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© ISO New England Inc. 2017 Procedure: Perform Reserve Adequacy Assessment Process Name: Perform Reserve

Adequacy Commitment Procedure Number: RTMKTS.0050.0010 Revision Number: 58 Procedure Owner: Thomas Knowland Effective Date: January 16, 2017

Approved By: Director, Operations Valid Through: May 26, 2018

This document is controlled when viewed on the ISO New England Internet web site. When downloaded and printed, this document becomes UNCONTROLLED, and users should check the Internet web site to ensure that they have the latest version. In addition, a Controlled Copy is available in the Master Control Room procedure binder. Hard Copy Is Uncontrolled Rev. 58 of 46

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SOP-RTMKTS.0050.0010 Perform Reserve Adequacy Assessment

Contents

1. Objective ................................................................................................................. 3

2. Background ............................................................................................................ 3

3. Responsibilities ...................................................................................................... 4

4. Controls .................................................................................................................. 4

5. Instructions ............................................................................................................. 5

5.1 Time of RAA .................................................................................................. 5 5.2 Set Up the RAA Case during the Re-Offer Period ......................................... 6 5.3 Run the RAA Case ...................................................................................... 10

5.3.1 Run the RAA case ................................................................................ 10 5.3.2 Review the RAA case ........................................................................... 13

5.4 Run an Intraday RAA (RSC) Case .............................................................. 15 5.5 Schedule Pumping ...................................................................................... 16 5.6 Run the SCRA Case ................................................................................... 17

5.6.1 Run the SCRA case .............................................................................. 17 5.6.2 Review the SCRA solution .................................................................... 18 5.6.3 Approve SCRA case ............................................................................. 22 5.6.4 Post-SCRA Case Approval Discussions ............................................... 24

5.7 Update SCRA During Operating Day .......................................................... 25 5.7.1 Run an Updated SCRA Case ................................................................ 25

5.8 Startup Cancellation and De-Commitment of Generators ........................... 28 5.8.1 Decision to Cancel S/Us or De-Commit Generators ............................. 28 5.8.2 Communications ................................................................................... 29

6. Performance Measures ........................................................................................ 30

7. References ............................................................................................................ 30

8. Revision History ................................................................................................... 31




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9. Attachments ......................................................................................................... 34

Attachment A - Forecaster Task and RAA Process Checklist ................................ 35 Attachment B - Retired (05/30/14) .......................................................................... 40 Attachment C - Retired (06/01/12) ......................................................................... 41 Attachment D - Abnormal/Emergency Pipeline Condition Alert to Generators ....... 42





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1. Objective The intent of this procedure is to define the business process that is performed to ensure

sufficient Generators are available to meet capacity and reserve requirements for the current and next operating day.

2. Background ISO New England (ISO) will perform a Reserve Adequacy Assessment (RAA) and if

necessary commit Generators to meet capacity and reserve requirements. Its primary focus is to review the difference between the ISO forecast of demand and the total demand that was cleared in the Day-Ahead (DA) Market. Should insufficient capacity be committed in the DA Market, Generators are committed to ensure adequacy of capacity in Real-Time to meet Load, Operating Reserve, and Replacement Reserve Requirements (Replacement Reserve Requirements may be set to zero). The objective function in the RAA is the minimization of the Start-up fees and costs to operate at Economic Minimum (Eco Min) for any additional Generators that are committed.

ISO will normally perform this run after the close of the re-offer period each day. ISO will also perform additional RAA runs throughout the Operating Day, based on updated ISO load forecasts and updated Generator and transmission maintenance availability information.

RAA Cases are created by copying the approved Day Ahead Case for a given day and applying forecasted load (as opposed to DA cleared load). RAA Cases are solved by the Application Presentation Framework Market Operator Interface (APF-MOI) software running the Resource Scheduling and Commitment (RSC) analysis.

After RAA approval, the ISO Forecaster will run Security Constrained Reserve Adequacy (SCRA) Cases at pre-determined schedules and as required based on updated ISO load forecasts and updated Generator and transmission maintenance availability information.

Initial SCRA Cases are created by copying the approved RAA and are solved by the APF-MOI running a Scheduling and Price Dispatch (SPD) analysis and Simultaneous Feasibility Test (SFT) analysis. Subsequent SCRA Cases for a given day are created by copying the previously approved SCRA, updating it as described above and running a SPD analysis. SFT analysis is not required for intra-day SCRA cases.





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3. Responsibilities

NOTE Any North American Electric Reliability Corporation (NERC) Certified System Operator, certified at the RC level, has the authority to take action(s) required to comply with NERC Reliability Standards

1. The Forecaster is responsible for:

A. Performing the RAA

B. Communicating a forecasted Minimum Generation Emergency to the Operations Shift Supervisor

C. Communicating Generator startup cancellation and de-commitment events and recording these events in the Control Room Event Logserver.

D. Performing the Forecast Capacity Analysis (FCA) and comparing the results with the results of the EMU System Capacity Monitor

E. Committing non-Fast Start Generators on a Day-Ahead basis and in Real-Time

F. Contacting long lead time Generators and communicating Start-Up orders.

NOTE A Forecaster is not to release an on-line Generator for shutdown in Real Time.

2. When a decision is made to cancel a startup or de-commit an on-line Generator for future hours, the Forecaster is responsible for notifying the Generator of the new schedule.

4. Controls • The save-case is time stamped upon completion

• The RAA process, through approval of the initial SCRA, is completed by 1700

• Forecaster uses Attachment A - Forecaster Task and RAA Process Checklist

• The Operating Reserve requirement is met 100% of the time except when all Generators have been committed

• Forecaster enters each cancelled start from the RAA process in the Control Room Event Logserver and also cancels the appropriate Real Time Commitment Decision (CD) in the APF-MOI software.





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5. Instructions 5.1 Time of RAA

1. The Forecaster shall check off and sign Attachment A - Forecaster Task and RAA Process Checklist while performing the RAA process.

2. The Forecaster shall perform an initial RAA, an initial SCRA and an ISO FCA when the Real-Time (RT) Energy Market Re-Offer Period closes.

3. The Forecaster shall periodically perform an SCRA and update the ISO FCA.

4. The Forecaster shall review all Gas Pipeline Electronic Bulletin Board notices throughout the course of the day and perform the following applicable actions:

NOTE Under normal operating conditions, various functions are performed on a daily basis to facilitate electric/gas coordination and enhance reliability for both systems (see Steps 4 through 8 in Attachment D). During abnormal or emergency conditions, Step 1 through Step 3, in Attachment D, is to be followed.

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A. When notified by any Gas Pipeline of abnormal/emergency condition(s), proceed to Attachment D, Abnormal/Emergency Pipeline Condition Alert to Generation and perform the applicable actions.

B. In accordance with ISO New England Operating Procedure No. 21 - Energy Inventory Accounting and Actions During an Energy Emergency OP-21), Appendix B - Electric/Gas Operations Committee (EGOC) Operations Communications Protocol, contact the regional natural gas pipeline/LDC companies and discuss/determine pertinent gas sector information including but not limited to the following:

• Weather and temperature conditions

• Anticipated demand on the regional natural gas pipelines/LDCs

• Any posted Critical or Non-Critical Notices, especially those concerning pipeline capacity constraints or Operational Flow Orders (OFOs).

C. Whenever conditions warrant, relay information obtained from the regional natural gas companies to the Manager, Control Room Operations (or designee) and the Supervisor, Operations Forecast and Scheduling (or designee).





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5.2 Set Up the RAA Case during the Re-Offer Period

NOTE Under normal conditions the Re-Offer Period is between the DA case approval and 1400 on the day prior to the Operating Day. Market Participants that wish to re-offer, normally submit re-offers through eMarket. The term “Redeclaration’ is defined in ISO New England Manual for Definitions and Abbreviations Manual M-35 (Manual 35) as “A restatement of a Resource’s availability, limits, or other Supply Offer data or Supply Offer parameter, except price, submitted by a Market Participant to the ISO to reflect a change in the status or capability of the Resource or changed by the ISO based upon the Resource’s actual performance.” The term Redeclaration and abbreviated forms of this term (e.g., Redec, Redeced, Re-declare, etc.) are used in this SOP. For Redeclarations and schedule changes, Designated Entities (DEs) should contact the Forecaster with the changes. This may be performed by phone, email or by fax.

1. When the Forecaster receives DE re-offers for Generators/Dispatchable Asset Related Demands (DARDs) that wish to Re-declare limits, schedules and commitments the Forecaster shall perform updates using the “Unit Limits” displays.

2. The Forecaster accepting a Redeclaration shall verify the Asset ID to confirm that the Redeclaration is applied to the correct Generator/DARD.

3. The Forecaster shall accept any DE requested change for the following:

• Operating limit Redeclarations to reflect physical limitations

• Self Schedule (SS) changes

• De-commit requests

• SS (commit) requests

• LEG maximum Daily Offer Redeclarations

• LEG Hourly limits Redeclarations

• SS pumping energy

• Manual Response rates

• Automatic Ramp rates





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• Claim10/Claim30

• Notification Times (Hot, Inter, Cold)

• Start-up Times (Hot, Inter, Cold)

• Self Dispatch MW

NOTE A Redeclaration request received after the close of the Re-Offer period is taken in accordance with CROP.36002 Redeclarations.

4. The Forecaster shall review each requested change and determine to accept or reject the requested change by performing the following:

A. Use the Current Operating Plan FCA tool to assist in determining to either accept or reject the requested change.

B. If the requested change can be accommodated according to system capacity, reserves and Reliability Coordinator Area/Balancing Authority Area (RCA/BAA) capacity, enter the requested change in the “Unit Limits” display.

• If the requested change results in any commitment changes, use the APF MOI to enter the commitment change into the “Case Inputs, Units” display and issue any appropriate CD.

• If the requested change is approved and affects a current day startup or shutdown or the initial conditions of the next day’s initial SCRA, as required, modify each appropriate SCRA.

C. If the requested change cannot be accommodated, inform the DE of the denial.

D. Enter the reason for any SS or de-commitment denial in the Control Room Event Logserver





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NOTE For combined cycle Generators modeled as a single Generator the following should be performed for a Redeclaration:

• Economic Maximum (Eco Max) Redeclared down due to one of the combined cycle Generators taken off-line

• Eco Max Redeclared down due to combined cycle released for dispatch with at least one Generator off-line

Combined Cycle Redeclarations will normally be performed by the Control Room System Operators in accordance with CROP.36002 Redeclarations.

5. The Forecaster shall not include combined cycle Generator Redeclarations in the initial RAA unless a material condition restricts the output of the combined cycle Generator (e.g., one Combustion Turbine is OOS).

NOTE Ramps are not included in RAA cases but will be shown in SCRA cases.

6. The Forecaster shall select a ramp profile (Hot, Intermediate or Cold) for any Generator that has a start-up from the Day-Ahead Market.

7. If the DE requests a ramp profile different from the bid-in profile to meet their commitment the Forecaster shall perform the appropriate Redeclaration in the “Unit Limits” display and the “ISO Unit Times Data” display of the Energy Market User Interface (EMU).

A. If a known Minimum Generation Emergency exists and the ramp schedule or run through causes or contributes to the Minimum Generation Emergency, deny the ramping request.

NOTE The approved SCRA solution will overwrite the DA Schedule or any prior SCRA schedule in the “Planned Leg MW” column of the “ISO Unit LEG/Posture” display in EMU. When a Designated Entity (DE) requests a Generator be run as a LEG, the UDS will use the schedule in the “LEG Limit” column on the “LEG Units” display. When a value is placed in the LEG Limit column the LEG flag will automatically be set and the UDS will run the Generator as a LEG.

8. For each Generator with a LEG, the Forecaster shall perform the following:

A. Upon a DE request to be run as a LEG (follow LEG schedule), re-declare their hourly Limited Energy Maximums with the DA, SCRA or Generator requested schedule in the “LEG Limit” column of the “ISO Unit LEG/Posture” display.





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B. When Re-declaring a Generator LEG Hourly Max Limit (Schedule), verify the LEG Hourly Max Limit is at least 1 MW greater than the Eco Min in each hour (Unless the Redeclaration is for 0 MW).

B. Upon DE request, Re-declare the Generator Maximum Daily Energy available.





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5.3 Run the RAA Case

5.3.1 Run the RAA case

1. The Forecaster shall determine the status of the Day-Ahead case and perform the following applicable action:

A. If there is an approved Day Ahead case go to step 5.3.1.2

B. If there is no approved Day-Ahead case go to step 5.3.1.3

2. The Forecaster shall set up the RAA case as follows:

A. Duplicate the “APPROVED Day-Ahead” case file, and rename it as an RAA case:

(1) Set up a case to run a Reserve Adequacy study mode PROV.

(2) Set the case end and Resource Scheduling and Commitment (RSC) end hours for Hour 24 of the following day.

B. Remove the case ID from the RSC case window.

C. Remove all Generators from the DA case on the APF MOI “Units” tab

D. Evaluate any newly excluded or created Day Ahead Market contingencies and discuss newly excluded or created Day Ahead Market contingencies with the Operations Shift Supervisor, and as directed by the Operations Shift Supervisor either include or exclude these contingencies in the RAA case.

E. Manually enter any Generator needed for RT reliability as follows:

(1) Compare the Generators from DA case and enter Generators reliability commitments as determined in SOP-RTMKTS.0050.0005 - Determine Reliability Commitment for Real-Time.

(2) Enter any reliability commitments in the APF-MOI “Case Input, Units” display as:

• Storm Constraint Up (SCU) Reliability Commitment

• Voltage Support Up (High) [VAR_UP_HIGH] Reliability Commitment

• Voltage Support Up (Low) [VAR_UP_LOW] Reliability Commitment

• Transmission Constraint Up (TCU) Reliability Commitment

• Reliability Must Run (RMR) Reliability Commitment





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• Special Constraint Resource (SCR) Reliability Commitment

• Fuel Diversity (FUELDIV) Reliability Commitment

• Generator Performance Audits (GPA) Reliability Commitment

(3) Go to and perform step 5.3.1.4

3. If there is no approved Day-Ahead case, the Forecaster shall set up the RT-RSC case as follows and perform the following actions:

A. Duplicate the latest SCRA case file, and rename it as an RT-RSC case

(1) Set up a case to run a Reserve Adequacy study mode RT-RSC.

(2) Set the case start time to the next day for Hour Ending (HE) 01

(3) Set the case end and Resource Scheduling and Commitment (RSC) end hours for HE 24 of the following day


C. Open the Outages tab in the APF MOI, and enter the transmission outages for the day by clicking on the “Populate” button.

(1) Working with Market Admin, set up the topology for the case.

D. Remove all Generators from the original SCRA case on the APF MOI “Units” tab

E. Enters Generator commitments as determined by SOP-RTMKTS.0050.0005 - Determine Reliability Commitment for Real-Time.

F. For local area protection (non-IROL), if post-first contingency load shed is required within 30 min to prepare for the next contingency, flag the Generator that is committed to protect the local area as RMR.

G. Commit any Generator requested by a Transmission Owner or LCC for contingency protection more stringent than OP-19 criteria (i.e., stuck breaker or bus fault without inter-area impact) and flag that committed Generator as SCR.

H. In the APF-MOI “Case Input, Units” display, enter any reliability commitments identified in the ISO Outage Scheduling software as:

• SCU - Reliability Commitment

• VAR_UP_HIGH - Reliability Commitment





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• VAR_UP_LOW - Reliability Commitment

• TCU - Reliability Commitment

• RMR - Reliability Commitment

• SCR - Reliability Commitment

• FUELDIV - Reliability Commitment

• GPA - Reliability Commitment

4. The Forecaster shall enter pump data per step 5.5 of this procedure.

5. Using the DA/RAA Import application, the Forecaster shall select the newly created RAA or RT-RSC case.

6. Using the DA/RAA Import application, the Forecaster shall enter the following:

A. The Generation Requirements for Transmission (GRT) Constraint file

B. The anticipated Fixed External Transactions using the transaction schedules provided by the Tariffs, Schedules and Oasis (TSO) Administrator:

(1) Adjust interchange totals as necessary to reflect conditions that will impact deliverability of certain External Transactions.

C. System wide and Locational Reserve Requirements:

(1) As necessary, adjust reserve numbers on reserve tab for MYS8&9.

(2) As necessary, adjust or enter reserve numbers for HQ.

(3) As necessary, adjust or enter reserve numbers for NB.

(4) Adjust or enter reserve numbers to reflect Generator status.

(5) Adjust or enter the correct Replacement Reserve requirement:

o 160 MW during Daylight Savings Time

o 180 MW during Standard Time

(6) Sets Spinning Reserve requirement to 30%.

(7) Verify the imported System Reserve Requirements are consistent with the requirements stated in CROP.35003, Reserve Requirement Adjustment.





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D. Initialize Zonal Demand.

NOTE

Approximately 15 minutes after the close of the reoffer period, the Forecaster should receive an e mail showing that the Market Monitoring price schedules have been uploaded automatically.

7. The Forecaster shall save the case.

8. The Forecaster shall run the RAA study case.

5.3.2 Review the RAA case

1. Upon RAA case solution, the Forecaster shall perform the following actions: A. Review the following

(1) System wide Ten Minute Spinning reserve (TMSR), Ten Minute Non-Spinning Reserve (TMNSR) and Thirty Minute Operating Reserve (TMOR).

a. If deficient in TMSR, TMNSR or TMOR, consult with the Operations Shift Supervisor before committing additional Generators and verify that a 50% Spinning Reserve requirement can be met in RT and that pumped storage pond levels are adequate for the expected day’s run.

b. When it is necessary to commit for reserve:

i. Utilize the APF MOI General Input “Manage Commitments” tab to determine the least cost capacity to commit

ii. Consider the minimum run time constraints.

iii. All pool scheduled CDs that are created in the RAA case are not issued until the first SCRA case is approved.

B. Load the results into FCA and verify that sufficient capacity for both system and reserve zones has been committed.

C. Use the Commitment Differences Report to determine which Generators were committed in the RSC or if their DA commitment was extended.

2. The Forecaster shall run the “Data Validation report” in the “DA/RAA Import” application and takes any necessary actions.

3. If required for reliability (i.e., due to anticipated storms, hurricanes or other conditions that affect Bulk Electric System reliability), the Forecaster shall commit additional Generators.





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4. The Forecaster shall approve the case in the APF-MOI as follows:

A. Open the “Case Solution” tab

B. Select the Case Approval menu option

C. Select “Approve”

5. Immediately after all case approvals, the Forecaster shall click on the “Approve case” button in the FCA tool for archiving purposes.





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5.4 Run an Intraday RAA (RSC) Case

NOTE If loads are running over by more than 400 MW, and that trend is expected to last through the peak of the day, or there has been a loss of capacity (External Transactions, Wind Deviation, etc.) in excess of 400 MW, and due to either of those reasons the current SCRA case indicates a need for additional commitment, it may warrant running an Intraday RAA (RSC) case. In addition if unplanned transmission outages occur that could create constraints then consider running an Intraday RSC case.

1. If conditions warrant, the Forecaster shall consider running an intraday RAA (RSC) case and if so, perform the following:

A. Copy the current SCRA case and rename it as an RAA case.


C. Set the case start to the beginning of the next hour

D. Set the study mode to “PROV”.

E. Using the DA/RAA Import application, enter the following data if it has changed from the last approved SCRA case:

(1) GRT Constraint File.

(2) The anticipated External Transaction Data.

(3) System Wide and Locational Reserve Requirements.

(4) If the load forecast has been changed, initialize the Zonal Demand in the “DA/RAA” Import application.

F. Run the RSC case.

G. Review and approve the Intraday RSC case as described in step 5.3.2 of this procedure.





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5.5 Schedule Pumping

1. During the Re-Offer period, RAA process and Real-Time, the Forecaster shall be in communications with the DE to receive any Real-Time SS.

2. If requested, the Forecaster shall SS pumps by performing the following:

A. Redeclare the Minimum Consumption (Min Cons) value in the “Demand Limits” display for the MW value and hours of SS requested.

B. Set the Must Run flag for the requested hours.





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5.6 Run the SCRA Case

5.6.1 Run the SCRA case

1. To run the SCRA case, the Forecaster shall:

A. Make a duplicate of the RAA case and re-name as SCRA case.

B. Set up the case to run an SCRA study mode.

C. Input the approved RAA case number into the RSC window.

D. If the re-named SCRA study case has changed from the RSC case or a previously run SCRA case, use the DA/RAA Import application to enter the following data:

(1) Any changes in the “GRT Constraint” file.

(2) The system wide and Locational Reserve Requirements.

NOTE The Forecaster needs to determine which Generators are running and adjust or input the reserve numbers into the Reserve Requirements to reflect actual Generator status.

(3) The anticipated Fixed External Transactions using the transaction schedules provided by the TSO Administrator.

a. Adjust interchange totals as necessary to reflect conditions that will impact deliverability of certain External Transactions.

E. Enter requested changes to Pumped Storage SS for Real-Time operation as described in Step 5.5.

F. Enter any reliability commitment identified in the ISO Outage Scheduling software into the APF MOI “General Input, Manage Commitments” display as:

• SCU - Reliability Commitment

• VAR_UP_HIGH - Reliability Commitment

• VAR_UP_LOW - Reliability Commitment

• TCU Reliability Commitment

• RMR Reliability Commitment

• SCR Reliability Commitment

• GPA - Reliability Commitment





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• (FUELDIV) - Reliability Commitment

NOTE A Generator that has a Claim 10/30 demonstration scheduled (as indicated in the ISO Outage Scheduling software) is not to be put into the SCRA case.

G. Save the case.

H. Run SCRA study.

5.6.2 Review the SCRA solution

NOTE Running the SCRA case gives a security-constrained dispatch to meet ISO load forecast with Generators committed in the DA and RAA processes. Running the initial SCRA case will normally include the SPD and SFT run.

1. Upon completion of the SCRA case solution, the Forecaster shall review the following Report information and perform the applicable action(s):

A. Reserve Zone Summary Report for TMOR:

(1) If deficient in Locational TMOR, commit additional Generators.

(2) When committing for locational reserve, either execute an Intraday RSC case or uses the APF MOI “General Input, Manage Commitments” display to determine the least cost capacity and refer to SOP-RTMKTS.0050.0005 - Determine Reliability Commitment for Real-Time to commit generation.

B. Reserve Summary Report for System wide, TMSR, TMNSR and TMOR:

(1) If deficient in TMOR, commit additional Generators.

(2) Using the Commitment Differences Display, analyze those Generators that were additionally committed or had their DA commitments extended by the RAA with regard to reserve and economics.

a. De-commit any RAA added Generator that is not required or can be replaced by more economic generation

(3) When committing for system wide reserve, either execute an Intraday RSC case or use the APF MOI “General Input, Manage Commitments” display to determine the least cost capacity to commit and also consider the minimum run time constraints.

C. Unit Hourly Details and Commitment Differences Reports:

• Review for problems with Generators minimum down times.





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• Review for ramp schedules and commitments outside of DA schedules.

D. Hourly Generator violations (Ramping, MW output is < or > limits):

• If Ramping violations occur on startup or shutdown enter startup/shutdown profile as Redeclared operating limits.

E. Hourly network violations (Branch flow, Interface flow and Phase angle):

(1) If Branch flow violations exist, manually intervene as necessary by performing the following applicable action(s):

a. With concurrence from the Operations Shift Supervisor, change the limits in the APF MOI “Branch” tab

b. Commit additional Generators.

c. De-commit on-line Generators.

(2) If Interface flow violations exist, as necessary perform the following applicable action(s):

a. With concurrence from the Operations Shift Supervisor, change the limits in the APF MOI “Input Constraints” tab

b. For import limited interfaces, commit additional Generators.

NOTE The magnitude of the interface flow violation is a good indicator of the minimum amount of capacity that must be committed outside of the export area to meet the demand.

i. If there are insufficient Generators on-line outside the export area to meet demand, commit additional Generators outside of the export area

ii. If the Generator MW output is equal to their Emergency Minimum such that there is an excess of generation on-line in the export area:

• Prepare a list of Generators for de-commitment in Real-Time including Generators that have Eco Min Limit and minimum downtime that closely match the magnitude and duration of the interface violation.

F. For any hour that has a violation, open the Case Output Constraint tab and perform the following actions:





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(1) Sort the display by marginal value, from greatest value to least value

NOTE Constraints Labeled as GNRC are generic constraints and do not cause price separation.

(2) Find the constraint that has the largest marginal value associated with it and either adjust generation, or with the concurrence of the Control Room Supervisor, change the limit that is causing the violation.

2. The Forecaster shall import the SCRA case results into the FCA tool as follows:

A. Load the GRT Data

B. Load the Market Data

C. Project the difference between: 1) the sum of Fixed External Transaction purchases and all on-line generating Generator Eco Min Limits and 2) the projected load consumption for all of New England and if the projected difference is less than 300 MW, notify the Operations Shift Supervisor to consider issuing a Minimum Generation Emergency Warning per CROP 25005, Minimum Generation.

3. Using the FCA tool, and DA/RAA Import application, the Forecaster shall prepare the DR Zonal Report as follows:

A. Click the “RTDR” button

B. In the box that opens, verify that the data is correct.

C. Click the “Export RTDR Schedules to MDB” button and verify success.

D. In the DA/RAA Import application, click the “Initialize DR Zonal Forecast” button and verify success.

E. In the DA/RAA Import application, click the “Edit DR Zonal Forecast” button, verify correct values, and manually upload the RTDR schedules to the APF MOI.

F. In the APF MOI, run the DR Zonal Report and check for accuracy.

NOTE The LEG flag defaults to False for each LEG offered in the DA Market. The DE must request this flag be set to True in order to be operated as a LEG in Real-Time operations.

4. The Forecaster shall perform a LEG review as follows:





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A. If the SCRA case uses all of the energy available from a LEG utilize the FCA to evaluate the effect of the loss of sustainable capacity from the LEG.

(1) If capacity loss results in a capacity deficiency discuss with the Operations Shift Supervisor to determine if Posturing is required, or if further commitment is necessary.

(2) If Posturing is required, go to CROP.25001, Posturing and perform required actions.

5. The Forecaster shall use either an intraday RSC case or the APF MOI “General Input, Manage Commitments” display for any commitments.

6. In order to more closely reflect real-time zonal LMP prices in SCRA cases, the Forecaster shall consult with the Operations Shift Supervisor and considering the following conditions, take the applicable actions in the SCRA cases:

NOTE This following process is performed with the recognition that there are times when no actions can be taken because prices are much higher than $100 on a consistent basis due to either fuel prices or fuel scarcity.

A. When prices are greater than $100 and are keying on Ten Minute Spinning Reserve Penalty Prices, refer to the guidelines stated in CROP.35003, Reserve Requirement Adjustments Attachment 1 and determine if the TMSR requirements can be lowered to 30% of the largest New England contingency.

B. For the hours that the above conditions are true, consider reducing the TMSR requirements in the APF MOI “Area Hourly Tab” of the “Input Data” screen.

C. If conditions do not warrant reducing the TMSR requirement per the above guidelines, consider bringing on available off-line Fast Start Generators that the Loader Operator would consider starting in his UDS cases by reviewing Generator pricing in the Fast Start Manual Dispatch display in EMU.

D. When LMP prices are greater than $100 due to constraint limits, consider bringing on Fast Start Generators in the SCRA case that the Loader Operator would consider starting in UDS cases.

E. When prices are greater than $100 due to constraint limits, revise limits to reflect available temporary limits.





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F. When prices are greater than $100 due to constraint limits and the Forecaster is not able to reflect real-time actions (i.e., SPS operation) that would mitigate the constraint, exclude the constraint or skip SFT for the hours necessary.

G. Anytime any Step 5.6.2.6.A through F action is taken notify the Operations Shift Supervisor of each action taken.

5.6.3 Approve SCRA case

NOTE When a case is approved the Forecast Information (FI) reports for Generators, External Transactions and Real-time Demand Response resources are published to secure sites for review by the Lead Participant(s). This information may be accessed by the LCCs and is available for incorporation into Powerflow. When the initial next day SCRA case is approved, the approval will issue CDs for all non-fast start Generators that were committed in the approved RAA case and the SCRA case.

1. The Forecaster shall update the FCA prior to approval of the SCRA case by performing the following:

A. Load the Market Data

B. Load the (GRT) constraint file

NOTE Based on system conditions, the Operations Shift Supervisor determines the amount of capacity margin that is required in the FCA.

2. Prior to the Operating Day, the Forecaster shall verify that the capacity margin on the updated FCA is equal to or greater than the amount directed by the Operations Shift Supervisor.

3. If the updated FCA indicates a deficiency of capacity in the ISO-NE System, or ISO-NE Reserve Zone, and all available Generators have been committed, the Forecaster shall perform the following:

A. Review/edit the Real-time Demand Response hourly schedules with the Operations Shift Supervisor prior to approving the SCRA case.

B. If approving the initial SCRA case after the close of the reoffer period that has a forecasted Demand Response schedule, send an email to “DR Audits” group mailbox ([email protected]) to notify the DR group of that fact.

4. The Forecaster shall run the SCRA Data Validation Report in the DA/RAA Import application and make changes as necessary.

mailto:[email protected]





ISO-NE PUBLIC

5. The Forecaster shall perform the following actions:

A. Select the “Case Solution” menu option

B. Select the “Case Approval” option and select “Approve”.

C. Approve the FCA 6. The Forecaster shall contact each long lead-time Generator committed during

the RAA process and communicate start-up times.

A. This commitment must be accompanied by the creation and the issuance of a manual CD.

B. In addition, any Generator that is committed after 1830 on the day prior to the operating day (OD-1) must have a manual CD created for that commitment in addition to being committed in the “Units” tab in the APF MOI if a subsequent SCRA case is to be run.

7. The Forecaster shall print and distribute the following Current Operating Plan (COP), reports using the DA/RAA Import application:

• System Summary

• System Reserve Summary

• LEG Summary

• Commitment Differences

• Unit Hourly Report Loading

• LMP Summary

• Startup/Shutdown Summary

• Transaction Hourly

• Asset Related Demand Hourly Clearing

• Reserve Zone Summary

• Constraint Summary

• Zonal DR Forecast

• Wind Hourly Report Unit Loading

• Capacity Analysis

• Fast Start Report





ISO-NE PUBLIC

8. If the ISO Outage Scheduling software Must Run report indicates any Generators are scheduled for a Claim 10/30 or MRR demonstration, the Forecaster shall highlight the Generators on a hard copy and deliver the hard copy to the Senior System Operator.

9. The Forecaster shall provide hard copy reports of the COP as requested by Control Room staff.

5.6.4 Post-SCRA Case Approval Discussions

NOTE A discussion allows the opportunity to familiarize Control Room System Operators with the upcoming load / Generator expectations.

1. After each SCRA case approval, the Forecaster shall provide a summary of the SCRA case to the Operations Shift Supervisor and discuss the following conditions and the applicable action(s) to be taken:

• Current / upcoming weather conditions

• Current Load Forecast Deviation and if load is running 400 MW from expectations, determine whether any remedial actions are needed

• The latest weather report and determining if any major revision to the weather forecast requires re-running the load forecast.

o If latest weather forecast indicates any major change, contact the weather providers to verify the weather forecast.

• If the load forecast is running over but a revised forecast indicates no changes to the peak, discuss and consider increasing the surplus to be equal to or greater than the MW amount that the load is running over

• The surplus capacity requirement (taking into account transactions scheduled on tie-lines and remaining available transfer capability).

2. If the FCA indicates a deficiency of capacity at the ISO-NE System, or ISO-NE Reserve Zone, and all available Generators have been committed, the Forecaster shall meet with the Operations Shift Supervisor and perform the following:

A. Review the Real-time Demand Response hourly schedules.

B. Discuss the need to call for capacity available when OP-4 Action 7 is declared IAW SOP-RTMKTS.0050.0005 - Determine Reliability Commitment for Real-Time.





ISO-NE PUBLIC

5.7 Update SCRA During Operating Day

5.7.1 Run an Updated SCRA Case

1. The Forecaster shall update the SCRA periodically to reflect:

• Generator commitment and de-commitment requests

• SS changes

• DE Redeclarations

• Submittal and cancellation of Real-Time External Transactions

• Updates to the ISO load forecast

• Line Outages

• Line limit changes

• Hourly Real-time Demand Response MW schedules

2. If the SCRA is updated following an Intraday RSC case, the Forecaster shall perform the following actions:

A. Duplicate the Approved Intraday RSC case

B. Set up the case to run an SCRA study mode

C. Enter the approved Intraday RSC case number into the RSC window

3. If the SCRA is not updated following an Intraday RSC case, the Forecaster shall make a duplicate of the latest approved SCRA case and rename it for the current case time.

4. The Forecaster shall set the start time of the SCRA case being run to reflect the future hours for that case.

5. The Forecaster shall verify the case is set to study mode SCRA.

6. Using the DA/RAA Import application the Forecaster shall enter the following data if it has changed from the last SCRA case by completing the following applicable action(s):

NOTE Forecasters can only perform this function when on the FCSTPRD1 and the OPSCN2 machines in the Control Room. When making changes in the GRT, never over write a calculation. Only make changes to a cell that has a number in the Excel Spreadsheet Formula Bar. Always confirm that the Operations Shift Supervisor, Security Operator and the Forecaster all are aware of and agree on any changes that are made.





ISO-NE PUBLIC

A. Verify GRT Constraint file and if GRT file needs to be updated, perform the following actions:

(1) Click on the GRT Export Icon in the Main Control Center (MCC) Shortcuts Folder or access using //:RTSMB/GRT_RW.

(2) Open the GRT Spreadsheet for the appropriate day.

(3) Make changes as necessary in the GRT.

(4) To save and export the GRT spreadsheet, click the “Export GRT” button.

(5) Close GRT spreadsheet.

(6) Re-import the GRT data into APF MOI using DA/RAA Import application for the “Upload Constraint File” and “Upload Locational Reserve Requirements”.

(7) Re-import the GRT into Cap Analysis using the “Load GRT Data” button in that application.

B. Verify RCA/BAA External Transaction data as follows:

(1) Adjust interchange totals as necessary to reflect conditions that will impact deliverability of certain External Transactions.

(2) Do not commit any off line Generators (with the exception of Fast Start Generators) to support External Transaction sales.

C. Update system wide and Locational Reserve Requirements.

D. Update “Units” tab to reflect Generator commitment changes.

E. Update Pumped Storage fixed and dispatchable demand.

F. If the load forecast has been changed, initialize Zonal Demand in the DA/RAA Import application.

G. Hourly Real-time Demand Response MW schedules.

7. Using the DA/RAA Import application, the Forecaster shall initialize the DR Zonal Forecast, edit the DR Zonal Forecast, and verify the DRI Zonal Forecast report in the APF MOI is correct.





ISO-NE PUBLIC

NOTE In the event of a late SCRA_HE11 case approval, the COP needs to be updated so that it is current in order to provide the correct Generator initial conditions for the DA market next day case. If the Generator in question is a SS, it is necessary to run a new SCRA case to incorporate the change. If the Generator is pool scheduled, the correction to the initial conditions is accomplished by the issuance of a manual CD via the “General Input, Manage Commitments” display.

8. The Forecaster shall performs the following actions:

A. Run an SCRA case.

B. Perform SCRA data validation.

C. Review the SCRA solution and commits Generators as necessary.

NOTE It is acceptable for naturally occurring surplus to be present due to the DA clearing and/or Real-Time Self-Scheduling or self-commitment by DEs.

9. The Forecaster shall update the FCA prior to approval of the updated SCRA case by performing the following actions:

A. Load the GRT constraint file.

B. Run the FCA application.

C. Review the FCA and attempt to maintain as close to the reserve requirement specified by Operations Shift Supervisor.

D. If the updated FCA indicates a deficiency of capacity in the ISO-NE System, or ISO-NE Reserve Zone, and all available Generators have been committed, review/edit the Real-time Demand Response hourly schedules with the Operations Shift Supervisor prior to approving the SCRA case.

13. The Forecaster shall post the results in accordance with Step 5.6.3.

A. Approves the SCRA case

B. Approves the FCA

C. Posts the results in accordance with Step 5.6.3





ISO-NE PUBLIC

5.8 Startup Cancellation and De-Commitment of Generators

5.8.1 Decision to Cancel S/Us or De-Commit Generators

1. When condition(s) have changed from the original commitment, the Forecaster shall determine if any Generator committed as part of the RAA process should be de-committed.

Examples of such conditions are:

• Actual load less than originally forecast

• Unexpected availability of Generators (e.g., a Generator coming online from a forced outage)

• Unexpected availability of contract energy via inter-tie (e.g., due to restoration of transmission capability)

• Excessive Real-Time Generator SS

2. The Forecaster shall select the highest cost Generators from the APF MOI “Case Input Scheduling” display for startup cancellation or De-commitment based on the following:

• Operating Rate o Generator energy offers from 0 - Eco Min o Generator No Load cost

• Generator minimum run time

• Generator minimum down time

• Future startup schedule

• Ability to maintain system reliability

• If a natural gas fired Generator has been ordered online subsequent to the Day Ahead Market and that Generator has procured gas, the startup is not cancelled unless there is a reliability concern that needs to be addressed.

o In addition, when a natural gas fired Generator is given a schedule in the RAA/SCRA process, that schedule is honored in its entirety, unless there is a reliability issue.

• When a Generator clears in the Day-Ahead Market as SS and then requests to de-commit in real time, the Forecaster performs a reliability assessment in accordance with SOP-RTMKTS.0050.0005, Determine Reliability Commitment for Real Time and performs the applicable action(s).





ISO-NE PUBLIC

o This reliability assessment is performed to determine if the reliability criteria determined by the appropriate transfer limits in the RMR worksheet are satisfied with the requested de-committed Generator offline and any actions that are to be performed.

If the target value for the reliability criteria is deficient, use the “General Input, Manage Commitments” display to commit additional Generators to meet the reliability criteria target.

If additional Generators are not available due to notification time limits, or if there are any scheduled or unscheduled outages, the Generator requesting the SS de-commitment has its SS flag removed and is kept on line.

While using “General Input, Manage Commitments” display, if the Generator requesting the de-commitment is the economic Generator to be called on, the Generator is not to be de-committed and the SS flag is to be removed.

The same process of a Day-Ahead SS de-commit request is applicable to capacity commitments.

5.8.2 Communications

1. When a decision is made to cancel a startup or de-commit an on-line Generator for future hours, the Forecaster shall promptly notify the Generator of the new schedule.

2. If ISO requests a start prior to the Generator satisfying its Minimum Down Time and the Generator agrees to waive its Minimum Down Time, the Forecaster shall make an entry in the Control Room Event Logserver.

3. When a Generator has been de-committed or a start-up has been cancelled, the Forecaster shall make an entry in the Control Room Event Logserver.

4. The Forecaster shall enter all supplemental commitments and all manual CDs into the Control Room Event Logserver.





ISO-NE PUBLIC

6. Performance Measures None.

7. References NPCC Directory # 5 Reserve

ISO New England Inc. Transmission, Markets and Services Tariff, Section I.2.2, Definitions

ISO New England - ISO New England Inc. Transmission, Markets and Services Tariff Section III, ISO New England Market Rule 1 - Standard Market Design (Market Rule 1)

ISO New England Manual for Market Operations Manual M-11

• Section 5 - Scheduling and Dispatch Philosophy and Tools

• Section 6 - Scheduling Strategy and Methods

ISO New England Manual for Definitions and Abbreviations Manual M-35 (Manual 35)

ISO New England Operating Procedure No. 4 - Action During a Capacity Deficiency (OP-4)

ISO New England Operating Procedure No. 8 - Operating Reserve and Regulation (OP-8)

ISO New England Operating Procedure No. 21 - Energy Inventory Accounting and Actions During an Energy Emergency (OP-21), Appendix B - Electric/Gas Operations Committee’s (EGOC) Operations Communications Protocol (OP-21B)

SOP-DAMKTS.0040.0010 - Create Day Ahead Market Schedule

SOP-OUTSCH.0040.0010 - Create Demand Forecast

SOP-OUTSCH.0040.0020 - Create Seven-Day Capacity Margin Forecast

SOP-RTMKTS.0050.0005 - Determine Reliability Commitment for Real-Time

SOP-RTMKTS.0050.0007 - Perform Cold Weather Condition Operations

SOP-RTMKTS.0050.0030 - Produce Forecast Daily Report

SOP-RTMKTS.0110.0015 - Flagging for RT Market Settlements

CROP.10002 Implement Capacity Remedial Actions





ISO-NE PUBLIC

CROP.25001 Posturing

CROP.25005 Minimum Generation

CROP.35003 Reserve Requirement Adjustment

CROP.36002 Redeclarations

8. Revision History Rev. No. Date Reason Contact

-- 08/30/16 For previous revision history, refer to Rev 50 available through Ask ISO Thomas Knowland

51 09/27/13 Section 5.3.1.6.C – Added Replacement Reserve requirement William Callan

52 12/05/13 3.1.G, added Forecast Responsibility to change fuel schedules; 5.1.4 NOTE, modified to reflect current practice; 5.2.9, removed Step. Former content is now covered in Step 5.3.1.6.C; 5.3.1.2.D, rewritten to reflect current practices; 5.3.1.6.C.6, added to incorporate a part of Step 5.2.9 that was removed; 5.6.1.4.D, removed Step. Former content is covered in Step 5.6.2.3; Section 5.8 Added to Change Fuel Schedules for Winter Readiness Program; 5.9.3.2, deleted, information now covered in Section 5.8; Attachment A, total rewrite to reflect current practices; Attachment D, changed name for Step 3. Removed Step 3.B former content now covered in Step 6.A.(1);

William Callan

53 05/30/14 Biennial review by procedure owner completed; Globally, Per ROC directive, eliminated the use of the term “shall” and made the applicable grammar changes; Section 2, Removed paragraph explaining LER vs LEG. No longer necessary; 3.1.E Clarified when Forecasters are responsible for commitment 3.1.F, Added task of exempting Generators from mitigation; 5.1.4, Language change from notifications to Electronic Bulletin Board notices; 5.1.4 Note – Eliminated redundant reference to gas notices 5.2.4.D, Added “or de-commitment” to step; 5.2.8.C, Added “Generator Maximum” for clarification purposes 5.3.1.2.A, Language change; 5.3.1.2.E.(3), Added step; 5.3.1.3.A, Language change; 5.3.1.3.F, Added language clarifying SCR and RMR commitment; 5.3.2.1, Clarified step to include all available dispatchable transactions; 5.3.2.1.B.(2), Deleted reference to Attachment B which will be retired due to the retirement of SAL3 and SAL4;

Continued on next page

William Callan





ISO-NE PUBLIC

Rev. No. Date Reason Contact

53 (cont) 05/30/14 (cont)

Continued from previous page

5.6.2.1.A.(2) Changed from Capacity Priority list to reliability priority list due to locational requirement; 5.6.2.1.B.(3) Added “system wide” for clarification; 5.6.2.1.B.(4), Clarified step to include all available dispatchable transactions; 5.6.2.1.C, Included additional report for reviewing; 5.6.2.1.E.(1) Changed sequence of tasks; 5.6.2.1.e.(2) Changed sequence of tasks 5.6.2.1.6.A, Changed minimum spinning reserve requirements to conform with current operational practice.; 5.6.2.2.C,Deleted reference to procedure and added reference to a CROP; 5.6.2.4.A.(2) Changed reference from an SOP to a CROP; 5.6.2.6.B – Changed reference from an SOP to a CROP; 5.6.2.6.B - Changed Spinning Reserve criteria (%) to conform with current practice; 5.6.2.6, Added NOTE prior to Step 5.6.2.6.A concerning high energy prices due to fuel prices or fuel scarcity; 5.6.2.6.A,Changed Spinning Reserve criteria (%) to conform with current practice; 5.6.2.6.C Added clarification 5.6.3.7,Added “Wind Unit Hourly Report” loading; 5.7.1.6.A.(4), language change; 5.7.1.6.B,Changed wording to clarify the step; 5.7.1.6.C, Grammar changed; 5.7.1.6 NOTE, Listed the new IT identifier for the spare market machine for Forecasters in the restoration room; 5.8.1 Added note concerning alternate fuel schedules for fast start units Attachment A, Added steps for the creation of the Metrix Zonal Load Forecast; Attachment B, Deleted Generator information due to the retirement of SAL3 and SAL4 on 05/31/14.; Attachment D:

2.A.(1), a Deleted statement about Generator specific details due to ISO- NE Information Policy change after FERC Order on electric gas coordination ; 5.A.1, Changed “aggregate” to “unit specific” to reflect ISO-NE Information Policy change; 5.A.2, Changed “aggregate” to “unit specific” to reflect ISO-NE Information Policy change; 5.A.3,Added step to e mail aggregated gas consumption to ISO-NE management personnel

William Callan (cont)

54 12/05/14 Updated to conform to changes in the procedure due to the Energy Market Offer Flexibility project.

William Callan





ISO-NE PUBLIC


55 06/16/15 Restored grammar for directed actions to be in the present tense; Entered minor corrections and process changes after the Energy Market Offer Flexibility project; 2. Background- Changed to correct definition of RSC 3.1.D - Added clarifying language; 3.3 - Added clarifying language; 4- Added clarifying language; 5.1.2 -Substituted abbreviation; 5.1.3 - Grammar; 5.2.2 - Added clarifying language; 5.2.4.B - Substituted abbreviation; Added clarifying language; Removed dated material no longer pertinent due to Hourly Markets changes; 5.2.5 - Added clarifying language; 5.2.6 - Added clarifying language; 5.2.7 - Added clarifying language; 5.3.1.3.E - Deleted redundant note; 5.3.1.6.C.1 - Added clarifying language; 5.3.1.6.C.6 - Changed to reflect current CR operating practice; 5.3.1.6.C.7 - Removed reference to retired procedure and referenced the pertinent CROP; 5.3.1.6.D - Added step; 5.3.2.1.A.(1) a - Added clarifying language; 5.3.2.1.A.1.b.iv Removed unnecessary language; 5.4 - Added clarifying language; 5.4.1 - Added clarifying language; 5.6.2.B.2 - Added clarifying language; 5.7.1 - Grammar; 5.7.7 - NOTE changed to reflect current operating practice; Removed language no longer material; 5.7.8 - Removed language no longer material; Attachment A - Changed to reflect current operating practices;

William Callan





ISO-NE PUBLIC


56 05/26/16 Biennial review completed by procedure owner; Headers Procedure Owner and Revision History, replaced William Callan with Thomas Knowland 3.2 – Clarified the responsibilities of the Forecaster regarding to Generator de-commitment Section 4. .Controls – Clarified CD cancellation process 5.3.1.8.B iii – Changed method of communicating any FCM compliance report units to the CR staff 5.3.2.1.A.1.b.iii – Removed reference to evaluating RT dispatchable contracts within the RAA case since it is performed by the Operations Shift Supervisor in RT 5.6.2.1.b.4 - Removed reference to evaluating RT dispatchable contracts within the SCRA case since it is performed by the Operations Shift Supervisor in RT 5.8.2.1 – Clarified the actions by the Forecaster in regards to Generator de-commitment Section 7, Deleted SOP-RTMKTS.0110.0010, replaced SOP-RTMKTS.0120.0020 with CROP.10002, and added CROP.36002; Attachment A – Modified to reflect current operating practices and to incorporate CTS related process changes, correct referred to procedures and titles, and modified to include “Correction to Redecs” process;

Thomas Knowland

57 08/30/16 Added required corporate document identity to all Footers; Truncated the Revision History per SOP-RTMKTS.0210.0010 Section 5.6; Attachment A:

Changed time of flag review to after the GDMA bridge runs; Added step to wait for Mitigation Schedule emails prior to running SCRA cases; Added steps to run RMR Worksheets; Added step to verify all manual commitment decisions for prior day; Added clarification on time to run gas pipeline report;

Thomas Knowland

58 01/16/17 Step 5.3.1.8, deleted step and all sub-steps (regarding the FCM Compliance Report to reflect changes to Market Rule 1 Section 13.6.2.1.1.2); Section 5.4, modified 1st NOTE; Attachment A, page 39, deleted checklist step (re: the FCM Compliance Report) to be consistent with to deletion of Step5.3.1.8 and sub-steps;

Thomas Knowland

9. Attachments Attachment A - Forecaster Task and RAA Process Checklist

Attachment B - Retired (05/30/14)

Attachment C - Retired (06/01/12)

Attachment D - Abnormal/Emergency pipeline Condition Alert to Generators





ISO-NE PUBLIC

Attachment A - Forecaster Task and RAA Process Checklist

NOTE

This checklist should be kept for the current month plus one month in the past.

Night Shift

Forecaster on Duty: _____________________ Date: _____________________

Sign In and Review Control Room Event Log Server.

Copy SCRA_20 Setup Case. Rename it the SCRA_20 Case and run with SFT off.

Import results into the FCA. Evaluate results. Export RTDR from the FCA. Initialize and edit the RTDR values using the DA/RAA Import Utility.

Perform Data Validation, review the Case Approval page for CDs to be issued, and approve the SCRA_20 case and the FCA.

Verify that the Mitigation Schedule updated successfully (Email received ~1830). Do not run the SCRA_B case or manually commit Generators for the next day until this email has been received or in coordination with MMM.

Review all Gas Pipeline notifications.

Review Elevations and Update BSW & NFLD Max Daily Energy.

Call all Generators that are deficient on the TSO Nominations Report by 2100.

Run SCRA_B and import results into the FCA and evaluate. Export RTDR from the FCA. Initialize and edit the RTDR values using the DA/RAA Import Utility.

Check Reports, compare Capacity Analysis with the Senior System Operator & notify Operations Shift Supervisor of forecast Min Gen conditions.

Perform Data Validation, review the Case Approval page for CDs to be issued, and approve the SCRA_B case and the FCA by 2300.

Import results of SCRA_B case into the RMR Worksheets. Verify that all areas have sufficient generation to satisfy the limits from the GRT. Save the RMR Worksheet.

Copy the SCRA_B case and rename it the SCRA_07 case, and run with SFT off.

Initialize and edit the DR Zonal Forecast.

Perform “Correction to Redecs” process.





ISO-NE PUBLIC

Review all flags and send necessary emails IAW SOP-RTMKTS.0110.0015 - Flagging for RT Market Settlements (0200).

Review manual Commitment Decisions for the prior day. Verify the start hour is the first full hour of commitment in both GDMA and Opralog.

If in OP-4 the previous day, or if either a RTDR or RTEG audit was performed in the previous day, perform Load Reconstitution IAW SOP-OUTSCH.0040.0010 - Create Demand Forecast.

Update Historical Load Log with Log 7 data and weather observations.

Produce Forecast Daily Report for the current day IAW SOP-RTMKTS.0050.0030 - Produce Forecast Daily Report. Check previous day supplemental commitment for accuracy and add or delete as necessary for FERC metrics reporting.

Verify Supplemental Commitments are recorded in the Logserver IAW SOP-RTMKTS.0110.0015 - Flagging For RT Market Settlements.

Review Elevations and Update Bearswamp & Northfield Max Daily Energy. (0300).

Complete the Metrix Zonal Load Forecast and save to \\RTSMB\Zonal Forecast files\Internal Folder.

Begin the process to Create Initial Next Day System Demand Forecast IAW SOP-OUTSCH.0040.0010 - Create Demand Forecast after the 0300 weather forecast has been received. (0300 - 0500).

Import the GRT changes from the Security Operator. Update the current day RMR Worksheet with calculated values and save the worksheets. (0400).

Complete Forecast portion of Operations Shift Supervisor Daily Report (0400).

Export Initial Next Day System Demand Forecast (0500).

Process Zonal Load Forecast File in the \\RTSMB\Zonal Forecast Files\Internal Folder. Notify TSO that the file is ready to upload to the Web.

Export and approve the 7- Day Capacity Margin Forecast by 0510 IAW SOP-OUTSCH.0040.0020 - Create Seven Day Capacity Margin Forecast.

Perform Data Validation, review the Case Approval page for CDs to be issued, and approve the SCRA_07 Case and the FCA (0530 - 0600).

Update Forecaster Turnover Sheet (0600).





ISO-NE PUBLIC

Day Shift

Forecaster on Duty: _____________________ Date: _____________________

Sign in and Review Control Room Event Logserver.

Review all Gas Pipeline notifications.

Review Elevations and Update Bear Swamp & Northfield Max Daily Energy.

Copy SCRA_07 case and rename it the SCRA_11 Case, and run with SFT off.

Initialize and edit the DR Zonal Forecast.

Review all current and next day transmission and generation outages in the ISO Outage Scheduling Software. From the Transmission Outages Request, Forecaster Print View, perform reviews in Outage Scheduling Software.

IAW SOP RTMKTS.0050.0005 - Determine Reliability Commitment for Real-Time and based on the review of the Outage Scheduler Software completed in the step above, prepare a list of Generators required for reliability to give to the DA representative at the 0845 meeting

Attend meeting with Day Ahead Market Administrators and Outage Coordinators (0845).

Create revised Next Day System Demand Forecast and export by 0945 IAW SOP-OUTSCH.0040.0010 - Create Demand Forecast (0900 - 0930).

Export and approve the revised 7 Day Capacity Margin Forecast IAW SOP-OUTSCH.0040.0020 - Create Seven-Day Capacity Margin Forecast. Send System Demand Forecast email while in this application. (0930 - 1000).

Check with the Generation Operator for any current day HE 24 Redecs and if necessary update the COP. Perform Data Validation. Review the Case Approval page for CDs to be issued. Approve the SCRA_11 Case and the FCA (0930 - 1000)

Use Forecaster DAM Case input email template in MCC shortcut folder to notify and record any Generator needed for reliability, any Generator with minimum run carryover, or any Generator with HE24 SS or de-commitment.

Copy SCRA_11 Case and rename it the SCRA_20_Setup Case. Use this case to make COP changes in the current day for the Night Shift Forecaster use.

Perform Reliability Analysis for next day (1000 - 1700) IAW SOP-RTMKTS.0050.0005 - Determine Reliability Commitment for Real-Time. Contact long lead time Generators if necessary prior to close of DAM. Reliability Generator startup orders should commence after Reoffer Period Closes.





ISO-NE PUBLIC

Review night Forecaster flagging finalizations, documents and emails IAW SOP-RTMKTS.0110.0015 - Flagging for RT Market Settlements.

Create Look Ahead sheet and attend afternoon meeting with Outage Coordinators and Operations Shift Supervisor (1300).

After DAM is Approved

True Up Bids to ISO Outage Scheduling software (Redecs) IAW CROP.36002 Redeclarations (1400).

In APF/MOI, copy Approved Day Ahead (DA) Case and rename it as an RAA case.

Set up to run Reserve Adequacy (RAA) Study Mode – PROV.

Set the “Case end” and “RSC end” for HE 24 of the following day.

Remove all DA committed and decommitted Generators from the “Units”.

Enter Real Time Supplemental Generators, committed for reliability.

Using the DA/RAA Import Application, upload the next day GRT constraint file.

Verify that the Mitigation Schedule Update Email has updated successfully (Email comes in at ~1415). Do not run the RAA case until this email has been received or in coordination with MMM.

Initialize the anticipated Fixed External Transactions.

Upload System Reserves and Locational Reserve Requirements (verify requirements are set consistent with CROP.35003, Reserve Requirement Adjustments). Add in the seasonal Replacement Reserve Requirement value.

Set Spinning reserve requirement at 30% but analyze that sufficient Operating Reserve is available to satisfy a 50% requirement and that water inventory will be sufficient to provide necessary reserves.

Initialize the Zonal Demand.

Input SS pump data into the EMU “Demand Limits” display.

Enter standard Generator ramp profiles into the EMU, if required, should be entered as a Redeclaration. Customized ramp profiles, if requested, should be entered as a Redeclaration to an existing standard ramp profile.

Run RAA case, check Reports and FCA.

Enter any necessary manual capacity adjustments to the FCA.





ISO-NE PUBLIC

Perform Data Validation, review the Case Approval page for CDs to be issued, and approve RAA Case and associated FCA.

Duplicate the RAA Case and rename it the SCRA_A Case. Set Study Mode to SCRA.

Check Generator schedule synchronization between SCRA_20_Setup Case and the SCRA_A case.

Import results into the FCA. Evaluate results. Export RTDR from the FCA. Initialize and edit the RTDR values using the DA/RAA Import Utility. Prior to approving the SCRA_A case, discuss any positive results with the Operations Shift Supervisor. Email “DR Audits” group if approving SCRA_A case with DR in it.

Perform Data Validation, review the Case Approval page for CDs to be issued, and approve the SCRA_A case and the FCA (1700).

As appropriate, brief the Operations Shift Supervisor and Senior System Operator.

Import results of SCRA_ A case into the RMR Worksheets. Verify that all areas have sufficient generation to satisfy the limits from the GRT. Save the RMR Worksheet.

Complete Forecast portion of Operations Shift Supervisor Daily Report (1700).

Email Pipeline report after approval of the SCRA_A case and before by 1730.

Update Forecaster Turnover Sheet (1730).





ISO-NE PUBLIC

Attachment B - Retired (05/30/14)





ISO-NE PUBLIC

Attachment C - Retired (06/01/12)





ISO-NE PUBLIC

Attachment D - Abnormal/Emergency Pipeline Condition Alert to Generators

I. Instructions

1. Notices Indicating Abnormal and/or Emergency Conditions on the Pipeline Infrastructure Serving Generators

NOTE Notices indicating abnormal and/or emergency conditions on the pipeline infrastructure serving a Generator in the ISO RCA/BAA could come in the form of, but not limited to, Operational Flow Orders, Imbalance Warnings or even a verbal notification.

A. When electronic and or verbal notices indicating abnormal and or emergency conditions on the pipeline infrastructure serving a Generator in the ISO RCA/BAA are received, the Forecaster notifies the Operations Forecast and Scheduling Supervisor (or designee)

(1) The Forecaster reviews this information and depending upon the severity of the condition may pass the publicly available information along by drafting an email and submitting it to Customer Service for dissemination to each applicable Generator Designated Entity (DE) management contact(s) and/or Lead Market Participant (MP) contact(s).

NOTE The following guideline or one tailored to the current situation can be used as a template for drafting this notification;

“ISO-NE has received the following information via the publicly available notices published by the gas pipelines:

(Insert Notice, such as Operational Flow Order or Force Majeure, etc.)

“Because of this situation, it is critical that each applicable Generator DE or Lead MP provide ISO-NE with up to date and reliable estimates of each Generator current and future capabilities including the ability to have fuel for a Generator under their control. This includes immediately reporting any information that may prevent a Generator from operating in accordance with submitted offer data, including, but not limited the following:

o Planned, Maintenance and or Forced outages of the Generator facilities as soon as that information is available

o Immediate reporting of any updates to outages including overruns and or early returns to service of the Generator facilities

o Any high risk activities at a Generator location that may reduce its capability or place the capability at risk

o Any fuel reductions or outages that may limit a Generator ability to perform in any way





ISO-NE PUBLIC

o Any changes to any operating limits of a Generator which must reflect the most accurate and up to date information available

o Any changes at all in a Generator ability to follow dispatch instructions including manual response rates, ability to provide reserve, ability to provide energy, and/or ability to provide capacity

o Any changes in projected Generator self schedules

It is incumbent that each Generator DE/Lead MP provides this information, as well as all other information required under ISO rules and procedures. If you should have any questions please contact the ISO New England Control Room Forecast Desk at (413) 535-4340.

2. Communicate Abnormal Conditions to ISO New England System Interstate Pipelines

A. Whenever ISO enters or exits any abnormal and or emergency condition the on-shift Forecaster (or designee) immediately contacts the five (5) interstate pipeline company control rooms and within the limits of the ISO New England Information Policy notify each interstate pipeline company of each abnormal condition, the action(s) taken and any impact(s).

(1) The types of conditions/events that might trigger the Forecaster to make notifications can include, but are not limited to, the following:

a. Whenever an unexpected start up and or ramp up of a gas-fired Generator on a pipeline may adversely impact pipeline operations, the Forecaster should provide notification of the general reason.

b. Whenever there is an implementation of the actions of Master/Local Control Center No. 2 - Abnormal Conditions Alert and while respecting the limits of the ISO New England Information Policy, the Forecaster should provide notification of the general reason for the alert including transmission constraints and or capacity constraints and the potential issues that may arise that may impact electric and gas operations.

c. Whenever there is an implementation of the actions of ISO New England Operating Procedure No. 4 - Action During a Capacity Deficiency, the Forecaster should provide notification of any action(s) impacts on gas and electric operations

d. Whenever there is an implementation of the actions of ISO New England Operating Procedure No. 7 - Action in an Emergency, the Forecaster should provide notification of any action(s) impacts on gas and electric operations

e. Whenever any other condition/event on the ISO New England System requires any coordinated communication(s) to regain or maintain reliable operations





ISO-NE PUBLIC

3. Forecaster Responsibilities during Abnormal Pipeline Conditions

A. When there is indication of abnormal conditions/events on the interstate pipeline system serving the New England RCA/BAA the on-shift Forecaster (or designee) performs the following actions:

(1) Confirm the following for Generators on the gas pipelines:

a. That each Generator has the ability to operate in accordance with the energy schedule and capacity limits provided by ISO when committed in the RAA process or Day Ahead Markets

b. That each gas-fired, fast-start Generator is available to supply Claim 10 and 30 minute reserves for the next operating day

(2) Discount any Generator that is not able to provide the services in the Current Operating Plan and as applicable, commit other Generators

4. Determine the Generator Fuel Schedules

A. Each day at 1700, the on-shift TSO Administrator performs the following:

(1) Use the application in Control Room Event Logserver to complete a survey confirming the fuel that will be used by each dual-fuel Generator for the next operating day.

(2) Upon completion of the survey, provide a report to the on-shift Forecaster, the Operations Shift Supervisor and the Supervisor, Operations Forecast and Scheduling.

a. If a particular fuel is in short supply, the Forecaster will use the survey information report to determine each supplemental Generator that will be committed.





ISO-NE PUBLIC

5. Generator Specific Fuel Burns to Interstate Gas Pipelines

A. Each evening after the RAA process is complete, the on-shift Forecaster:

(1) Prepares the Generator specific hourly fuel burns to each pipeline report for the next operating day.

(2) Emails a copy of the Generator specific hourly fuel burns to each pipeline report to the following pipeline contacts:

a. Algonquin (AGT)

b. Iroquois

c. Maritimes and Northeast (M&N)

d. Portland Natural Gas Transmission System (PNGTS)

e. Tennessee Gas (TGP)

(3) E-mails the next day aggregated total gas consumption for all of the interstate personnel to Operations Management.

6. Collect Pipeline Bulletin Board Data

A. Each evening after the RAA process is completed, the on-shift TSO Administrator runs the 0000-1000 Nominations Report for the current gas day and the 1000-2400 Nominations Report for the future gas day and use these reports to determine which gas-fired Generators will have the gas required to the meet the energy schedule and capacity limits provided by ISO when committed in the RAA process or Day Ahead Markets.

(1) If it is determined from the report that a Generator has not nominated and scheduled gas up to their meter, that Generator DE will be contacted and requested to confirm if gas will be scheduled and whether the Generator is expected to meet the energy schedule and capacity limits provided by ISO when committed in the RAA process or Day Ahead Markets for the remainder of the current gas day or the new gas day.

(2) The Forecaster will use the information provided in the reports, the information from the Generator DE, and all known interstate pipeline conditions and the ISO New England RCA/BAA to determine if supplemental Generator commitments are required to ensure reliability.





ISO-NE PUBLIC

7. Daily Communications with Pipelines and Weekly Outlook Report

(1) During abnormal and or stressed system conditions these communications may be more frequent and occur over the weekend periods

(2) As part of these communications and after consultation on the Interstate Pipeline conditions, on each Friday of every week, the Supervisor, Operations Forecasting and Scheduling (or designee) produces a weekend outlook report for operational use within the ISO.

8 Supplemental Commitment due to Potential Fuel Issues

A. The on-shift Forecaster and Operations Shift Supervisor (in consultation with off shift management if required and time constraints allow) determines if Supplemental Commitment of Generators is required to meet the Load and Reserve Requirements in New England by considering the following factors:

(1) Expected weather conditions, (this is particularly acute during extreme heat or cold weather conditions when a more conservative approach is required to ensure reliability)

(2) External area ties and resource availability/capability

(3) Regional gas pipeline conditions

(4) Transmission availability into local areas dependent upon gas-fired generation

(5) Generator availability projections, fuel surveys and availability of long lead time generation

(6) The Forecaster performs a feasibility assessment each day comparing estimated cold weather related gas outages versus the total gas commitment in the DA and/or SCRA cases to evaluate the commitment of non-gas Generators for the next day operating plan.

B. When gas-fired Generators communicate with the Forecaster that they are experiencing problems with gas supply pressures or obtaining gas supply, or gas transportation services, the Forecaster relays this information to the Control Room Operations Shift Supervisor (or designee) and the Supervisor, Operations Forecast and Scheduling.

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