HomeMy WebLinkAbout2023-10-13 IMC Agenda and docs INTERTIE MANAGEMENT COMMITTEE (IMC) REGULAR MEETING UPDATED AGENDA September 29, 2023 RESCHEDULED to October 6, 2023 RESCHEDULED to October 13, 2023 9:00 AM 11:00 am Alaska Energy Authority Board Room
813 W Northern Lights Blvd, Anchorage, AK 99503
To participate dial 1-888-585-9008 and use code 212-753-619#
1. CALL TO ORDER
2. ROLL CALL FOR COMMITTEE MEMBERS
3. PUBLIC ROLL CALL
4. PUBLIC COMMENTS
5. AGENDA APPROVAL
6. APPROVAL OF PRIOR MINUTES – July 28, 2023
7. NEW BUSINESS
A. Primary Frequency Response Standard
B. Douglas Substation Control Enclosure
C. FERC Order 866 Communications Between Control Centers
8. COMMITTEE REPORTS
A. Budget to Actuals
B. IOC Committee
C. Operator’s Report
9. MEMBERS COMMENTS
10. NEXT MEETING DATE – December 8, 2023
11. ADJOURNMENT
Alaska Energy Authority
AK Intertie Budget to Actual Revenues and Expenses
07/01/2023 to 08/31/2023
Page 1 of 4
FY24 Approved
Budget
BUDGET
07/01/2023 -
08/31/2023 Actuals
YTD Actuals as a
% of Total
Annual Budget
OVER (UNDER)
YTD Variance
Revenue From Utilities
AKI-GVEA 3,631,114 657,548 842,964 23%185,416
AKI-CEA 471,717 258,940 258,940 55%-
AKI-MEA 654,520 181,544 184,981 28%3,437
Total Revenue From Utilities 4,757,352 1,098,031 1,286,885 27%188,853
Interest - - 5,424 0% 5,424
Total Revenues 4,757,352 1,098,031 1,292,309 27%194,277
Total Revenues 4,757,352 1,098,031 1,292,309 27%194,277
56600 Misc Transmission Expense
Alaska Energy Authority
AK Intertie-Cell Phone Comm. Svc. for Wx Monitorng 13,000 2,167 1,000 8%(1,166)
AK Intertie-Miscellaneous Studies as Needed 516,000 86,000 - 0%(86,000)
Alaska Energy Authority Total 529,000 88,167 1,000 0%(87,166)
Golden Valley Electric
AK Intertie-Private Line Telephone Service SCADA 6,000 1,000 - 0%(1,000)
Golden Valley Electric Total 6,000 1,000 - 0%(1,000)
56601 Weather Monitoring Batteries
Alaska Energy Authority
AK Intertie-SLMS Support & Intertie Ground Patrol 175,000 29,167 - 0%(29,167)
Alaska Energy Authority Total 175,000 29,167 - 0%(29,167)
56700 Rents
Alaska Energy Authority
AK Intertie-Alaska Railroad 1,000 167 - 0%(167)
Alaska Energy Authority Total 1,000 167 - 0%(167)
Matanuska Electric Association
AK Intertie-Talkeetna Storage 7,200 1,200 1,200 17%-
Matanuska Electric Association Total 7,200 1,200 1,200 17%-
56900 Maintenance of Structures
Matanuska Electric Association
AK Intertie-Maintenance of Structures 150,000 25,000 - 0%(25,000)
Matanuska Electric Association Total 150,000 25,000 - 0%(25,000)
57000 Maintenance of Station Equip
Chugach Electric Association
AK Intertie-Teeland Substation 175,000 29,167 - 0%(29,167)
Chugach Electric Association Total 175,000 29,167 - 0%(29,167)
Golden Valley Electric
AK Intertie-Healy, Cantwell, Goldhill 125,000 20,833 - 0%(20,833)
AK Intertie-Cantwell 4S2 Switch Repair 306,000 51,000 - 0%(51,000)
AK Intertie-Capacitor Spares 20,000 3,333 - 0%(3,333)
Golden Valley Electric Total 451,000 75,167 - 0%(75,167)
Matanuska Electric Association
AK Intertie-Douglas Substation 25,000 4,167 1,381 6%(2,785)
Matanuska Electric Association Total 25,000 4,167 1,381 6%(2,785)
57100 Maint of OH Lines
Golden Valley Electric
AK Intertie-Northern Maintenance 150,000 25,000 - 0%(25,000)
AK Intertie-Landing Pads 75,000 12,500 - 0%(12,500)
Golden Valley Electric Total 225,000 37,500 - 0%(37,500)
AK Intertie-Southern Maint. (Incl Ground Insp) 140,000 23,333 - 0% (23,333)
AK Intertie-Equipment Repair & Replacement 350,000 58,333 148,020 42%89,687
Matanuska Electric Association Total 490,000 81,667 148,020 30%66,353
ALASKA ENERGY AUTHORITY
AK INTERTIE BUDGET TO ACTUAL REVENUE AND EXPENSES
FOR THE PERIOD 07/01/2023 THROUGH 08/31/2023
Page 2 of 4
FY24 Approved
Budget
BUDGET
07/01/2023 -
08/31/2023 Actuals
YTD Actuals as a
% of Total
Annual Budget
OVER (UNDER)
YTD Variance
ALASKA ENERGY AUTHORITY
AK INTERTIE BUDGET TO ACTUAL REVENUE AND EXPENSES
FOR THE PERIOD 07/01/2023 THROUGH 08/31/2023
57101 Extra Ord Maint of OH Lines
Golden Valley Electric
AK Intertie-Re-level Structures & Adjust Guys 80,000 13,333 - 0%(13,333)
Golden Valley Electric Total 80,000 13,333 - 0%(13,333)
57102 Maint OH Lines-ROW Clearing
AK Intertie-Northern ROW Clearing 550,000 91,667 - 0%(91,667)
AK Intertie-Northern ROW Remote Sensing 400,000 66,667 - 0%(66,667)
Repair Tower 531 Foundation 150,000 25,000 - 0%(25,000)
Repair Tower 532 Foundation 150,000 25,000 - 0%(25,000)
Golden Valley Electric Total 1,250,000 208,333 - 0%(208,333)
Matanuska Electric Association
AK Intertie-Southern ROW Clearing 500,000 83,333 - 0%(83,333)
AK Intertie-Southern ROW Remote Sensing 125,000 20,833 - 0%(20,833)
Matanuska Electric Association Total 625,000 104,167 - 0%(104,167)
58306 Misc Admin
Alaska Energy Authority
AK Intertie-IMC Admin Cost (Audit, Meeting, Legal)20,000 3,333 2,101 11%(1,232)
Alaska Energy Authority Total 20,000 3,333 2,101 11%(1,232)
58401 Insurance Premiums
Alaska Energy Authority
AK Intertie-Insurance 22,200 3,700 11,339 51%7,639
Alaska Energy Authority Total 22,200 3,700 11,339 51%7,639
Matanuska Electric Association
AK Intertie-Insurance 14,800 2,467 - 0%(2,467)
Matanuska Electric Association Total 14,800 2,467 - 0%(2,467)
Total Total Expense 4,246,200 707,700 165,041 4%(542,659)
Total Operating Expenses 4,246,200 707,700 165,041 4%(542,659)
71001 Total Expense, Budget
Alaska Energy Authority
Administrative Support Services 230,000 38,333 (168) 0%(38,501)
Alaska Energy Authority Total 230,000 38,333 (168) 0%(38,501)
Total Total Expense 230,000 38,333 (168) 0%(38,501)
Total AEA Administration Expenses 230,000 38,333 (168) 0%(38,501)
Total Expenses 4,476,200 746,033 164,874 4%(581,159)
Surplus (Shortage)281,152 351,998 1,127,435 401%775,437
Page 3 of 4
Alaska Intertie FY24 Budget to Actuals Status Report for the Period 07/01/2023 through 08/31/2023
Budgeted Usage Actual Usage to Date
GVEA MEA CEA TOTAL GVEA MEA CEA TOTAL
MONTH MWH MWH MWH MWH MONTH MWH MWH MWH MWH
Jul 11,500 1,993 - 13,493 Jul 21,896 2,018 - 23,914
Aug 13,600 2,034 - 15,634 Aug 18,254 2,288 - 20,542
Sep 14,050 1,972 - 16,022 Sep - - - -
Oct 23,500 2,036 - 25,536 Oct - - - -
Nov 25,190 2,273 - 27,463 Nov - - - -
Dec 24,990 2,494 - 27,484 Dec - - - -
Jan 25,470 2,495 - 27,965 Jan - - - -
Feb 24,740 2,043 - 26,783 Feb - - - -
Mar 21,230 2,158 - 23,388 Mar - - - -
Apr 13,470 1,943 - 15,413 Apr - - - -
May 20,380 1,871 - 22,251 May - - - -
Jun 31,070 1,835 - 32,905 Jun - - - -
TOTAL 249,190 25,147 - 274,337 TOTAL 40,150 4,306 - 44,456
INTERTIE PROJECTED ENERGY USAGE TO DATE (MWH)29,127 INTERTIE ACTUAL ENERGY USAGE TO DATE (MWH) 44,456
Budgeted Operating Costs for the Period 707,700$ Actual Operating Costs for the Period 165,041$
(based on amended budget)
Budgeted Usage Revenue for the Period 149,130$ Actual (Billed) Usage Revenue for the Period 227,615$
(budgeted rate * projected usage)(budgeted rate * actual usage)
Estimated Budgeted Energy Rate per MWH 20.29$
(based on budgeted costs and usage)
Annual Budgeted Energy Rate (Billed Rate)5.12$ Projected Actual Energy Rate per MWH 3.10$
(based on minimum contract value)(based on actual costs and usage)
Page 4 of 4
Intertie Management Committee Meeting
IOC Report
September 29, 2023
1.Intertie Operating Committee
a.The IOC discussed a new draft Primary Frequency Response standard, see attached,
related to the system’s frequency response when an event occurs. The standard
addresses how much fast spin is necessary to ensure recovery from an event before the
system goes into underfrequency load shed (UFLS). It also provides an outline of how
much fast spin each unit on the Railbelt can provide and it prohibits running the system
in a manner that would allow a single unit trip to cause UFLS. The standard does not
address the loss of transmission lines, put restrictions on buying spin from others, or
how the spin is divided among LBAs. The IOC is still reviewing the standard and will
have a recommendation on how to proceed with the standard at the next IMC meeting.
b.A drat intertie wildfire mitigation plan was presented to the IOC and is attached for
reference. The IOC is reviewing the plan will provide a recommendation on the plan to
the IMC.
2.System Studies Subcommittee
a.The SSS provided an update on the sychrophaser project. Utilities continue to work with
their IT departments to determine a method for safely and securely moving data. This
effort is anticipated to run into the first quarter of 2024. Once this effort is completed,
EPG will work with the utilities to implement their software.
b.The SSS has contracted with NREL to study the impact of inverter-based resources
(IBRs). One of the first step in modeling the impact of IBRs is data collection, which is
currently underway. Finalizing NDAs with each utility has taken longer than anticipated,
which has pushed data collection into the fourth quarter. Once collection is completed
modeling will begin. Modeling of the base cases is anticipated to run through the first
quarter of 2024. Once validation of the base cases is complete, modeling of the system
with IBRs will be done. Final modeling and a report on the results will be completed by
late in the second quarter of 2024 or the third quarter.
c.The SSS is developing a scope of work to study system impacts if the Alaska Intertie is
upgraded to 230 kV. System stability, transfer capability, and reserve requirements are
some of the major items that will be included in the study. Once the scope is approved
by the IOC selection of a contactor to perform the study will begin. A contractor is not
anticipated to begin work until the first quarter of 2024.
3.SCADA & telecommunications Subcommittee
a.The subcommittee continues to move forward with construction of upgraded
communications between Anchorage and Douglas using AEA provided funds. In
addition, the committee is looking at developing a scope for upgraded communications
between Douglas and Healy which could potentially use AEA funds for some or all of the
installation.
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Page 1 of 14
Alaska Railbelt Standard – Primary Frequency Response
A. Introduction
1.Title: Primary Frequency Response
2.Number: TBA
3.Purpose:
3.1.This standard defines a process to maintain interconnection frequency
within defined limits during the arrest period.
4.Applicability:
4.1.Balancing Authorities
4.2.Generator Owners
4.3.Generator Operators
4.4.Obligated Entity
4.5.Reliability Coordinator
5.Effective Date: 12 months from adoption by the Reliability Organization.
B. Requirements
R1. The Balancing Authority shall identify Reportable Disturbances and within 14
days of the Disturbance, shall notify the Compliance Monitor and make the
following information available to all Obligated Entities: time of Disturbance, pre-
disturbance frequency, and frequency minimum/ maximum.
R2. The Balancing Authority shall calculate the Primary Frequency Response of each
generating unit/ generating facility in accordance with this standard and Section
2 of the Primary Frequency Response Reference document. This calculation shall
provide a 12-month rolling average of Primary Frequency Response performance.
Unit performance shall be measured through Digital Fault Recorders (DFR)
recordings during Reportable Disturbances as described in the Section 2 of the
Reference Document. This calculation shall be completed each month for the
preceding 12 calendar months.
2.1. The calculation results shall be submitted to the Compliance Monitor and
made available to the Generator Owner by the end of the month in which
they were completed.
2.2. If a generating unit/generating facility has not participated in a minimum
of (8) eight Reportable Disturbances in a 12-month period, its
performance shall be based on a rolling eight average response.
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2.3. If a generating unit/ generating facility has not participated in any
Reportable Disturbances, Primary Frequency Response performance may
be determined from unit load rejection test data.
R3: The Balancing Authority may set their Battery Energy Storage Systems to supply
Primary Frequency Response reserves up to the asset’s full rating as described in
Section 3 of the Reference Document. Energy Storage Systems shall be
considered a generating unit in this standard.
R4: A Balancing Authority may use SILOS for Primary Frequency Response. Frequency
set points and delay times must be set as described in Section 4 of the Reference
Document.
R5. The Reliability Coordinator shall determine the Interconnection Minimum
Frequency Response (IMFR) hourly as the maximum rating of the Largest Single
Generating Contingency committed for the day per Hertz. The IMFR, the
methodology for calculation and the criteria for determination of the IMFR shall
be made available to the Obligated Entities as described in Section 5 of the
Reference Document.
5.1. If an unscheduled unit, that has a larger maximum rating than the LSGC, is
started during the day and ran for more than two hours at its maximum,
the IMFR will be recalculated to reflect the new Largest Single Generating
Contingency. The Balancing Authority shall notify the other Railbelt
Balancing Authorities of this change as soon as practicable but within 30
minutes of the unit’s start.
R6. After each calendar month in which one or more Reportable Disturbances occur,
the Reliability Coordinator shall determine and make available to the Obligated
Entities the Interconnection’s combined Primary Frequency Response
performance for a rolling average of the last (6) six Reportable Disturbances by
the end of the following calendar month.
R7. Following any Reportable Disturbance that causes the Interconnection’s six
rolling average Primary Frequency Response Performance to be less than the
average IMFR from the last six Reportable Disturbances, the Reliability
Coordinator shall direct any necessary actions to improve Primary Frequency
Response, which may include but are not limited to the following: directing
adjustment of Governor deadband and/or droop settings.
R8. Each Generator Owner shall operate each generating unit/ generating facility
that is connected to the Railbelt with the Governor in service and responsive to
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Page 3 of 14
frequency when the generating unit/generating facility is online and released for
dispatch, unless the Generator Owner has a valid reason for operating with the
Governor not in service and the Generator Operator has been notified that the
Governor is not in service.
R9. A Balancing Authority shall notify the other Railbelt Balancing Authorities and
the Reliability Coordinator as soon as practical but within 30 minutes of the
discovery of a status change (in service, out of service) of a Governor and steps
taken by the Balancing Authority to maintain their Primary Frequency Response
Obligation.
R10. Each Generator owner shall meet a minimum 12-month rolling average Primary
Frequency Response performance of 0.75 on each generating unit/generating
facility, based on participation in at least eight Reportable Disturbances as
described in Section 6 of the Reference Document.
10.1 The Primary Frequency Response performance shall be the ratio of the
Actual Primary Frequency Response to the Expected Primary Frequency
Response during the initial measurement period following the
Disturbance.
10.2 If a generating unit/ generating facility has not participated in a minimum
of eight Reportable Disturbances in a 12-month period, performance shall
be based on a rolling eight average.
10.3. If a generating unit/ generating facility has not participated in any
Reportable Disturbances, Primary Frequency Response performance may
be determined from unit load rejection test data.
10.4. A generating unit/generating facility’s Primary Frequency Response
performance during a Reportable Disturbance may be excluded from the
rolling average calculation by the Balancing Authority due to a legitimate
operating condition that prevented normal Primary Frequency Response
performance. Examples of legitimate operating conditions that may
support exclusion of a generating unit from Reportable Disturbances
include, but are not limited to:
Operation at or near auxiliary equipment operating limits (such as
boiler feed pumps, condensate pumps, pulverizes, and forced
draft fans.
Data telemetry failure. The Balancing Authority may request raw
data from the Generator Owner as a substitute.
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R11. Primary Frequency Response reserves must be dispatched such that a single unit
trip does not cause Underfrequency Load Shed to occur as described in Section 7
of the Reference Document.
C. Measures
M1. The Balancing Authority shall have evidence it reported each Reportable
Disturbance to the Compliance Monitor and that it made the information
available to the Obligated Entities within 14 calendar days after the Disturbance
as required in Requirement R1.
M2. The Balancing Authority shall have evidence it calculated and reported the rolling
average Primary Frequency Response performance of each generating unit/
generating facility monthly as required in Requirement 2.
M3. The Balancing Authority shall provide documentation on how Battery Energy
Storage systems are set to respond to Reportable Disturbances.
M4. Balancing Authorities using SILOS for Primary Frequency Response shall report
how SILOS are programed with their delay times and frequency set points.
M5. The Reliability Coordinator shall provide evidence that the IMFR was determined
hourly as required in Requirement 5. The Reliability Coordinator shall provide
evidence that the IMFR, the methodology for calculation and the criteria for
determining the IMFR are available to Obligated Entities. If there are any changes
impacting the IMFR, the Balancing Authority shall provide evidence that they
notified the other Railbelt Balancing Authorities.
M6. The Reliability Coordinator shall provide evidence that the rolling average of the
Interconnection’s combined Primary Frequency Response Performance for the
last (6) six Reportable Disturbances was calculated and made available to the
Obligated Entities as required in Requirement 6.
M7. The Balancing Authority shall provide evidence that actions were taken to
improve the Interconnection’s Frequency Response if the Interconnection’s six-
Reportable Disturbance rolling average combined Frequency Response
performance was less than the IMFR, as required by Requirement R7. The
Balancing Authority shall be required to increase their Primary Frequency
Response allocation for the calendar quarter.
M8. Each Generator Owner shall have evidence that it notified the Generator
Operator as soon as practical each time it discovered a Governor not in service
when the generating unit/ generating facility was online and released for
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Page 5 of 14
dispatch. Evidence may include but not limited to operator logs, voice logs, or
electronic communications.
M9. The Balancing Authority shall have evidence that they notified the other Railbelt
Balancing Authorities within 30 minutes of each discovery of a status change (in
service, out of service) of a governor. They shall also have evidence of steps taken
to maintain their Primary Frequency Response Obligation.
M10. Each Generator Owner shall have evidence that each of its generating
units/generating facilities achieved a minimum rolling average of Primary
Frequency Response performance level of at least 0.75 as described in
Requirement R9. Each Generator Owner shall have documented evidence of any
Reportable Disturbances where the generating unit performance was excluded
from the rolling average calculation.
M11. The Balancing Authority shall have evidence that a single unit trip did not cause
Underfrequency Load Shed to occur.
D. Definitions
Term Acronym Definition
Interconnection
Minimum Frequency
Response
IMFR The interconnections Minimum Primary Frequency Response
obligation measured in MW/0.1 Hz. determined by the Largest
Single Generation Contingency per 0.1 Hz.
Largest Single
Generation Continency
LSGC The declared capability of the largest generating unit contingency
interconnected to the Railbelt minus the effects of HRSGs at
combined cycle plants.
Primary Frequency
Response
PFR Response capability of a generating unit during the frequency
arresting period of a Reportable Disturbance.
Reportable
Disturbance
Reportable Disturbances are contingencies involving any
generating unit trips, transmission line trips, and distribution level
disturbances that result in frequency deviation > 0.2 Hz.
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Attachment 1
Primary Frequency Response Reference Document
1. Introduction
This document provides the methodology for calculating the Primary Frequency Response (PFR)
and performance of generating units/generating facilities. EPS conducted three studies:
Benchmarking Report V0 which was a PSSE model validation report, Railbelt Contingency
Reserves Analysis V2 which was primary report of study, and BESS Analysis Report V2 which was
a follow up analysis of BESS performance. The second report, Railbelt Contingency Reserves
Analysis V2 proposed 2 methods to dispatch Contingency Reserve, or Spin. One method was the
Primary Frequency Response Method, PFR, which will be discussed in this document.
2. Primary Frequency Response Calculations using Digital Fault Recorders
Requirement 2
R2. The Balancing Authority shall calculate the Primary Frequency Response of each
generating unit/ generating facility in accordance with this standard and the
Primary Frequency Response Reference document. This calculation shall provide
a 12-month rolling average of Primary Frequency Response performance. Unit
performance shall be measured through Digital Fault Recorders (DFR) recordings
during Reportable Disturbances as described in the Section 2 of the Reference
Document. This calculation shall be completed each month for the preceding 12
calendar months.
2.1. The calculation results shall be submitted to the Compliance Monitor and
made available to the Generator Owner by the end of the month in which
they were completed.
2.2. If a generating unit/generating facility has not participated in a minimum
of (8) eight Reportable Disturbances in a 12-month period, its
performance shall be based on a rolling eight average response.
2.3. If generating unit/ generating facility has not participated in any
Reportable Disturbances, Primary Frequency Response performance may
be determined from unit load rejection test data.
To determine the performance of each generating unit/ generating facility to provide Primary
Frequency Response during a Reportable Disturbance, Disturbance Fault Recorder, DFR,
recordings are used. This calculation shall provide a 12-month rolling average of the primary
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frequency performance. The PFR of a unit during a Reportable Disturbance using DFR recordings
is measured using the following formula:
= ( _ − )∗60.0 −58.2 60.0 − _
Where _ is the unit’s output when unit frequency reaches its minimum. is the unit’s output before the Disturbance occurs. is the primary frequency response of the unit during a Reportable Disturbance. _ is when the when the unit’s frequency reaches its minimum value.
3. Battery Energy Storage Systems (BESS)
Requirement 3
R3: The Balancing Authority may set their Battery Energy Storage Systems to supply
Primary Frequency Response reserves up to the asset’s full rating as described in
Section 3 of the Reference Document. Energy Storage Systems shall be
considered a generating unit in this standard.
A BESS may be used for Primary Frequency Response up to its rating. If limits are placed on a
BESS, the Primary Frequency Response of that BESS is only assigned to that limit.
4. Shed In Lieu of Spin (SILOS)
Requirement 4
R4: Each Balancing Authority may use SILOS for Primary Frequency Response.
Frequency set points and delay times must be set as described in Section 4 of the
Reference Document.
SILOS settings at the time of the EPS Study did not trigger before Stage 1 Underfrequency Load
Shed due to long delay times. The following table shows five sets of alternate SILOS settings
with shorter delay times. All were found to replace reserves on a MW-to-MW basis without
entering Stage 1 UFLS. Each Balancing Authority may choose whichever set it finds most
appropriate. The percentages represent the percent of SILOS reserves armed at each frequency
setpoint. Delay times are the detection and relay time, and not the breaker operating time. Each
Balancing Authority shall report how SILOS are programed with their delay times and frequency
set points.
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Set -> 1 2 3 4 5
59.7 Hz 25% 25% 50% 25% 33%
59.4 Hz 25% 50% 50% 75% 33%
59.2 Hz 50% 25% 34%
Delay time (cycles) 3 3 or 6 3 or 6 3 or 6 3 or 6
5. Interconnection Minimum Frequency Response (IMFR)
Requirement 5
R5. The Reliability Coordinator shall determine the Interconnection Minimum
Frequency Response (IMFR) hourly as the maximum rating of the Largest Single
Generating Contingency committed for the day per Hertz. The IMFR, the
methodology for calculation and the criteria for determination of the IMFR shall
be made available to the Obligated Entities as described in Section 5 of the
Reference Document.
5.1. If an unscheduled unit, that has a larger maximum rating than the LSGC, is
started during the day and ran for more than two hours at its maximum,
the IMFR will be recalculated to reflect the new Largest Single Generating
Contingency. The Balancing Authority shall notify the other Railbelt
Balancing Authorities of this change as soon as practicable but within 30
minutes of the unit’s start.
This section of the PFR Reference Document establishes the process to calculate the
Interconnection’s Minimum Frequency Response, IMFR. This methodology defines the LSGC,
Largest Single Generation Contingency, as the declared capability of the largest generating unit
contingency connected to the Railbelt. The HRSG would not be included in the calculation of the
LSGC due to the negligible ramp down of the HRSG during the arresting period
The Interconnection Minimum Frequency Response is calculated as the Railbelt’s Primary
Frequency Response Obligation per Hertz. The Primary Frequency Response Obligation for the
Railbelt is the amount of required PFR that must be available to prevent Underfrequency Load
Shed. For example, if the largest rated unit on the Railbelt at a given hour is 60 MW, the
Primary Frequency Response Obligation is 60 MW and the IMFR is 60 MW/ 1 Hz or 6.0 MW/0.1.
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6. Primary Frequency Response Performance Calculation
Requirement 10
R10. Each Generator owner shall meet a minimum 12-month rolling average Primary
Frequency Response performance of 0.75 on each generating unit/generating
facility, based on participation in at least eight Reportable Disturbances as
described in Section 6 of the Reference Document.
10.1 The Primary Frequency Response performance shall be the ratio of the
Actual Primary Frequency Response to the Expected Primary Frequency
Response during the initial measurement period following the
Disturbance.
10.2 If a generating unit/ generating facility has not participated in a minimum
of eight Reportable Disturbances in a 12-month period, performance shall
be based on a rolling eight average.
10.3. If a generating unit/ generating facility has not participated in any
Reportable Disturbances, Primary Frequency Response performance may
be determined from unit load rejection test data.
10.4. A generating unit/generating facility’s Primary Frequency Response
performance during a Reportable Disturbance may be excluded from the
rolling average calculation by the Balancing Authority due to a legitimate
operating condition that prevented normal Primary Frequency Response
performance. Examples of legitimate operating conditions that may
support exclusion of a generating unit from Reportable Disturbances
include, but are not limited to:
Operation at or near auxiliary equipment operating limits (such as
boiler feed pumps, condensate pumps, pulverizes, and forced
draft fans.
Data telemetry failure. The Balancing Authority may request raw
data from the Generator Owner as a substitute.
This section describes how to calculate the average Primary Frequency Response for each
generating unit/ generating facility over a 12 month period with a minimum of (8) Reportable
Disturbances. If a generating unit/ generating facility has not participated in a minimum of eight
Reportable Disturbances in a 12 month period, performance shall be based on a rolling eight
average. If a unit has not participated in at least 8 Reportable Disturbances historically, then
data from unit load rejection tests will be used. The unit load rejection test will be considered a
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Page 10 of 14
Reportable Disturbance so it can be included in the performance calculation. This is to establish
whether the unit is in compliance with its PFR obligation. The P.U. PFR is the per unit measure of
the Primary Frequency Response of a unit during Reportable Disturbances. The average of the
unit’s PFR during a 12 month period must be greater than or equal to 0.75. =[ . . ]≥0.75
Where . . =
Headroom must be greater than the unit’s expected Primary Frequency Response. If not, this
unit during this event will not be included in the performance calculation. The unit would be
considered operating at full capacity, so its response is not included to calculate the average
performance. If a unit has not run for more than a defined number of hours and there is no
available data from unit load rejection tests, Primary Frequency Response for the unit shall be
assigned 0 MW.
7. Primary Frequency Response Dispatch
Requirement 11
R11. Primary Frequency Response reserves must be dispatched such that a single unit
trip does not cause Underfrequency Load Shed to occur as described in Section 7
of the Reference Document.
The PFR method focuses on the turbine/governor response of each unit and assigns the
available arrest period reserves for each unit. The units that increase their output more rapidly
than other units, contribute more to arresting frequency and UFLS prevention than units with a
slower response. Reserves are allocated on a MW basis for each unit. Each unit has an “upper
limit” which is defined as the PFR of the unit. For example, if a unit has 20 MW of headroom,
but its upper limit is 8 MW, then only 8 MW of Primary Frequency Response can be allocated to
the unit.
The PFR method assigns a single reserve value for each unit in MW, but limits how many
reserves each unit can be allocated based on the response of the unit during the arrest period.
Tables 10, 11, and 12 of the EPS Contingency Reserves Study summarizes the simulated PFR
values for each individual unit which are referenced in Appendix A of this document. This value
is the maximum allowable reserve that can be allocated to a unit under the assumption that the
unit has adequate headroom. If the headroom of a unit is less than the PFR of that unit, the
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response of the unit is equal to the available headroom. When dispatching units, the sum of the
available response of each online unit must be equal to or greater than the LGSC, as defined in
this document. As required in Requirement 11, Primary Frequency Response reserves shall be
dispatched such that a single unit trip does not cause an Underfrequency Load Shed event to
occur.
If a Balancing Authority is purchasing spin as a source of Primary Frequency Response, they
must state that the spin they are purchasing must be PFR. The Balancing Authority selling spin
must then provide evidence that the spin they are selling is Primary Frequency Response.
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Appendix A – Unit Primary Frequency Response
Table 1: Primary Frequency Response – Kenai
Unit
Primary Frequency Response
(MW)
Soldotna CT 7.8
Bradley Lake 1 0.0
Bradley Lake 2 0.0
Tesoro 1 0.0
Tesoro 2 0.0
Bernice 2 7.4
Bernice 3 9.3
Bernice 4 6.3
Nikiski CT* 0.0
Nikiski ST* 0.0
Cooper Lake 1* 0.4
Cooper Lake 2* 0.4
Units marked with an (*) asterisk were benchmarked with field recordings.
Shaded rows have no PFR assigned to that unit
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Table 2: Primary Frequency Response – Anchorage
Unit
Primary Frequency Response
(MW)
Nikkels 3 5.7
Sullivan 7 13.3
Sullivan 8 26.0
Sullivan 9* 2.7
Sullivan 10* 2.7
Sullivan 11 (HRSG)* 0.0
Beluga 3 13.5
Beluga 5 15.6
Beluga 6 3.5
Beluga 7 3.5
SPP 11* 3.6
SPP 12* 4.2
SPP 13* 3.6
SPP 10 (HRSG)* 0.0
Eklutna Hydro 1* 1.3
Eklutna Hydro 2* 1.3
EGS 1* 1.7
EGS 2* 1.7
EGS 3* 1.7
EGS 4* 1.7
EGS 5* 1.7
EGS 6* 1.7
EGS 7* 1.7
EGS 8* 1.7
EGS 9* 1.7
EGS 10* 1.7
Units marked with an (*) asterisk were benchmarked with field recordings.
Shaded rows have no PFR assigned to that unit
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Table 3: Primary Frequency Response – Fairbanks
Unit
Primary Frequency Response
(MW)
Wilson BESS* 5.0
Healy 2* 0.0
Healy 1 3.2
UAF (new unit) 1.1
Zehnder 1 5.5
Zehnder 2 5.5
Chena 5 0.0
Chena 1 0.0
Chena 2 0.0
Chena 3 0.0
North Pole 1 4.4
North Pole 2 4.6
North Pole CC 3* 4.9
North Pole CC 4
(HRSG)* 0.0
Units marked with an (*) asterisk were benchmarked with field recordings.
Shaded rows have no PFR assigned to that unit
Intertie Wildfire Mitigation Plan Scope
Plan Service Area- figures and GIS data
Goals and Objectives- coverage of plan and site specific use
Operational Practices
o Vegetation Management- add helicopter pad maintenance, update veg clearing cycle
length based on NV5 Lidar and vegetation sampling
o Vegetation conversion/fuels reduction
o Species compatibility
o Bare mineral soil break potential
o Grubbing and mulching fire resistance
o Shaded fuel breaks
o Substation vegetation clearing buffers
o Minimum Vegetation Clearance Distances
o De-energization protocols and notifications
o Re-energization protocols and notifications
Risk Analysis-
o Four categories for powerline sparks and ignition
Contact from objects
Equipment/facility failure
Wire to wire contact/contamination
Other
o Site Specific Threat Assessment- wildfire likelihood and fire intensity, spatial fuels and
vegetation data, and point locations of historic fire occurrence
Based on communities, vegetation types, topography, accessibility, fire history,
tree mortality/ tree failure, lightning, fire weather.
Fire behavior modeling
Determine transmission and distribution line and other infrastructure
that would be vulnerable to high wildfire threat.
Interagency Fuel Treatment Decision Support System (IFTDSS) platform
used to run all fire behavior modeling.
Fire hazard and risk layers used in the analysis will include:
o Fire Behavior Fuel Models
o Flame lengths
o Rates of Spread
o Crown Fire Potential
o Fireline Intensity
o Burn Probability
o Integrated Hazard
o Suppression Difficulty Index
GIS experts will use these datasets to create detailed maps of high-risk line
segments and other infrastructure.
Incorporate information and technical expertise such that the fire behavior
layers are calibrated to conditions observed on the ground.
Identify areas with heightened fire risk in detailed appendices with
recommended cost-effective mitigation measures
Recommends measures and programs for future use and consideration
Include recommendations for data collection and management for improved
situational awareness
Describe and propose protocols for de-energizing lines and disabling reclosers
o Key Risk Impacts- personal injuries/fatalities, damage to public and/or private property,
damage and loss of infrastructures and assets, impacts to reliability and operations,
damage claims and litigation, damage to reputation and loss of public confidence.
o Real-time risk assessment- USFS-Wildland Fire Assessment System
Emergency Preparedness and Response
o Communications plan
Contact List
Local governments
DNR Forestry
Landowner communication protocols during fire events
Describe protocols for coordination with fire response personnel and incident
management teams
o Emergency Response Plan (GIS Based with figures and downloadable GPS data)
Site specific access
Helicopter Landing Pads
Landowner Vegetation Grants
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