring of the NYISO load forecast data for use by SCUC.
4.2.2
Assemble Day-Ahead Transmission Outages
The outage process for transmission facilities involves the following procedures:
 Transfer of the transmission outages from the EMS
 Preparation of the updated SCUC model, which is used by the SCUC function.
4.2.3
Initial Generator Status and Commitment Rules
The Automatic Generation Control System produces a list of actual generator start and stop
times and dates. This start and stop information is transferred for use by the SCUC process.
In preparation for the start of a unit commitment study, the SCUC input processor updates
generating unit statuses.
Initialization Status
When SCUC initializes at 05:00 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.
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.
4-2
NYISO Energy Market Operations
Version 4.4
10/28/2016
NYISO DAY-AHEAD SCHEDULING MANUAL
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.
Minimum Run Time
In SCUC, the minimum run time is honored within the 24-hour evaluation period only;
requirements across midnight are not recognized (except to the extent they are reflected in a
late day start Bid). A unit must bid appropriately to enable commitment in the next day.
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.
4.2.4
Scheduling a “Must Run” Generator
There is no such thing as a “Must Run” generator. To improve the chances that a generator
is scheduled into the market, it must be offered such that it is positioned at the bottom of the
economic bid curve.
A generator that desires a commitment to operate might not be scheduled due to system
constraints or reliability rules. For example, if a set of generators are running to meet a
particular load and all the generators are operating at their minimum generation level, then
no other generator would be started, even if the new generator is otherwise economic (less
costly, on an incremental basis, than the generators that are already operating). Also, if a
generator is constrained for transmission security, then it may not be scheduled to run, or it
may be scheduled at a reduced amount, by Security Constrained Unit Commitment (SCUC)
and Real-Time Commitment (RTC). To increase the probability that a generator will be
scheduled into the market, it must be bid at the bottom of the economic dispatch curve. The
following presents a few simple guidelines to increase the chances otherwise available that
a generator would be economically scheduled.
Bid a “Start-Up Cost” of Zero Dollars
Market Participants may enter zero dollars into the “Start-Up Cost ($)” field on the
Generator Bid screen in the MIS. This will prevent the SCUC or RTC from considering
start-up cost.
Submit a Low Minimum Generation Bid
SCUC and RTC minimize total production costs over their respective evaluation periods.
The Minimum Generation Costs are factored into this evaluation; therefore a low value in
this field will increase the likelihood that the unit will be scheduled to run based on
economics.
Submit a Low Incremental Energy Bid
The dispatch curve is used between the minimum and upper operating points to dispatch the
unit. If not the marginal unit, a generator will receive the higher Locational Based Marginal
NYISO Energy Market Operations
Version 4.4
10/28/2016
4-3
NYISO DAY-AHEAD SCHEDULING MANUAL
Price at its bus, regardless of itits bid. If many generators are vying for a “must-run”
schedule within an area, a negative bid may prove necessary to be scheduled, especially if
others are bidding negative. However, when bidding a negative value, the generator risks
setting the price and having to pay to operate. Also, the SCUC and RTC software minimize
production costs over multiple hours, so all hours must be strategically bid together. For
example, the hourly bids of a unit would be evaluated over all the hours that it could be
scheduled, given its minimum run time or down time constraints.
Use Appropriate Static Generator Parameters
In the SCUC Day Ahead Market, all static generator parameters are used based on the
unit’s initialization. Generators that bid into the non-synchronous reserve market will not
have their unit scheduled for energy if their bid is accepted in the non-synchronous reserve
market. The generator may change this value by going to the Generator Commitment
Parameters in the Market Information System.
Outage Schedule Utilization
In addition, a unit must not be listed in the NYISO Outage Scheduler as an outage or a
deration, since this will override the bid values and will prevent RTC from scheduling the
unit above its reduced maximum output. If a unit is no longer on forced shutdown or
derated, the generator must notify their Transmission Owner, who will then notify the
NYISO operator. Notice must be given 75 minutes prior to an hour for RTC to evaluate the
unit.
Submit a Bid in Self-Committed Fixed Mode
By submitting a bid in Self-Committed Fixed mode, a unit will be dispatched to the level
indicated in the bid, subject to system security. Although submitting a bid in SelfCommitted Fixed mode cannot guarantee the commitment of a unit, there is a high
possibility that the unit will be committed in SCUC. However, a unit bidding as SelfCommitted Fixed is not eligible to submit any cost curve, so it can be scheduled regardless
of the low LBMP it will get paid.
4.2.5
Multiple Response Rates for Generating Units
Each generation unit modeled in the Market Information System (MIS) may specify up to
five response rates. Three response rates are available for following basepoints in the
energy market, the emergency response rate is available for providing operating reserve
pick-up, and the regulating capacity response rate is available for regulation service.
In an effort to encourage generating units to place themselves in Flexible mode, multiple
response rates that more accurately reflect a unit’s response capability may be specified.
The energy and emergency response rates may be specified for up to three energy supply
ranges. For example, the Minimum Generation MW-50MW range may have a 0.2
MW/minute response rate, the 51-150MW range may have a response rate of 8
MW/minute, and the range from 151MW to the maximum upper operating point may have
a response rate of 2.2 MW/minute. Defining the three energy ranges and the response rate
for the ranges is at the discretion of the generator. It is the generator’s responsibility;
4-4
NYISO Energy Market Operations
Version 4.4
10/28/2016
NYISO DAY-AHEAD SCHEDULING MANUAL
however, to ensure that the response rates specified are within the capability of the unit,
provided, however, response rates that differ from those specified in the ISO Tariffs based
on the capability of the unit shall be reviewed and accepted by the NYISO. The NYISO
will maintain the response rates currently shown in the MIS for the unit until the changes
are accepted.
The SCUC and RTC programs, which perform Day-Ahead and Real-time scheduling
calculations respectively, use the explicit response rates for each megawatt segment.
Regulation bids must be structured such that the unit’s specified capacity response rate is
valid for the bid submitted. For example, a regulation capacity bid of 30MW must be
supported by a regulation capacity response rate of 6 MW/minute over the 5-minute RTD
interval to fully comply with regulation provider responsibilities. The regulation capacity
response rate must not be slower than the slowest energy or emergency response rate.
The emergency response rate specified for a unit will be used during a reserve pickup
condition when RTD-CAM moves the unit towards its emergency upper operating limit.
Neither the emergency response rate nor the regulating response rate will be used as
additional energy response rates in any dispatch other than that.
The three energy response rates and the emergency response rate must be specified in
increments such that they will result in an integer MW amount over an RTD interval. In
other words, response rates with an odd decimal place (i.e. .1, .3, .5, .7, or .9) are not
allowed. The minimum response rate allowed for energy and the emergency response rate is
0.2 MW/minute. The minimum capacity response rate allowed for regulation is 1
MW/minute.
Market Participants interested in specifying multiple energy response rates for a generating
unit(s) must set this up by contacting their Stakeholder Services Representative.
4.2.6
Day Ahead Reliability Unit (DARU) Commitment
Background
Transmission Owners regularly request that the NYISO commit additional resources to
meet the reliability needs of their local systems. Recent changes allow the NYISO to
commit these resources in the Day-Ahead Market when notified of the need to do so by the
Transmission Owners. Since a Day-Ahead commitment of these resources produces a more
efficient commitment than a commitment following the Day-Ahead market run,
Transmission Owners should notify the NYISO of the need for these resources by 01:00
a.m. prior to the Day-Ahead Market close, to allow for input into the system (e.g., a request
for Saturday must be communicated to the NYISO by 01:00 a.m. Friday). Those units that
the NYISO commits solely for reliability reasons at the request of a Transmission Owner or
for statewide reliability needs as initiated by NYISO, are known as Day-Ahead Reliability
Units (“DARU”).
Transmission Owner Requests for DARUs
When requesting the commitment of a reliability-necessary unit for the Day-Ahead market,
TOs must give the NYISO the reliability reason for the request, the expected duration of the
NYISO Energy Market Operations
Version 4.4
10/28/2016
4-5
NYISO DAY-AHEAD SCHEDULING MANUAL
need, and the specific facility or constraint affected. TOs should request a DARU for all
generating units needed for reliability of their local system to ensure against economic
decommitments. NYISO operators will log all such TO requests. (This is consistent with
the requirements that apply to TO SRE requests.) Within 5 business days, the TO
requesting the reliability commitment shall provide detailed written justification for the
DARU request to SREinfo@nyiso.com. The NYISO will review all these requests to ensure
that practices being followed are consistent with NYISO tariffs and NYS Reliability Rules.
The TO's written justification must detail the system conditions that resulted in the need for
the reliability commitment such that the NYISO can independently verify the request. The
following system conditions should be identified when applicable: TO local area or regional
load levels; thermal transmission facility or substation voltage constraint; whether the
constraint represents a predicted pre-contingency or post-contingency violation; significant
transmission or generating unit outages affecting such constraint; and special local
reliability criteria. Any additional local area system conditions that resulted in the need for
the DARU commitment should also be identified.
All requests by TOs to commit generators via the DARU process, as well as NYISOinitiated DARUs, will be posted to the OASIS at the time of Day-Ahead Market close. For
units located in Zone J (New York City), non-binding, advisory postings will be made at
the time of DARU entry, modification, or deletion, in addition to the posting at Day-Ahead
Market close.
An e-mail notification will also be sent to a DARU generator’s contact, as entered in the
Market Information System, when the Day-Ahead Market closes, indicating that the unit
has been requested for Day-Ahead reliability. For units located in Zone J (New York City),
a supplemental process will be used whereby a non-binding, advisory e-mail will be sent
for every creation, modification, or deletion of a DARU entry by NYISO Operators. The
Generator’s contact may reach out to the requesting TO when there are constraints
preventing the unit from being able to meet the commitment requested. If there are issues
with TO communication, the Generator’s contact may also reach out to inform the NYISO
Grid Operations Department regarding the constraints.
NYISO Processing of Day-Ahead Reliability Unit Requests
SCUC optimizes offers and bids over the dispatch day to preserve system reliability and
ensure that sufficient resources are available to meet forecasted load and reserve
requirements. When a Transmission Owner notifies the NYISO of the need for a reliability
unit, SCUC will first evaluate the generator for possible economic commitment. If
economic, the unit’s commitment will not be considered a reliability commitment.
Commitment for reliability reasons renders the unit a DARU. A DARU request by a
Transmission Owner or by the NYISO may override a generator's startup notification time.
4.2.7
Phase Angle Regulator Scheduling
Phase Angle Regulators (PARs) are scheduled in SCUC as follows:
1. Except for the conditions listed in Item #2, #3, #4 and #5 below, Day-Ahead PAR
schedules to be input into SCUC will match the previous like day schedule for each
PAR internal to or bordering the NYCA.
4-6
NYISO Energy Market Operations
Version 4.4
10/28/2016
NYISO DAY-AHEAD SCHEDULING MANUAL
2.
3.
4.
5.
6.
4.3
If PAR scheduling changes are anticipated or maintenance facility outages are
scheduled which affect PAR operation, Day-Ahead PAR schedules to be input into
SCUC are modified in accordance with published contractual agreements and/or
operating procedures.
PARs that have been designated to be under NYISO operational control are
optimized by SCUC along with other resources. The optimization allows
adjustments to the original schedules of the PARs to help relieve energy
transmission into congested areas.
The desired flows will be established for the ABC, JK, and 5018 interconnections
based on the following, pursuant to OATT Section 35, Attachment CC – JOA
Among and Between NYISO and PJM, Schedule C and Schedule D:
•
The ABC interconnection will be scheduled on the Consolidated Edison
Company of New York’s Day-Ahead Market hourly election for the
“600/400MW Contracts” plus 0% of PJM-NYISO Day-Ahead Market
hourly interchange
•
The JK interconnection will be scheduled on the Consolidated Edison
Company of New York’s Day-Ahead Market hourly election for the
“600/400MW Contracts” plus 0% of PJM-NYISO Day-Ahead Market
hourly interchange
•
The Hopatcong-Ramapo interconnection will be scheduled to carry 40% of
the PJM-NYISO hourly interchange. The Hopatcong-Ramapo 500kV
Operating agreement allows for the assumption that up to 61% of PJM-NY
transaction schedules flow over the 5018 interconnection. However, flows
over the 5018 interconnection will be conservatively modeled at 40% to
ensure feasible operating schedules. In any case, the schedule on HopatcongRamapo interconnection will not exceed the rating of 5018. The desired flow
scheduled over the Hopatcong-Ramapo interconnection may be adjusted by
an offset MW value to reflect expected operational conditions.
The Northport PAR which is in series with the 1385 Northport-Norwalk Harbor
transmission facility has been superseded by the 1385 Proxy bus in the scheduling
systems.
PAR Schedules to be input into SCUC and SCUC results are posted by the NYISO.
Security Constrained Unit Commitment
The SCUC function is used in the LBMP implementation to produce the generating unit
commitment schedules, reserve and regulation market schedules, and firm transactions
schedules for the First Settlement.
4.3.1
SCUC Stages
The intent of SCUC is to develop a schedule using a computer algorithm that
simultaneously minimizes the total Bid Production Cost of:
1. Supplying power to satisfy all accepted purchasers' Bids to buy Energy from the
Day-Ahead Market.
NYISO Energy Market Operations
Version 4.4
10/28/2016
4-7
NYISO DAY-AHEAD SCHEDULING MANUAL
2.
3.
4.
5.
Providing sufficient Ancillary Services to support Energy purchased from the DayAhead Market.
Committing sufficient Capacity to meet the NYISO's Load forecast and provide
associated Ancillary Services.
Committing sufficient Capacity to meet the NYISO's Load forecast and Local
Reliability Rule requirements.
Meeting all Bilateral Transaction schedules submitted Day-Ahead.
To meet the above requirements, the SCUC algorithm is designed as a multiple pass
process in which two security constrained commitment passes and two security constrained
dispatch passes are executed in sequence as follows:
Pass #1 – Bid Load, Virtual Load, and Virtual Supply Commitment
The first pass of SCUC commits and schedules generating units, including units nominated
to be Day Ahead Reliability Units, to supply Bid Load (Physical and Virtual) less Virtual
Supply while securing the bulk power transmission system. The system is secured against
the normal NYISO bulk power system contingency set so that monitored facilities do not
become overloaded. Also, the program secures for certain Local Reliability Rules
contingencies and monitored facilities.
Once this commitment run has converged, the automatic mitigation evaluation is
performed, including a recommitment/redispatch. This commitment/dispatch is evaluated
by security analysis. Additional iterations of unit commitment with bids and security
analysis are performed until convergence is again achieved.
Pass #2 – Bulk Power System Forecast Load Commitment
The next pass commits any additional units that may be needed to supply the forecast load.
Load bids (physical and virtual) and Virtual Supply bids are not considered in Pass #2. At
the beginning of this pass, generator limits and commitment statuses are modified to ensure
that the units selected in Pass #1 will not be de-committed or dispatched below their Pass
#1 value. Generating units selected in Pass #1 may be dispatched higher, and additional
units may be committed and dispatched. Since Pass #2 is used to assure that sufficient
capacity is committed to supply forecast load it considers only incremental uplift costs and
does not consider energy costs when determining additional commitments. Pass #2 also
secures the bulk power system. In Pass #2, only the wind energy forecasts are used for
scheduling intermittent resources that depend on wind as their fuel.
Pass #3 – Reserved for future use
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 capacity) 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.
4-8
NYISO Energy Market Operations
Version 4.4
10/28/2016
NYISO DAY-AHEAD SCHEDULING MANUAL
Pass #5 – Bid Load, Virtual Load and Virtual Supply Redispatch
In Pass #5, the final dispatch is determined to supply the bid load, virtual load and virtual
supply (where virtual supply is treated as negative virtual load) and is limited by the
constraint set produced in the Pass #1 commitment. The quick start units selected in the
forecast pass are not dispatched Day-Ahead.
Figure 4-1: Multi-Pass Solution Process
Forecast Required Energy for Dispatch (FRED)
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 Energy Market Operations
Version 4.4
10/28/2016
4-9
NYISO DAY-AHEAD SCHEDULING MANUAL
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 import transaction schedules.
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 is selected by SCUC. Non-committed suppliers selected to provide
FRED are 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:
1. Supplier is guaranteed recovery of its start-up bid price and minimum generation
bid price bid through the remainder of the dispatch day subject to mitigation as
appropriate.
2. Supplier may set and is paid the Real-Time Energy LBMP for actual energy
supplied. No availability is paid for FRED.
As is the case for all Real-Time energy suppliers including FRED, an applicable NYISO
penalty is assessed to FRED suppliers for failure to provide energy.
4.3.2
SCUC Components
The SCUC function consists of the following major components:
 Initial Unit Commitment
 Network Data Preparation
 Network Constrained Unit Commitment.
Initial Unit Commitment (IUC)
The initial unit commitment (IUC) function computes the initial unit commitment schedule
based upon:
 The load and generation bid data from the Bid/Post system
 Unit status data derived from the Automatic Generation Control system (AGC)
 Current schedules
 Load forecasts
Bid data is transferred from the Bid/Post system into the RANGER database. This data
includes time stamps associated with the Bid/Post system data. IUC then runs with the
newly loaded database as input and produces the initial unconstrained unit commitment
schedule.
4-10
NYISO Energy Market Operations
Version 4.4
10/28/2016
NYISO DAY-AHEAD SCHEDULING MANUAL
Network Data Preparation (NDP)
The network data preparation (NDP) function provides an automated procedure to set up
the initial conditions and various parameters of power flow cases, i.e., base cases,
corresponding to the specified study period. It also validates the cases by calculating the
power flow solution. A case is acceptable only when its power flow solution is successfully
solved. NDP has the following essential components:
 NPD Controller – successively sets up the NDP case for each time step in the study
and stores the resulting power flow solutions for subsequent processing
 Schedule and Limit Retrieval – for in/out-of-service equipment, and corresponding
breaker statuses
 Network Model Builder – determines the network topology in the form of a bus
model
 Bus Scheduler – sets up the power flow case
 Load – distributes system load to individual buses
 Voltage Regulation – assigned to the regulating devices
 Generation – economic dispatch for units (such as external) that are not considered
in the initial unit commitment
 Dispatcher Power Flow – develops a base case power flow solution to detect data
anomalies and to validate the initial unit commitment schedule.
Network Constrained Unit Commitment (NCUC)
The network constrained unit commitment (NCUC) function calculates a generation
schedule for a specified study period, making sure that both unit commitment constraints
and network security constraints are satisfied. NCUC has the following essential
components:
 NCUC Controller – coordinates the NCUC solution process consisting of the
following iterative steps:
•
Retrieve initial base cases and superimpose schedules from the latest Unit
Commitment (UC) execution
•
Invoke DC Security Analysis (SA)
•
Invoke UC
 DC Security analysis (SA) – evaluates the impact of a set of given contingencies on
the feasibility of the generation schedule
 Unit commitment (UC) – calculates the minimum bid cost schedule of the
generating resources and biddable loads, subject to constraints. The components of
cost include generation, startup, regulation, and reserve which are obtained from the
Bid/Post system. Generation cost includes the effect of transmission loss factors. The
set of constraints include:
•
Generation requirement
•
Reserve requirement
•
Generator operating limits
•
Generator minimum startup and down times
NYISO Energy Market Operations
Version 4.4
10/28/2016
4-11
NYISO DAY-AHEAD SCHEDULING MANUAL
•
Maximum unit shutdowns per day
•
Transmission constraints
•
Transaction schedules.
If the hourly constraints on system generation requirement, reserve, or
transmission do not allow a feasible solution, then UC continues to completion
and reports the source of the infeasibility.
Each UC solution is comprised of an Ideal Dispatch and a Physical Dispatch.
The Ideal Dispatch allows for GTs to be dispatched across their entire
operating range and, therefore, is eligible to set price across their entire
operating range. The LBMPs are determined from this dispatch. The Physical
Dispatch uses blocked bid limits for GTs modeling the physical manner in
which GTs operate. The generation schedules are determined from this
dispatch.
The following modeling features are incorporated within NCUC:
•
Preventive Control Mode – The generation schedule is determined such
that no security violations will occur if any defined contingency occurs.
•
Generator Voltage Control – Generators that are committed are modeled to
regulate voltages within their reactive power capabilities.
•
System Voltage Stability – System voltage stability is handled by imposing
flow constraints on selected branch interfaces, representing the sum of the
megawatt flows across the interface.
•
Infeasibility Handling – When a network security constraint is detected as
infeasible (unable to remove the violation) during the NCUC solution
process, the constraint is relaxed, and solved for, subject to a penalty cost.
Physical generating unit constraints, in contrast, are always enforced.
4.3.3
SCUC Inputs
Production Bid
A production bid is the composite of the incremental energy, minimum generation, startup
and reserve costs as follows:
 Operating Bid – The incremental energy bid for a generator is modeled as a series
of monotonically increasing constant cost steps. These bids are comprised of up to
12 segments. The first segment is determined by the minimum generation cost and
defined by the no-load cost axis intercept ($/hr) and a slope ($/MWh). The 11
incremental energy segments are defined by MW break point and slope ($/MWh)
pairs. Different curves can be input for different schedule days.
 Startup Bid – The startup bid is given by piecewise linear curve of bid versus time
the generator has been off line prior to the start. Different values can be input for
different schedule days.
 Reserve Bid – The regulation bid input for all units that can contribute to regulation,
is given by a regulation available capacity (MW), a regulation capacity cost ($/MW)
and regulation movement cost ($/MW).
4-12
NYISO Energy Market Operations
Version 4.4
10/28/2016
NYISO DAY-AHEAD SCHEDULING MANUAL

For off-line and non-dispatchable generators, the reserve bid is given by a reserve
availability cost ($/MW).
Different costs apply to different reserve types and to reserves from off-line and nondispatchable generators.
Startup and Shutdown Constraints
Multiple Shutdown limits constrain the number of times a generator can shut down in
defined 24-hour periods. The time of day for the start of these periods is input. Shutdowns
that occur at times when a generator becomes unavailable are not counted towards the
multiple shutdown limit constraint. Allowed values for this limit are 0 to 9.
Delivery Factors
The SCUC application uses the Security Analysis (SA) module to generate delivery factors
for each time step in the commitment period. The delivery factors for each time step reflects
the network topology expected for that time period and the generation dispatch from the
Unit Commitment (UC) module.
Losses
Power losses occur in the transmission system as energy flows from generation sources to
the loads. These losses appear as additional electrical load, requiring the generators to
produce additional power to supply the losses. The SCUC, RTC and RTD each employ the
same treatment of physical transmission losses. Transmission losses are calculated as part
of the power flow solution for each time interval simulated by these programs for each of
the eleven load zones in the NYCA.
The load forecast for day-ahead and real-time is determined for demand only and the
calculation of losses within SCUC, RTC, and RTD is added to the forecast for total
scheduling or dispatching requirements. The day-ahead load forecast plus the losses
determined within SCUC are used to determine day-ahead supply resource requirements.
Calculating losses for day-ahead involves the following steps:
1. The day-ahead load forecast estimates eleven zonal loads for each hour of the next
day. The forecast does not include an estimate of zonal transmission losses.
2. Hourly losses for the load zones are calculated within the bid load pass of SCUC.
3. Energy is scheduled in the bid load pass of SCUC to meet (i) the hourly zonal bid
load demands and (ii) the calculated hourly zonal losses for bid load demand.
4. Hourly losses for the load zones are also calculated within the forecast load pass of
SCUC.
5. Energy is scheduled in the forecast load pass of SCUC to meet (i) the hourly dayahead forecast of the eleven zonal loads and (ii) the calculated hourly zonal losses
for forecast load demand.
Reserve Profile
Four reserves are modeled:
 Regulation capacity
NYISO Energy Market Operations
Version 4.4
10/28/2016
4-13
NYISO DAY-AHEAD SCHEDULING MANUAL



10-minute spinning reserve
10-minute reserve (includes 10-minute spinning reserve)
Operating reserve (includes 10-minute reserve and 30-minute reserve)
Only on-line generators can contribute to regulation and spinning reserve. Regulation
capacity available is limited by the regulation capacity response rate, and spinning reserve
is determined by the 10-minute generator response rate. Both on-line and off-line available
generators can contribute to 10-minute and 30-minute reserve.
The contribution to Regulation from all generators and the contribution from nondispatchable and off-line generators depend on their associated input reserve cost bids.
4.3.4
Demand Curves
The unit commitment and dispatch module used in both the SCUC and RTS systems
utilizes demand curves to reflect shortages. The demand curves allow the program to relax
the applicable requirement if the shadow cost needed to supply the requirement exceeds a
preset value. The demand curve functionality is used for the reserve and regulation
requirements and to address transmission constraints:
Type
Demand Curve
Amount (MW)
NYCA
Regulation
25.0
80.0
remainder
$775.00
$25.00
$525.00
NYCA
Spinning Reserve
All
$775.00
NYCA
10 Minute Reserve
All
$750.00
NYCA
30 Minute Reserve
300.0
655.0
955.0
remainder
$25.00
$100.00
$200.00
$750.00
Eastern
New York
(EAST)
Spinning Reserve
All
$25.00
10 Minute Reserve
All
$775.00
30 Minute Reserve
All
$25.00
Spinning Reserve
All
$25.00
10 Minute Reserve
All
$25.00
30 Minute Reserve
All
$500.00
Spinning Reserve
All
$25.00
10 Minute Reserve
All
$25.00
30 Minute Reserve
All
$25.00
Transmission
5.0
$350.00
Southeastern
New York
(SENY)
Long Island
(LI)
All
4-14
Demand
Curve
Price ($)
New York Region
NYISO Energy Market Operations
Version 4.4
10/28/2016
NYISO DAY-AHEAD SCHEDULING MANUAL
20.0
remainder
4.3.5
$2.350.00
$4,000.00
Constraint Breaking
If the hourly resource constraints (i.e., system generation requirement, reserve, and
transmission) specified for a given unit commitment run do not allow a feasible solution,
the program relaxes the constraints in the following order:
1. Regulation and reserve constraints
2. Transmission constraints
3. Interchange ramp constraints
4. System Demand
To achieve a solution, the above constraints are relaxed incrementally in the given order
until a solution can be found. All infeasibilities are reported.
In addition, the generator constraints (i.e., input availability, minimum up and down time
constraints, multiple shut down limit constraints, and ramp constraints) may preclude a
feasible solution. If possible, the program relaxes these constraints in the following order:
1. Low operating limit
2. Multiple shutdown limit
In the event that SCUC is unable to satisfy its security constraints, the NYISO must apply
remedial actions, such as:
 Dispatching generators to emergency upper operating limits
 Cancellation or rescheduling of outages.
4.3.6



4.4
SCUC Interfaces with Other Systems
Bid/Post System – The SCUC function retrieves Bid data from the Bid/Post System
function. Later SCUC provides the Bid/Post System with accepted generator,
transaction, and load bids, clearing prices, etc. This information is also passed on to
the Real-Time Commitment process during the Dispatch Day.
Energy Management System (EMS) – The SCUC function retrieves equipment
outages, reserve and regulation requirements, unit status history and contingency
definition information from the EMS.
Load Forecaster – The SCUC function receives the load forecast for the Day-Ahead
study period from the Load Forecasting program.
Bilateral Transaction Evaluations
Refer to the NYISO Transmission & Dispatching Operations Manual (available from the
NYISO Web site at the following URL:
http://www.nyiso.com/public/markets_operations/documents/manuals_guides/index.jsp) for
a more complete description of Bilateral Transaction Scheduling and Curtailment.
NYISO Energy Market Operations
Version 4.4
10/28/2016
4-15
NYISO DAY-AHEAD SCHEDULING MANUAL
4.4.1
Firm Bilateral Transactions
Internal firm Bilateral Transactions are tabulated and automatically approved. Based upon
verification with other control areas, external transactions are either approved or rejected.
The results for all transactions are posted on the Bid/Post System.
4.4.2
Multi-Hour Block Transactions (MHBT)
Multi-hour block transactions are evaluated in the Day-Ahead Market relative to alternative
offers and scheduled or not scheduled based upon the total production cost associated with
the offer over the day. Instances may arise where a multi-hour block transaction may appear
to be economic, as compared to posted Locational Based Marginal Prices (LBMPs), but
was not scheduled.
The following examples describe possible scenarios where a submitted multi-hour block
transaction offer was not scheduled even though it may appear to be economic as compared
to the posted LBMPs:
 Example 1 - The submitted MHBT offer is less than the posted LBMP for an hour or
certain hours (but not all hours) of the offer, but was not scheduled. In this case,
although the MHBT offer was less than the posted LBMP during some hours, the
total cost of the bid transaction, over the hours bid, was greater than the alternative
offers selected for those hours. Market rules for MHBTs do not allow for the
selective scheduling of an hour or hours if less than the bid-specified minimum run
time.
 Example 2 - The submitted MHBT offer is less than the posted LBMP for all hours
of the offer, but the offer was not scheduled. In this case, the MHBT offer was not
selected because the offer would have resulted in even higher LBMPs than the
LBMPs that were posted for some or all of the hours considered. One possible reason
for this condition is that the scheduling of the MHBT in question may have
precluded the scheduling of an alternative offer(s) due to minimum generation or
minimum run time constraints related to the alternative offer(s). This situation would
then result in a different set of resources being scheduled with an even higher priced
offer setting the LBMP.
Another possibility is that the submitted MHBT was the marginal offer. In this case,
scheduling of the MHBT may have exceeded the energy scheduling requirements for an
hour or several hours. Since the market rules for MHBTs require that an MHBT be
scheduled for the full bid MW amount for at least the minimum run time specified,
alternative offers are scheduled to arrive at the most economic schedule that best meets the
commitment requirements of each hour.
Scheduling decisions made for hours outside of the hours covered in a MHBT offer may
also impact the scheduling of MHBTs. Even though a MHBT may be economic for the
hours bid, scheduling the MHBT in question for those hours may result in additional costs
related to resources and transactions scheduled for hours outside of the hours covered by
the MHBT bid, yielding higher overall costs for the day.
4-16
NYISO Energy Market Operations
Version 4.4
10/28/2016
NYISO DAY-AHEAD SCHEDULING MANUAL
LBMP calculations require consideration of numerous inter-related factors, not the least of
which is system security. As a result, SCUC’s decision to schedule, or not, certain MHBT
offers is based on factors that may not be readily apparent from posted LBMPs.
4.4.3
Non-Firm Bilateral Transactions
Non-firm transactions are those Bilateral Transactions that are not willing to pay congestion
charges. These transactions are treated as follows in the Day-Ahead scheduling process:
An evaluation of non-firm external transactions occurs after the DAM and Real-Time
Market have closed. The results of these evaluations are strictly advisory, until the NYISO
system operator has confirmed the transactions.
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 ATCs. 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.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
Non-firm transactions are submitted prior to the DAM close.
The DAM closes.
The SCUC program is run, without considering non-firm transactions.
The non-firm transaction selector program is run using SCUC congestion data.
A bid status of “Advisory Accepted” or “Advisory Rejected” is assigned to each
non-firm transaction.
The DAM schedules and non-firm advisory schedules are posted.
Non-firm transactions are bid into the Real-Time Market prior to its close. All valid
DAM non-firm transactions for the real-time hour being evaluated are re-evaluated,
regardless of their status from the DAM evaluation.
The Real-Time Market closes.
The Real-Time Commitment (RTC) is run, without considering non-firm
transactions.
The non-firm transaction selector program is run using RTC congestion data.
A bid status of “Advisory Accepted”, “Bid Accepted”, or “Bid Rejected” is
assigned to each non-firm transaction.
The Real-Time schedules and non-firm advisory schedules are posted.
The external “Advisory Accepted” are sent to the IS+ interchange scheduler for
scheduling and confirmation with neighboring control areas.
Confirmed internal non-firm transactions will be posted to the Market Information
System (MIS) with “Bid Accepted” status.
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”.
NYISO Energy Market Operations
Version 4.4
10/28/2016
4-17
NYISO DAY-AHEAD SCHEDULING MANUAL
16. Non-Firm transmission will be curtailed in real time when congestion occurs and
agreement with neighboring control areas is reached.
Table 4-1: 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.
Zone A
Zone B
A
B
C
D
E
Interface
4-18
NYISO Energy Market Operations
Version 4.4
10/28/2016
NYISO DAY-AHEAD SCHEDULING MANUAL
Zone A
Zone B
A
B
C
D
E
Interface
Figure 4-2: Transaction 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.
Table 4-2: Transaction Parameters
Transaction
Bid
(MW)
A
B
C
D
E
25
20
15
10
10
Time
Stamp
Priority
1
2
3
4
5
After
DAM/RTC
Evaluation
AA
AA
AA
AR
AA
After System
Operator
Confirmation
BA
BA
BA
BR
BA
Scheduled
(MW)
25
20
5
0
10*
* Counter flow transaction (E) does not increase ATC.
AA = Advisory Accepted
AR = Advisory Rejected
BA = Bid Accepted
BR = Bid Rejected
NYISO Energy Market Operations
Version 4.4
10/28/2016
4-19
NYISO DAY-AHEAD SCHEDULING MANUAL
This page intentionally blank.
4-20
NYISO Energy Market Operations
Version 4.4
10/28/2016
NYISO DAY-AHEAD SCHEDULING MANUAL
5.
D AY-A HEAD I NTERFACE
D ISPATCH D AY
TO THE
This section describes the primary interfaces between the Day-Ahead activities and the Dispatch
Day activities.
5.1
Interchange Schedule Interface
The Interchange Schedule (IS+) function provides the primary mechanism for entering,
modifying, or deleting interchange transactions for the Day-Ahead and Real-Time markets.
Data Model
The fundamental data objects within IS+ are the:
 Customer
 Contract
 Transaction
 Transaction segment
 Transaction class
 Customer contact
 NERC tag
Refer to the NYISO Transmission Services Manual (available from the NYISO Web site at
the following URL:
http://www.nyiso.com/public/markets_operations/documents/manuals_guides/index.jsp) for
additional information.
5.1.1
User Interface
The IS+ function provides video displays to enter and review data. Summary displays show
transaction information filtered according to user-enterable or pre-specified filtering and
ordering parameters, such as:
 Transaction chronology
 Transaction attributes
 Currently active transactions
5.1.2
Functional Interfaces
The Interchange Scheduler subsystem has interfaces with the following functions:
Automatic Generation Control
The AGC function obtains the net scheduled interchange value (DNI) for the NY Control
Area from IS+.
NYISO Energy Market Operations
Version 4.4
10/28/2016
5-1
NYISO DAY-AHEAD SCHEDULING MANUAL
Historical Information Retention
All relevant information from IS+ is archived.
Real-Time Market Evaluation
The accepted Day-Ahead transaction bids along with available Real-Time transaction bids
are passed to the RTC function through the Bid/Post System. The RTC function passes
accepted operating-day transaction schedules to the IS+ function through the Bid/Post
System. The final Desired Net Interchanges for the NYCA and neighboring Control Areas
are passed from the IS+ function to the Real-Time Dispatch (RTD) function through the
Bid/Post System.
5.2
Generation Schedule Interface
The SCUC function (see Section 4.3.6) passes accepted generation schedules from the DayAhead process to the Bid/Post System, which then passes the information on to the RealTime Commitment (RTC) process during the Dispatch Day.
5.3
Ancillary Service Schedule Interface
The SCUC function (see Section 3.5) passes the following accepted Ancillary Services
schedules from the Day-Ahead process to the Bid/Post System..
 Regulation
 Spinning Reserve
 Non-spinning Reserve
The Ancillary Services are evaluated again as part of the Real-Time Scheduling systems
solutions and the accepted Ancillary Service schedules are passed to the Bid/Post System.
5-2
NYISO Energy Market Operations
Version 4.4
10/28/2016
NYISO DAY-AHEAD SCHEDULING MANUAL
6.
NYISO L OAD F ORECAST P ROCESS
This section describes the NYISO Load Forecast process, functions and user interfaces.
6.1
Load Forecast Overview
The Load Forecast function is used to forecast hourly loads for each of the eleven NY
Control Area Zones and at the statewide level. The Load Forecast function uses a
combination of advanced neural network and regression type forecast models to generate its
forecasts. The function uses historical load and weather data information (including
temperature, dew point, cloud cover and wind speed) for each Zone to develop Zone load
forecast models. These models are then used together with Zone weather forecasts to
develop a Zone load forecast. The function develops the hourly load forecasts for the
current day and the next six days..
6.2
Load Forecast Functions
The load forecast functional description covers the following:
 Load Forecast Module
 Load Forecast Training Module
 Load Forecast Functional Interfaces
6.2.1
Load Forecast Module
A single Load Forecast Module is used to produce the load forecasts for all the scheduling
systems. The program automatically generates the 5 minute forecasts used by RTS. The
hourly forecasts required for SCUC are published on demand for the current day and up to
six days for each Zone. The published forecast is posted to the NYISO website by 08:00
a.m. every day, or as soon thereafter as is reasonably possible. The module uses the recent
historical data; the current day historical data (up to the first hour of forecast); the weather
forecast data for the forecast period, and the most recently updated load forecast models.
The forecasts that are produced for the scheduling systems represent only the expected
demand usage and do not include transmission losses. The transmission losses are
specifically computed as part of the scheduling systems' functionality.
6.2.2
Load Forecast Training Module
This module allows the generation of load forecasts models for each Zone and for the New
York Control Area. There is one load forecast model for each day of the week and each
weather-defined season. Up to four seasons are allowed. The module allows for selection of
model input parameters and parameters of neural network training.
The training module requires up to four years of historical hourly load and weather data for
each area. The module allows for defining weather-defined season boundaries within the
historical data, which is based on the load shape changes from one season to another. The
module allows a complete or partial selection of historical data for training of a load
NYISO Energy Market Operations
Version 4.4
10/28/2016
6-1
NYISO DAY-AHEAD SCHEDULING MANUAL
forecast model. The training of the models for all areas (for all day types and all defined
seasons) is automated through execution of a designated macro in the program.
6.2.3
Load Forecast Functional Interfaces
This section outlines the functional interchange of data between Load Forecast (LF) and
other NYISO applications.
Oracle Information Storage and Retrieval (OISR) System
The LF function provides the OISR System function with the NYCA and Zonal hourly
loads for storage. The MIS, SCUC and RTS systems can then retrieve the most up to date
load forecast available.
Historical Information Retention
Load forecast results are archived.
Historical Load Data
The LF function retrieves historical load data from the EMS through its PI Historian data.
Weather Data
The LF function retrieves weather forecast data and historical weather data from files
received from the weather service.
6.3
Load Forecast User Interface
The NYISO forecast is on a zonal basis and is produced by NYISO Energy Market
Operations personnel. Initial forecasting is completed prior to initializing SCUC each day
prior to the Dispatch Day. The forecast is for the Dispatch Day and the next six days, a total
of up to 168 hours.
The Load Forecast function provides a complete set of input/output displays for a typical
load zone. Input/output displays are available at the system level to present the load forecast
values.
The function is accompanied with a set of displays for input, execution, and output. The
required files as input to the program are in .csv format.
The function provides the capability to publish the load forecast data to the OISR for the
SCUC package to utilize.
By 08:00 a.m. or as soon thereafter as is reasonably possible, the NYISO develops and
posts its statewide Load forecast on the OASIS.
6-2
NYISO Energy Market Operations
Version 4.4
10/28/2016
NYISO DAY-AHEAD SCHEDULING MANUAL
7.
SCUC E XECUTION
This section describes SCUC Execution procedure.
7.1
SCUC
These procedures are performed by the NYISO Energy Market Operations personnel after
the MIS DAM Market closing process has completed. The procedures are executed on the
RANGER system.
7.2
SCUC Execution Actions
The NYISO Energy Market Operations personnel perform the following actions:
1. Retrieve the MIS System file for the next day’s Bids
2. Transfer data from the EMS / Real Time server
3. Perform the SRE end of the day fill in process
4. Execute the SCUC
5. Review and analyze results
6. Send the SCUC output data to the Bid/Post System Box
7. Save SCUC case for:
a. Archival purposes
b. Next SCUC History run
c. Dispute resolution purposes
NYISO Energy Market Operations
Version 4.4
10/28/2016
7-1
NYISO DAY-AHEAD SCHEDULING MANUAL
This page intentionally blank.
7-2
NYISO Energy Market Operations
Version 4.4
10/28/2016
NYISO DAY-AHEAD SCHEDULING MANUAL
8.
R ELIABILITY F ORECAST
This section describes the maintenance of reliability in the time frame one to seven days ahead of
the Dispatch Day.
8.1
Reliability Forecast Requirements
In the SCUC program, system operation shall be optimized based on Bids over the Dispatch
Day. However, to preserve system reliability, the NYISO must ensure that there will be
sufficient resources available to meet forecasted Load and reserve requirements over the
seven-day period that begins with the next Dispatch Day.
The NYISO will perform a Supplemental Resource Evaluation (SRE) for days two through
seven of the commitment cycle. If it is determined that a long start-up time Generator is
needed for reliability, the NYISO shall accept a Bid from the Generator and the Generator
will begin its start-up sequence. During each day of the start-up sequence, the NYISO will
perform a SRE to determine if long start-up time Generators will still be needed as
previously forecasted. If the Generator is still needed, it will continue to accrue start-up cost
payments on a linear basis. If at any time it is determined that the Generator will not be
needed as previously forecasted, the NYISO shall order the Generator to abort its start-up
sequence, and its start-up payment entitlement will cease at that point.
The NYISO will commit long start-up time Generators to preserve reliability. However, the
NYISO will not commit resources with long start-up times to reduce the cost of meeting
Loads that it expects to occur in days following the next Dispatch Day. Supplemental
payments to these Generators, if necessary, will be determined according to the provisions
of Attachment C of the NYISO Services Tariff, and will be recovered by the NYISO under
Rate Schedule 1 of the NYISO OATT.
NYISO Actions
The NYISO shall perform the SRE as follows:
1. The NYISO shall develop a forecast of daily system peak Load for days two
through seven in this seven-day period and add the appropriate reserve margin.
2. The NYISO shall then forecast its available Generators for the day in question by
summing the Operating Capacity for all Generators currently in operation that are
available for the commitment cycle, the Operating Capacity of all other Generators
capable of starting on subsequent days to be available on the day in question, and
an estimate of the net imports from External Bilateral Transactions.
3. If the forecasted peak Load plus reserves exceeds the NYISO's forecast of available
Generators for the day in question, then the NYISO shall commit additional
Generators capable of starting prior to the day in question (e.g., start-up period of
two days when looking at day three) to assure system reliability.
4. In choosing among Generators with comparable start-up periods, the NYISO shall
schedule Generators to minimize the start-up and minimum Generation Bid costs of
meeting forecasted peak Load plus Ancillary Services consistent with the
Reliability Rules.
NYISO Energy Market Operations
Version 4.4
10/28/2016
8-1
NYISO DAY-AHEAD SCHEDULING MANUAL
5.
In determining the appropriate reserve margin for days two through seven, the
NYISO will supplement the normal reserve requirements to allow for forced
outages of the short start-up period units (e.g., gas turbines) assumed to be
operating at maximum output in the unit commitment analysis for reliability.
The bidding requirements and the Bid tables in Attachment D of the NYISO Services Tariff
indicate that Energy Bids are to be provided for days one through seven. Energy Bids are
binding for day one only for units in operation or with start-up periods less than one day.
Minimum generation cost Bids for Generators with start-up periods greater than one day
will be binding only for units that are committed by the NYISO and only for the first day in
which those units could produce Energy given their start-up periods. For example,
minimum generation cost Bids for a Generator with a start-up period of two days would be
binding only for day three because, if that unit begins to start up at any time during day one,
it would begin to produce Energy 48 hours later on day three. Similarly, the minimum
generation cost Bids for a Generator with a start-up period of three days would be binding
only for day four.
8.2
Reliability Responsibilities
NYISO Actions
To insure that the New York Control Area (NYCA) will meet its operating capability,
reserve, interchange, and load requirements in a reliable manner, the NYISO Scheduling
staff performs the following:
1. Determine that the NYCA has sufficient operating capability and reserve to meet
the forecasted load and reserve requirements for the Day-Ahead period.
2. Determine that the NYCA has sufficient Regulation margin to meet light load
requirements.
3. Coordinate, verify, and confirm the Day-Ahead transaction schedules.
4. Coordinate the scheduling of NYCA Inadvertent Interchange payback when
conditions warrant.
5. Identify hours when the magnitude of External interchange schedule changes could
degrade NYCA control performance and adjust transactions accordingly.
Market Participant Actions
The Market Participants must perform the following:
1. Notify the NYISO of any scheduled generation and transmission outages according
to the procedures defined in the NYISO Outage Scheduling Manual (available from
the NYISO Web site at the following URL:
http://www.nyiso.com/public/markets_operations/documents/manuals_guides/inde
x.jsp) that would affect transactions.
2. Respond to NYISO directions involving security, capability, schedule changes, and
light load problems.
8-2
NYISO Energy Market Operations
Version 4.4
10/28/2016
NYISO DAY-AHEAD SCHEDULING MANUAL
8.3
Dealing with Insufficient Bids
The following provides procedures to deal with insufficient bids and to ensure that
sufficient operating capacity is available to serve all NYCA load. To do this, a variety of
measures (i.e., installed capacity, annual reliability assessments, maintenance outage
coordination, seven day reliability forecasts, SCUC, etc.) will help reduce the likelihood of
experiencing insufficient available bids. Notwithstanding, the NYISO needs the ability to
identify potential bid insufficiencies with adequate lead-time to be able to solicit and reevaluate additional bids.
The Need for Bids
The NYISO cannot commit resources in the DAM without receiving bids from those
resources. Upon determining that it needs more Day-Ahead resources the NYISO will
issue a public request for more bids. This information will be posted prominently to the
NYISO web page. If the NYISO continues to have insufficient bids to serve NYCA load
even after bid solicitations, it can reasonably be assumed that sufficient resources are truly
not available. In this case, the NYISO should implement emergency measures that may
include purchasing external emergency energy, shared activation of reserves, and load
curtailment.
Reliability Assessments
The NYISO will perform a reliability assessment to determine if projected Operating
Reserves over an upcoming period will be adequate. This reliability assessment will
compare projected Operating Capacity with the forecast NYCA Peak Load (where
Operating Capacity equals NYCA Installed Capacity less Proposed Maintenance Outage
Schedules less Projected Unavailable Capacity). For instance:
Table 8-1: Reliability Assessment - Load and Capacity Table
Assessment
MW Capacity
NYCA Installed Capacity (ICAP)
30,000 MW
Less Scheduled Maintenance Outages
(3,000 MW)
Less Forecast Unavailable
(4,000 MW)
Net Operating Capability
23,000 MW
Less Forecast NYCA Peak Load (including Firm Energy Exports)
(20,000 MW)
Net Operating Reserves
3,000 MW
Less Required Operating Reserves
(1,800 MW)
Operating Reserve Surplus (Deficiency)
1,200 MW
If Operating Capacity is expected to be deficient, the NYISO will take actions as specified
below for various time frames.
NYISO Energy Market Operations
Version 4.4
10/28/2016
8-3
NYISO DAY-AHEAD SCHEDULING MANUAL
8.4
Reliability Assessment Processes
The NYISO continually re-evaluates the reliability of the NYCA. There are several
reliability assessments of any given Operating Day performed over various time horizons.
The sequences of these evaluations are described next.
Annual Reliability
The NYISO has the responsibility to ensure sufficient capacity is expected to be available
to serve all NYCA load on an annual basis. This is accomplished using the NYISO
maintenance outage coordination procedure. All installed capacity providers are required to
abide by NYISO maintenance coordination, and all other generating resources are required
to inform the NYISO of their annual maintenance plans.
Based upon a weekly reliability assessment for the upcoming calendar year, if Operating
Capacity is expected to be deficient in a certain period, the NYISO will take actions to
modify generator maintenance schedules as outlined in the NYISO outage Scheduling
Manual (available from the NYISO Web site at the following URL:
http://www.nyiso.com/public/markets_operations/documents/manuals_guides/index.jsp).
7-Day Reliability
Similarly to the case of Annual Reliability, the NYISO will perform a reliability assessment
on a rolling basis to determine if projected Operating Reserves for each day of the next
seven days will be adequate. If a deficiency is forecast, the NYISO will commit generation
capable of starting in time to meet the expected load. In addition, if resources are
anticipated to be insufficient for any day of the rolling commitment week, the NYISO will
immediately broadcast a bid solicitation message via the Market Information System (MIS)
to all market participants, identifying all deficient bid times and categories.
Day-Ahead Reliability
At the close of the Day-Ahead market, the NYISO will use SCUC to evaluate bids and
clear the Day-Ahead market. If SCUC cannot solve due to insufficient bids to meet DayAhead requirements, the NYISO shall commit all bid resources; and then solicit additional
bids and initiate the Supplemental Resource Evaluation (SRE) process as described in
Section 10 of this Manual. When the Day-Ahead Energy Market does not clear due to
insufficient resources, the calculated Energy LBMP will be the marginal cost to supply the
last MW of load; MW amounts in forward contracts for load bids will be prorated to match
total supply forward contracts with load forward contracts.
Post SCUC Day-Ahead and Pre or Post RTC In-Day Reliability
Any time an event occurs such as a generator trip or a transmission outage that renders a
Day-Ahead commitment insufficient for hours that would not yet be evaluated by RealTime Commitment (RTC) (or in Real-Time after RTC has run), the NYISO must perform
an SRE.
8-4
NYISO Energy Market Operations
Version 4.4
10/28/2016
NYISO DAY-AHEAD SCHEDULING MANUAL
Real-Time Reliability
The NYISO will use Real-Time Commitment (RTC) to evaluate Real-Time bids, and check
that sufficient bids exist for the next two subsequent hours. If RTC cannot solve due to
insufficient bids to meet Real-Time requirements, the NYISO shall commit all bid
resources subject to network security constraints; and then solicit additional bids and
initiate the SRE process.
NYISO Energy Market Operations
Version 4.4
10/28/2016
8-5
NYISO DAY-AHEAD SCHEDULING MANUAL
This page intentionally blank.
8-6
NYISO Energy Market Operations
Version 4.4
10/28/2016
NYISO DAY-AHEAD SCHEDULING MANUAL
9.
I NTERCHANGE C OORDINATION
P ROCEDURE
Scheduled interchange must be coordinated between Control Areas to prevent:
 Frequency deviations
 Accumulation of Inadvertent Interchange
 Exceeding mutually established transfer limits
NYISO Actions
The NYISO schedules external bilateral transactions with other Control Areas in accordance
with current NERC policies and procedures.
NYISO Energy Market Operations
Version 4.4
10/28/2016
9-1
NYISO DAY-AHEAD SCHEDULING MANUAL
This page intentionally blank.
9-2
NYISO Energy Market Operations
Version 4.4
10/28/2016
NYISO DAY-AHEAD SCHEDULING MANUAL
10. S UPPLEMENTAL R ESOURCE E VALUATION
O NE OR M ORE D AYS A HEAD
The Supplemental Resource Evaluation (SRE) process is used to commit additional resources
outside of the SCUC and RTC processes to meet NYISO reliability or local reliability
requirements. The Transmission and Dispatch Manual provide more information on SREs in
sections 5.7.5 through 5.7.12.
NYISO Energy Market Operations
Version 4.4
10/28/2016
10-1
NYISO DAY-AHEAD SCHEDULING MANUAL
This page intentionally blank.
10-2
NYISO Energy Market Operations
Version 4.4
10/28/2016
NYISO DAY-AHEAD SCHEDULING MANUAL
A.
Attachment A. Calculation of Incremental Losses
Generator
“i”
∆ Gi
∆L
Incremental
Transmission
Losses
Bus “i”
Reference
Bus
∆D
System
Load
Energy Balance : ∆ Gi = ∆ D + ∆ L
Figure A-1: Incremental Transmission Losses
Calculation of Incremental Losses
The marginal (or incremental) effect of real power transmission losses is taken into account
by the SCUC for the Day-Ahead Market, Real-Time Market, and Real-Time operations.
Losses occur in the transmission system as energy flows from generation sources to the
loads. These losses appear as additional electrical load, requiring the generators to produce
additional power to supply the losses. The amount of losses that occur on specific
transmission lines or areas of the transmission network at any given time are dependent on
network topology and the specific generation sources being used to meet the load at that
time. Figure A-1 illustrates the concept of incremental losses:
The elements in Figure A-1 are defined as follows:
ΔD = an increment of load at the reference bus with all other loads held constant
ΔGi = the increment of generation at bus “i” that is required to supply the increment of load
at the reference bus
ΔL = the increment of transmission losses resulting from the transfer of power from the
generator to the reference bus load.
Penalty Factors The Penalty Factor for generator “i” is defined as the increase required in
generator output at Bus “i” to supply an increase in load at the reference Bus
with all other loads held constant, or:
NYISO Energy Market Operations
Version 4.4
10/28/2016
A-1
NYISO DAY-AHEAD SCHEDULING MANUAL
 PFi = ΔGi / ΔD
Which, from the energy balance relationship, can also be defined as follows:
 PFi = 1 / (1 - ΔL / ΔGi)
Generator Energy bid prices are multiplied by Penalty Factors to account for incremental
transmission losses in the dispatch process.
Delivery Factors
The Delivery Factor for Generator “i” is defined as follows:
 DFi = ΔD / ΔGi
Which, is related to Penalty Factor as follows:
 DFi = 1 / PFi
Delivery Factors are used to calculate the marginal loss components of the LBMPs.
Losses Associated with External Transactions
External Generators and Loads can participate in the LBMP Market or in Bilateral
Transactions. External Generators may arrange Bilateral Transactions with Internal or
External Loads and External Loads may arrange Bilateral Transactions with Internal
Generators. Charges for marginal losses for each of these types of transactions (LBMP
Market or Bilateral) are limited to losses inside the NYCA. The Generator and Load
locations for which LBMPs are calculated are initially limited to a pre-defined set of buses
External to the NYCA. The marginal losses component for these LBMPs are calculated
from points on the boundary of the NYCA (Interconnection buses) to the reference bus.
The marginal losses component of the LBMP at each External bus are a weighted average
of the marginal losses components of the LBMPs at the Interconnection buses. To derive
the marginal losses component of the LBMP at an External location, a hypothetical
transaction is scheduled from the External bus to the reference bus. The Shift Factors for
this transaction on the tie lines into the Interconnection buses, which measure the per-unit
effect of flows over each of those tie lines that result from the hypothetical transaction,
provide the weights for this calculation. Since all the power from this hypothetical
transaction crosses the NYCA boundary, the sum of these weights is unity. The sum of the
products of these weights and the marginal losses component of the LBMP at each of these
Interconnection buses yields the marginal losses component of the LBMP that are used for
the External bus.
A-2
NYISO Energy Market Operations
Version 4.4
10/28/2016
NYISO DAY-AHEAD SCHEDULING MANUAL
B.
Attachment B. NYISO Load Forecasting Model
NYISO Load Forecasting Model
The NYISO Load Forecasting Model (LFM) is designed to meet a number of objectives.
Perhaps most important of the objectives is the ability to forecast hourly loads for the dayahead market. This particular need encompasses not only the loads for the New York
Control Area (NYCA), but also the loads for each of the eleven zones that comprise the
NYCA. Other objectives extend the geographic purview of the model and the timeframe for
the forecasts.
The geographic reach of the model will be extended to each zone within the NYCA. Since
the NYISO auction model turns on location based marginal prices (LBMP), there needs to
be a mechanism to support the determination of those prices. The market-clearing price will
be determined by the supply and demand for power. Since both supply and demand for
power have geographic aspects, the system that provides (expected) demand information to
the auction process needs geographic aspects as well.
The timeframe needs of the electricity market are quite varied, and a modeling system to
support that market must also function within the various timeframes. In addition to the
day-ahead market, there is a need for week-ahead demand information since some
generating facilities may take that long to become fully functional. There is a need to
understand what is likely to happen during a capability period since capacity may need to
be procured to meet reliability requirements. It is important to understand the demand and
energy profile for the entire calendar or capability year so that rational planning can take
place. Finally, in the arena of longer timeframes, a five to ten year horizon meets NERC
standards and allows planning for capacity to be sited and built. Retreating from the long
run towards the very shortest runs, we need to understand demand in the balancing markets
and in situations of highly changeable weather. These analyses would logically take place
during the day in question.
There are also a number of technical objectives for the modeling system. For day-ahead
forecasting, it needs to be convenient and transparent to run, in order to feed information in
a timely manner to market participants and to the SCUC process. The model must be
accurate to within the limits of statistical and econometric models; forecasts of weather and
economic activity that drive the LFM are likely to have errors, which mean that actual loads
will deviate from forecasted loads. The modeled loads need to be within an acceptable
range of the actual loads after controlling for weather and economic activity. Thus, another
objective is that the performance of the model can be assessed easily and quickly so that
adjustments can be made appropriately. The economic components of the model structure
should conform to good economic theory and practice so that the system can also yield
information that is useful for policy analysis.
A Unified System
Despite a large number of seemingly disparate objectives, the unifying theme is one of
providing information about future loads and energy demands across the NYCA. With this
theme as backdrop, the NYISO decided that a unified modeling system using one set of
NYISO Energy Market Operations
Version 4.4
10/28/2016
B-1
NYISO DAY-AHEAD SCHEDULING MANUAL
equations, drivers, and historical information would best serve its information needs. In
particular, using one comprehensive data set eliminates inconsistencies and the need to try
to align data from different sources.
As the rest of this attachment will illustrate, creativity in model construction allows
appropriate data to drive the model in the relevant timeframe. Certainly, weather is
extremely important in the short run, while economic and secular data play a stronger role
in the medium and longer run. What makes the system unified is that weather does not
disappear in the long run (design weather is used for some scenario planning) nor does
economic activity disappear in the short run (economic activity is fixed at some level for
capability considerations and next day analysis).
Schematic Model Flow
The central objective of the model is to forecast hourly loads in each of eleven zones and
the NYCA for the next day. Peak load and total energy consumption for the next day are
extremely important ancillary objectives and might, under some circumstances, be derived
from the hourly loads. In fact, the LFM uses a “bottom/up” approach which pays explicit
attention to peak load and energy at zone level, and obtains the NYCA level by summing
over the zones. This approach uses state or NYCA information when it contributes well to
the model’s structure and zone information when it plays a premier role. Once the peak load
and daily energy are obtained, a series of hourly interval models are determined, comprised
of four fifteen-minute interval models for each hour of the day.
The model’s structure flows from daily peak and energy at the zonal level, to hourly
interval loads at the zone level. Part of the modeling process is by inclusion of predicted
values of peak or energy into the hourly interval load models at the NYCA level, from the
NYCA to the zones, and in the zones as isolated units.
The zonal daily peak load and energy are specified as functions of weather, economic
activity, day-type, and an installed energy-consuming equipment base (Estimation
procedures are discussed below). The predicted zonal peak and energy requirements then
become part of the driver set of the zonal hourly interval load models. Peak load and energy
requirements in the driver sets serve to constraint the hourly interval loads to be consistent
with the previously determined peak and energy requirements.
At this point there are eleven sets of (96) hourly interval zone load models and one set of
(96) NYCA-level hourly interval load model obtained by summing over all the zones.
The “bottom-up” methodology utilizes the detailed information at the NYCA level and
preserves the resulting profiles and forecasts for the unique behavior of each zone. They
also allow for a strong concordance between peak load and energy, and hourly interval
loads.
Data Considerations
Since this attachment is not a tutorial on load forecasting methodologies, it is not useful to
go into too much detail about particular data series or estimation methods, but some
description of each can help to illuminate the process. The core of the modeling system is
the next day hourly interval load forecast, and naturally, the central data set is the set of
hourly interval loads for the system and for the zones. Load data from three to four recent
B-2
NYISO Energy Market Operations
Version 4.4
10/28/2016
NYISO DAY-AHEAD SCHEDULING MANUAL
historical years provide sufficient experience to yield acceptable estimates of the
parameters associated with the drivers of the various models. Shorter periods will better
capture more recent weather-response characteristics while longer periods will better
capture weekday, weekend and holiday seasonal daily and hourly load profiles. The
challenge for modeling and estimation was to obtain data with hourly interval frequency or
construct other data to have the required frequency. The key drivers for the day-ahead
models are weather and day-type. The weather forecast provider was able to supply a
number of variables with an hourly frequency, for example, dry bulb temperature, wind
speed, cloud cover, dew point, wet bulb temperature, humidity, and barometric pressure.
However, it is not necessary to model or forecast weather at sub-hourly intervals.
The interaction of load and weather can be quite subtle, requiring consideration of build-up
effects, daily averages, recognition of maxima and minima, etc. The availability of the
hourly information listed above enabled the construction of transformed data to meet the
needs of modelers.
Table B-1 is an example of actual and forecasted weather for Albany International Airport,
the official weather collection site for Albany County. Note that the minimum, maximum,
and average values of the variables are determined over twenty-four hourly observations.
The data for 15 April, 1999 is the set of actual observations, while the data for 16 – 25
April, 1999 is a forecast.
Table B-1: Albany Airport Actual and Forecasted Weather
DATE
MIN
MAX AVG MIN
MAX AVG MIN
MAX AVG MIN
MAX AVG MAX AVG AVG
TMP
TMP TMP DPT
DPT
DPT
HU
M
HU
M
HU
M
WE
B
WE
B
WE
B
WS
P
WS
P
CLC
Apr. 15, 1999
28
62
48
17
32
24
18
89
47
27
44
38
18
7
33
Apr. 16, 1999
37
51
45
29
33
30
43
76
56
27
44
38
13
6
63
Apr. 17, 1999
40
57
48
34
39
37
46
96
68
27
44
38
13
9
79
Apr. 18, 1999
40
56
48
36
37
37
49
89
66
27
44
38
10
8
77
Apr. 19, 1999
36
53
45
36
37
37
36
100
72
27
44
38
12
8
75
Apr. 20, 1999
39
58
48
35
36
35
42
89
64
27
44
38
8
7
65
Apr. 21, 1999
36
62
49
33
35
34
35
92
59
27
44
38
9
7
59
Apr. 22, 1999
39
65
52
31
33
32
29
76
49
27
44
38
8
7
54
Apr. 23, 1999
42
69
56
30
31
31
24
65
41
27
44
38
11
8
52
Apr. 24, 1999
43
68
55
30
30
30
24
60
40
27
44
38
10
8
40
Apr. 25, 1999
41
64
52
30
40
35
36
86
54
27
44
38
10
7
30
The zonal forecast models use weather information gathered from seventeen weather
stations across New York. The data from the stations is aggregated appropriately to best
represent each zone. Thus, the information from those seventeen sites is combined into
eleven zone weather sets and one state-level weather set. Tables B-2 and B-3 show the state
and zone weighting schemes.
NYISO Energy Market Operations
Version 4.4
10/28/2016
B-3
NYISO DAY-AHEAD SCHEDULING MANUAL
Table B-2: Zonal Share of New York State’s 2010 Population
POPULATION
ZONE
Percent
(000)
A - WEST
1,532
7.9%
B - GENESE
1,003
5.2%
C - CENTRL
1,384
7.1%
D - NORTH
82
0.4%
E - MHK VL
891
4.6%
F - CAPITL
1,215
6.2%
G - HUD VL
1,372
7.0%
H - MILLWD
190
1.0%
I - DUNWOD
760
3.9%
J - N.Y.C.
8,186
42.1%
K - LONGIL
2,835
14.6%
TOTAL
19,450
100.0%
Upstate (A-F)
6,107
31.4%
Downstate (G-K)
13,343
68.6%
Table B-3: Weather Station Weights Imputed to Each Zone
B-4
Zone
Stations
Station Weight
A - WEST
Buffalo
Elmira
Syracuse
Total
91%
5%
4%
100%
B - GENESE
Elmira
Rochester
Syracuse
Total
5%
85%
10%
100%
C - CENTRL
Binghamton
Elmira
Syracuse
Watertown
Total
23%
14%
55%
9%
100%
D - NORTH
Plattsburgh
100%
NYISO Energy Market Operations
Version 4.4
10/28/2016
NYISO DAY-AHEAD SCHEDULING MANUAL
Zone
Stations
Station Weight
E - MHK VL
Binghamton
Massena
Monticello
Utica
Watertown
Total
20%
17%
13%
35%
15%
100%
F - CAPITL
Albany
Binghamton
Plattsburgh
Poughkeepsie
Utica
Total
76%
3%
5%
6%
10%
100%
G - HUD VL
Newburgh
Poughkeepsie
White Plains
Albany
Total
68%
27%
4%
2%
100%
H - MILLWD
White Plains
Total
100%
100%
I - DUNWOD
White Plains
100%
J - N.Y.C.
JFK
LGA
Total
21%
79%
100%
K - LONGIL
Islip
100%
Day-type information in the form of binary indicator variables comes from a master daily
calendar. Holidays and the days surrounding holidays were also available through this
master calendar. This kind of information is represented by binary variables, which indicate
that a given day either is or is not a particular day of the week, or a particular holiday.
Economic data at the state, metropolitan area or county level is available at best on a
monthly basis, in the case of employment, and on a quarterly or annual basis for other kinds
of information. This frequency did not pose a real problem since economic activity can be
considered fixed in the very short run. To incorporate levels of economic activity into the
model in the short run (peak loads or daily energy), and changes in activity as the short run
unfolds into the long run, the appropriate economic variables were converted (from
monthly, quarterly, annually) to daily values which remained constant until a new value
emerged, employment in the next month, for example.
The constancy of economic data in the very short run, combined with its variability in the
medium and long run, allows the use of the same model as the time horizon unfolds.
Weather data can be used in a similar way. As discussed above, weather is certainly a major
driver of day-ahead and week-ahead load, and weather data is available as a forecast to feed
into the driver side of a load or energy forecasting model as a set of assumptions. Longer
NYISO Energy Market Operations
Version 4.4
10/28/2016
B-5
NYISO DAY-AHEAD SCHEDULING MANUAL
run weather forecasts are much less certain, even for a month ahead, let alone a season,
capability period, year, or decade.
For these planning periods, we incorporate the concept of design weather into the model.
While each day or month can differ in accord with the design characteristics, the design
pattern can be held constant for planning purposes. In fact, atypical weather patterns as well
as typical or design patterns can be incorporated into the model for purposes of comparative
analysis. So, analogous to the way in which economic data is fixed in the short run, weather
patterns can be fixed in the longer run. It is the pliability of the model drivers that allows
the use of the same model structure over very different timeframes.
As described above, the LFM actually aggregates weather from seventeen stations across
New York into eleven zone points based on population and other historical weighting
factors. Economic data comes from our economic forecasting vendor and is provided at the
state, MSA, and county levels for subsequent aggregation into zones.
Estimation Processes
To articulate the LFM, we incorporated data into the appropriately specified equation
systems via statistical estimation procedures. The intent here is straightforward. The
estimation process should lead to a set of model equation parameters, which minimize the
(sum of squared) errors between the actual loads and what the model predicts for load under
the circumstances defined by the driver variables.
The LFM goes beyond traditional regression analysis to incorporate a technique known as
“artificial neural net” (ANN) analysis. By taking a sophisticated non-linear approach to the
estimation of the model’s parameters, ANN analysis allows a model to be “trained” and to
“learn” from its experience as it estimates the parameters. Training takes place when a
specification is articulated and parameters are estimated using a given data set. Learning
takes place when new data is incorporated into the data set and the original specification is
maintained. Learning can often result in some small adjustments to parameters as a result of
the new experience (data). It is an efficient way to update a model without expending effort
on a re-specification.
B-6
NYISO Energy Market Operations
Version 4.4
10/28/2016
Was this manual useful for you? yes no
Thank you for your participation!

* Your assessment is very important for improving the work of artificial intelligence, which forms the content of this project

Download PDF

advertising