HomeMy WebLinkAbout2024-01-26 IMC Agenda and docs INTERTIE MANAGEMENT COMMITTEE (IMC) REGULAR MEETING January 26, 2024 9:00 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 – December 8, 2023
7. NEW BUSINESS
A. GRID Resilience Formula Grant Program Application
8. OLD BUSINESS
9. COMMITTEE REPORTS
A. Budget to Actuals
B. IOC Committee
i. Primary Frequency Response Standard update
ii. FERC Order 866 Communications Between Control Centers update
iii. NREL Study – Inverter based resources
C. Operator’s Report
10. MEMBERS COMMENTS
11. NEXT MEETING DATE – March 22, 2024
12. ADJOURNMENT
Alaska Energy Authority
AK Intertie Budget to Actual Revenues and Expenses
07/01/2023 to 12/31/2023
Page 1 of 4
FY24 Approved
Budget
BUDGET
07/01/2023 -
12/31/2023 Actuals
YTD Actuals as a
% of Total
Annual Budget
OVER (UNDER)
YTD Variance
Revenue From Utilities
AKI-GVEA 3,631,114 1,823,492 2,602,609 72%779,117
AKI-CEA 471,717 344,051 344,051 73%-
AKI-MEA 654,520 374,763 380,159 58%5,396
Total Revenue From Utilities 4,757,352 2,542,306 3,326,819 70%784,513
Interest - - 27,320 0%27,320
Total Revenues 4,757,352 2,542,306 3,354,139 71%811,833
Total Revenues 4,757,352 2,542,306 3,354,139 71%811,833
56600 Misc Transmission Expense
Alaska Energy Authority
AK Intertie-Cell Phone Comm. Svc. for Wx Monitorng 13,000 6,500 5,005 38%(1,495)
AK Intertie-Miscellaneous Studies as Needed 516,000 258,000 28,200 5%(229,800)
Alaska Energy Authority Total 529,000 264,500 33,205 6%(231,295)
Golden Valley Electric
AK Intertie-Private Line Telephone Service SCADA 6,000 3,000 - 0%(3,000)
Golden Valley Electric Total 6,000 3,000 - 0%(3,000)
56601 Weather Monitoring Batteries
Alaska Energy Authority
AK Intertie-SLMS Support & Intertie Ground Patrol 175,000 87,500 21,205 12%(66,295)
Alaska Energy Authority Total 175,000 87,500 21,205 12%(66,295)
56700 Rents
Alaska Energy Authority
AK Intertie-Alaska Railroad 1,000 500 1,000 100%500
Alaska Energy Authority Total 1,000 500 1,000 100%500
Matanuska Electric Association
AK Intertie-Talkeetna Storage 7,200 3,600 3,000 42%(600)
Matanuska Electric Association Total 7,200 3,600 3,000 42%(600)
56900 Maintenance of Structures
Matanuska Electric Association
AK Intertie-Maintenance of Structures 150,000 75,000 - 0%(75,000)
Matanuska Electric Association Total 150,000 75,000 - 0%(75,000)
57000 Maintenance of Station Equip
Chugach Electric Association
AK Intertie-Teeland Substation 175,000 87,500 82,488 47%(5,012)
AK Intertie-Douglas Substation Communications - - 1,554 0%1,554
Chugach Electric Association Total 175,000 87,500 84,041 48%(3,459)
Golden Valley Electric
AK Intertie-Healy, Cantwell, Goldhill 125,000 62,500 - 0%(62,500)
AK Intertie-Cantwell 4S2 Switch Repair 306,000 153,000 - 0%(153,000)
AK Intertie-Capacitor Spares 20,000 10,000 - 0%(10,000)
Golden Valley Electric Total 451,000 225,500 - 0%(225,500)
Matanuska Electric Association
AK Intertie-Douglas Substation 25,000 12,500 1,441 6%(11,059)
Matanuska Electric Association Total 25,000 12,500 1,441 6%(11,059)
57100 Maint of OH Lines
Golden Valley Electric
AK Intertie-Northern Maintenance 150,000 75,000 - 0%(75,000)
AK Intertie-Landing Pads 75,000 37,500 - 0%(37,500)
Golden Valley Electric Total 225,000 112,500 - 0%(112,500)
AK Intertie-Southern Maint. (Incl Ground Insp) 140,000 70,000 - 0%(70,000)
AK Intertie-Equipment Repair & Replacement 350,000 175,000 156,090 45%(18,910)
ALASKA ENERGY AUTHORITY
AK INTERTIE BUDGET TO ACTUAL REVENUE AND EXPENSES
FOR THE PERIOD 07/01/2023 THROUGH 12/31/2023
Page 2 of 4
FY24 Approved
Budget
BUDGET
07/01/2023 -
12/31/2023 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 12/31/2023
Matanuska Electric Association Total 490,000 245,000 156,090 32%(88,910)
57101 Extra Ord Maint of OH Lines
Golden Valley Electric
AK Intertie-Re-level Structures & Adjust Guys 80,000 40,000 - 0%(40,000)
Golden Valley Electric Total 80,000 40,000 - 0%(40,000)
57102 Maint OH Lines-ROW Clearing
AK Intertie-Northern ROW Clearing 550,000 275,000 - 0%(275,000)
AK Intertie-Northern ROW Remote Sensing 400,000 200,000 - 0%(200,000)
Repair Tower 531 Foundation 150,000 75,000 - 0%(75,000)
Repair Tower 532 Foundation 150,000 75,000 - 0%(75,000)
Golden Valley Electric Total 1,250,000 625,000 - 0%(625,000)
Matanuska Electric Association
AK Intertie-Southern ROW Clearing 500,000 250,000 - 0%(250,000)
AK Intertie-Southern ROW Remote Sensing 125,000 62,500 132,165 106%69,665
Matanuska Electric Association Total 625,000 312,500 132,165 21%(180,335)
58306 Misc Admin
Alaska Energy Authority
AK Intertie-IMC Admin Cost (Audit, Meeting, Legal) 20,000 10,000 2,861 14%(7,139)
Alaska Energy Authority Total 20,000 10,000 2,861 14%(7,139)
58401 Insurance Premiums
Alaska Energy Authority
AK Intertie-Insurance 22,200 11,100 11,334 51%234
Alaska Energy Authority Total 22,200 11,100 11,334 51%234
Matanuska Electric Association
AK Intertie-Insurance 14,800 7,400 - 0%(7,400)
Matanuska Electric Association Total 14,800 7,400 - 0%(7,400)
Total Total Expense 4,246,200 2,123,100 446,341 11%(1,676,759)
Total Operating Expenses 4,246,200 2,123,100 446,341 11%(1,676,759)
71001 Total Expense, Budget
Alaska Energy Authority
Administrative Support Services 230,000 115,000 58,063 25%(56,937)
Alaska Energy Authority Total 230,000 115,000 58,063 25%(56,937)
Total Total Expense 230,000 115,000 58,063 25%(56,937)
Total AEA Administration Expenses 230,000 115,000 58,063 25%(56,937)
Total Expenses 4,476,200 2,238,100 504,405 11%(1,733,695)
Surplus (Shortage)281,152 304,206 2,849,734 1014%2,545,528
Page 3 of 4
Alaska Intertie FY24 Budget to Actuals Status Report for the Period 07/01/2023 through 12/31/2023
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 19,556 2,225 - 21,781
Oct 23,500 2,036 - 25,536 Oct 28,980 2,109 - 31,089
Nov 25,190 2,273 - 27,463 Nov 40,892 2,139 - 43,031
Dec 24,990 2,494 - 27,484 Dec 46,492 2,461 - 48,953
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 176,070 13,240 - 189,310
INTERTIE PROJECTED ENERGY USAGE TO DATE (MWH)125,632 INTERTIE ACTUAL ENERGY USAGE TO DATE (MWH) 189,310
Budgeted Operating Costs for the Period 2,123,100$ Actual Operating Costs for the Period 446,341$
(based on amended budget)
Budgeted Usage Revenue for the Period 1,547,786$ Actual (Billed) Usage Revenue for the Period 2,332,299$
(budgeted rate * projected usage)(budgeted rate * actual usage)
Estimated Budgeted Energy Rate per MWH 14.11$
(based on budgeted costs and usage)
Annual Budgeted Energy Rate (Billed Rate)12.32$ Projected Actual Energy Rate per MWH 1.97$
(based on minimum contract value)(based on actual costs and usage)
Page 4 of 4
Intertie Management Committee Meeting
IOC Report
January 26, 2024
1. Intertie Operating Committee
a. The IOC reviewed and commented on the attached draft Primary Frequency Response
Policy. Overall, the discussion and comments on the policy were productive. Comments
received at the IOC will be incorporated and an updated policy should be ready for the
IMC’s review and approval in March. A significant item that gained traction in the IOC
meeting was using non-coincidental peak loads to allocated Contingency Reserves. No
agreement was reached on allocation, but it is anticipated that the IOC will have a
recommendation to the IMC on allocation in March.
b. AEA has received $22.1M in funds from the DOE under the Infrastructure Investment
and Jobs Act (IIJA) and the IOC, through GVEA as the project manager, would like to put
in two grant applications. The first application would be to address snow loading issues
on the Alaska Intertie. Each year the IMC budget includes $200k-$300k in general
“maintenance” for the line of which the majority is to handle patrols and snow
unloading outages. These costs could be significantly reduced through this grant. Snow
loading outages would be reduced through replacing the 345 kV insulators with 230 kV
insulators in a unique “V” configuration to minimize unbalanced snow unloading.
Specifics on the insulator replacements are found in the attached documentation.
Assuming around 700 structures have insulators replaced, an order of magnitude
estimate for the replacement totals $10M, which would require a 30% match by the
IMC. The second application would be to fund the synchrophasor project. The total
cost to completely build out the sychrophasor project and associated communication is
estimated at $2M, of which a 30% match would be needed by the IMC. The IOC is
formally requesting the IMC to approve matching grant funds in the 2025 budget in an
amount not to exceed $4M so both grant applications can be submitted.
2. System Studies Subcommittee
a. The SSS provided an update on the sychrophaser project. GVEA and CEA have set up
the necessary infrastructure to collect sychrophaser data, MEA has begun to set up the
infrastructure, and HEA’s status was not known. Once the infrastructure is in place, 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). However scoping issues, delayed NDA approvals, and NREL personnel issues
have delayed the project. A meeting has been set up to discuss these concerns with
NREL. Until these concerns are addressed the project will not be moving forward.
c. The SSS is moving forward with an impact study for the Northern Intertie. The study will
look at the impacts of upgrading the line to 230 kV. Specifically, PSSE scenarios will be
run to determine the maximum transfer capability and impacts to the system under N-1
contingencies.
Attachment 1 – Draft Primary Frequency Response Policy
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Alaska Railbelt Standard – Primary Frequency Response Policy
A. Introducfion
1.Title: Primary Frequency Response Policy
2.Number: TBA
3.Purpose:
3.1.This standard policy defines a process to maintain interconnecfion
frequency within defined limits during the arrest period.
4.Applicability:
4.1.Balancing Authorifies
4.2.Generator Owners
4.3.Generator Operators
4.4.Obligated Enfity
4.5.Reliability Coordinator
5.Effecfive Date: 12 months from adopfion by the Reliability Organizafion.
B. Requirements
R1. The Confingency Reserve, which for this document shall be interchangeable with
Primary Frequency Response (PFR), requirement for the Railbelt shall not be less
than an amount equivalent to 100 percent of the Largest Single Generafing
Confingency. The Confingency Reserve requirement is allocated among the
Balancing Authorifies by the load rafio share based ofon a 3-year average of each
ufility’s non-coincidental peak load or by the load rafio share of a 3-year average
of the annual MWh. (Support document Spin Allocafion Methodology aftached)
R21. The Balancing Authority shall idenfify Reportable Disturbances and within 14
days of the Disturbance, shall nofify the Compliance Monitor and make the
following informafion available to all Obligated Enfifies: fime of Disturbance, pre-
disturbance frequency, and frequency minimum/ maximum, magnitude of
disturbance, and cause of the disturbance.
R32. The Balancing Authority shall calculate the Primary Frequency Response of each
generafing unit in accordance with this standard and Secfion 2 of the Primary
Frequency Response Reference document. This calculafion shall provide a 12-
month average of Primary Frequency Response performance. Unit performance
shall be measured through Digital Fault Recorders (DFR) recordings or
Synchrophasor data during the arrest period of Reportable Disturbances. This
calculafion shall be completed annually, per the Reliability Coordinator’s assigned
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date, to update each generafing unit ’s Expected Primary Frequency Response
values in Tables 1, 2, and 3 of Appendix A in the Reference Document.The
Balancing Authority shall calculate the Primary Frequency Response of each
generafing unit/ generafing facility in accordance with this standard and Secfion
2 of the Primary Frequency Response Reference document. This calculafion 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 Secfion 2 of the
Reference Document. This calculafion shall be completed each month for the
preceding 12 calendar months.
32.1.The calculafion results shall be submifted to the Compliance Monitor and
made available to the Generator OwnerBalancing Authority by the end of
the month in which they were completed. within two weeks of a date
determined by the Reliability Coordinator.
32.2.If a generafing unit/generafing facility has not parficipated in a minimum
of (8) eight Reportable Disturbances in a 12-month period, its
performance shall be based on a rolling eight average response.
32.3. If a generafing unit/ generafing facility has not parficipated in any
Reportable Disturbances, Primary Frequency Response performance may
be determined from unit load rejecfion test data from a system
disturbance that caused frequency to deviate more than 0.32 Hz. If there
is no data available for the generafing unit, its Expected Primary
Frequency Response shall be set to 0 MW.
R43.: The Balancing Authority may set their Baftery Energy Storage Systems to supply
Primary Frequency Response reserves up to the asset’s full rafing. as described
in Secfion 3 of the Reference Document. The following parameters must be
provided to the Reliability Coordinator: droop, ramp rates, and limits. Parameters
provided must be defined by a Coordinafion Study. Energy Storage Systems shall
be considered a generafing unit in this standard. Performance of the Energy
Storage System shall be tracked as if it’s a generafing unit.
R54.: A Balancing Authority may use SILOS for Primary Frequency Response. Frequency
set points and delay fimes must be set as described in Secfion 34 of the
Reference Document. The performance of the SILOS shall be tracked when used
for Primary Frequency Response.
R65. The Reliability Coordinator shall determine the Interconnecfion Minimum
Frequency Response (IMFR)Primary Frequency Response Obligafion hourly,
Commented [RF1]: To be completed each year, per the RC
direcfion
Commented [MAH2]: Why is this not 0.2 Hz??
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8/1811/21/2023 V1 Rev 1 Draft
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updated in real fime as necessary, as the maximum thermal rafing of the
Railbelt’s Largest SingleSingle Instantaneous Generafing Confingency, LSIGC.
commifted for the day per Hertz.The IMFR, the methodology for calculafion and
the criteria for determinafion of the IMFR shall be made available to the
Obligated Enfifies as described in Secfion 5 of the Reference Document.
6.1. If an unscheduled unit is started,that haswith a larger maximum thermal
rafing and output is larger than the previous LSGCLSIGC which causes the
PFR Obligafion to change, 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 Generafing Confingencyt. The Balancing Authority
shall nofify the other Railbelt Balancing Authorifies of this change as soon
as pracficable but within 30 minutes of the unit’s start.
R76.After each calendar month in which one or more Reportable Disturbances occur,
the Reliability Coordinator shall determine and make available to the Obligated
Enfifies the Interconnecfion’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.
R87.Following any Reportable Disturbance that causes the Interconnecfion’s six
rolling average Primary Frequency Response Performance to be less than the
average IMFR PFR Obligafion from the last six Reportable Disturbances, the
Reliability Coordinator shall direct any necessary acfions to improve Primary
Frequency Response, which may include but are not limited to the following:
direcfing adjustment of gGovernor deadband and/or droop seftings.
R98. Each Generator Owner shall operate each generafing unit/ generafing facility
that is connected to the Railbelt with the gGovernor in service (droop acfive) and
responsive to frequency when the generafing unit/generafing facility is online
and released for dispatch, unless the Generator Owner has permission from the
Reliability Coordinator a valid reason for operafing with the gGovernor not in
service (droop inacfive) and the Generator System Operator has been nofified of
the status changethat the Governor is not in service.
R109. A Balancing Authority shall nofify the other Railbelt Balancing Authorifies and
the Reliability Coordinator as soon as pracfical but within 30 minutes of the
discovery of a status change (in service, out of servicedroop acfive/inacfive) of a
gGovernor and steps taken by the Balancing Authority to maintain their Primary
Frequency Response Obligafion.
Commented [MAH3]: After discussion with the obligated
ufilifies
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Page 4 of 17614
R110.Each The Generator ownerGenerator Owner shall meet a minimum 12-month
rolling average Primary Frequency Response performance of 0.7575% of the
Expected Primary Frequency Response value foron each generafing
unit/generafing facility, based on parficipafion in at least eight Reportable
Disturbances as described in Secfion 46 of the Reference Document.
110.1 The Primary Frequency Response performance shall be the rafio of the
Actual Primary Frequency Response to the Expected Primary Frequency
Response scaled by the deviafion of frequency in the arresfing period per
Reportable Disturbance. The Actual PFR is the measured response, in
MW, of a generating unit during the arrest period of a Reportable
Disturbance. during the inifial measurement period following the
DisturbanceThe Expected PFR of a generafing unit is the annually updated
values in Table 1, 2, and 3 of Appendix A, as calculated in Requirement
R3. If the available headroom is less than the Expected PFR listed in the
tables at the fime of the disturbance, the available headroom will be used
in the performance calculafion. .
110.2 If a generafing unit/ generafing facility has not parficipated in a minimum
of eight Reportable Disturbances in a 12-month period, performance shall
be based on a rolling eight average.rolling average of the previous eight
Reportable Disturbances.
110.3. If a generafing unit/ generafing facility has not parficipated in any
Reportable Disturbances, Primary Frequency Response performance may
be determined from unit load rejecfion test data from a system
disturbance that caused frequency to deviate more than 0.3 Hz..
110.4. A generafing unit/generafing facility’s’s Primary Frequency Response
performance during a Reportable Disturbance may be excluded from the
rolling average calculafion by the Balancing Authority due to a legifimate
operafing condifion that prevented normal Primary Frequency Response
performance. Such exclusion must be approved by the Reliability
Coordinator. Examples An example of a legifimate operafing condifions
that may support exclusion of a generafing unit from Reportable
Disturbances include, but are not limited to::
Operafion at or near auxiliary equipment operafing 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 subsfitute.
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Commented [MAH4]: Again, why not 0.2?
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R121.Each Balancing Authority must dispatch Primary Frequency Response reserves
must be dispatched such that a single unit trip does not cause Underfrequency
Load Shed to occur as described in Secfion 57 of the Reference Document. 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 and the
Balancing Authority selling spin must state that the spin they are selling is PFR.
C. Measures
M1. The Balancing Authority shall have evidence that it was carrying its Confingency
Reserve allocafion as required in Requirement R1.
M21. The Balancing Authority shall have evidence it reported each Reportable
Disturbance to the Compliance Monitor and that it made the informafion
available to the Obligated Enfifies within 14 calendar days after the Disturbance
as required in Requirement R21.
M32. The Balancing Authority shall have evidence it calculated and reported the rolling
12-month average Primary Frequency Response performance of each generafing
unit/ generafing facility monthly annually to the Compliance Monitor with
supporfing documentafion as required in Requirement 32.
M43. The Balancing Authority shall provide documentafion on how Baftery Energy
Storage systems are set to respond to Reportable Disturbances and the
parameters listed in R1 must reflect the Coordinafion Study. The Balancing
Authority shall also report the performance of the Energy Storage System when
used for Primary Frequency Response.
M54. Balancing Authorifies using SILOS for Primary Frequency Response shall report
how SILOS are programed with their delay fimes and frequency set points, as
well as their performance if used for Primary Frequency Response..
M65. The Reliability Coordinator shall provide evidence that the IMFR Primary
Frequency Response Obligafion was determined hourly as required in
Requirement 65. The Reliability Coordinator shall provide evidence that the
IMFR, the methodology for calculafion and the criteria for determining the IMFR
are available to Obligated Enfifies . If there are any changes impacfing the
IMFRPrimary Frequency Response Obligafion, the Balancing Authority shall
provide evidence that they nofified the other Railbelt Balancing Authorifies.
M76. The Reliability Coordinator shall provide evidence that the rolling average of the
Interconnecfion’s combined Primary Frequency Response Performance for the
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last (6) six Reportable Disturbances was calculated and made available to the
Obligated Enfifies as required in Requirement 76.
M87.The Balancing Authority shall provide evidence that acfions were taken to
improve the Interconnecfion’s Primary Frequency Response if the
Interconnecfion’s six-Reportable Disturbance rolling average combined Primary
Frequency Response performance was less than the average PFR Obligafion from
the last six Reportable Disturbancesless than the IMFR, as required by in
Requirement R87. The Balancing Authority shall be required to increase their
Primary Frequency Response allocafion for the next calendar quarter by the
amount they were deficient in. .
M98. Each Generator Owner shall have evidence that it nofified the Generator System
Operator as soon as pracfical each fime it discovered a gGovernor status change
(droop acfive/inacfive)not in service when the generafing unit/ generafing facility
was online and released for dispatch. Evidence may include but not limited to
operator logs, voice logs, or electronic communicafions.
M109. The Balancing Authority shall have evidence that they nofified the other Railbelt
Balancing Authorifies within 30 minutes of each discovery of a status change (in
service, out of service) droop acfive/inacfive) of a governor. They shall also have
evidence of steps taken to maintain their Primary Frequency Response
Obligafion.
M110. Each Generator Owner shall have evidence that each of its generafing
units/generafing facilifies achieved a minimum rolling average of Primary
Frequency Response performance level of at least 0.7575% of the Expected
Primary Frequency Response as described in Requirement R119. Each Generator
Owner shall have documented evidence of any Reportable Disturbances where
the generafing unit performance was excluded from the rolling average
calculafion.
M121. The Balancing Authority shall have evidence that theya dispatched Primary
Frequency Response reserves such that a single unit trip does not cause
Underfrequency Load Shed to occur. The Balancing Authority shall have evidence
that a Balancing Authority purchasing spin as a source of Primary Frequency
Response, must state that the spin they are purchasing must be PFR and the
Balancing Authority selling spin must state that the spin they are selling is PFR.
single unit trip did not cause Underfrequency Load Shed to occur.
D. Compliance
C1. Compliance Monitoring Process
Commented [MAH5]: To clarify, are we considering this
to be RFS? Defining the spin consists of ESS and RFS or ESS,
RFS, and SILOS? IE, does spin-back count or not?
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C1.1. Compliance Enforcement Authority
Reliability Organizafion
C1.2. Compliance Monitoring Period and Reset Time Frame
Compliance for the Primary Frequency Response Policy will be evaluated
for each reporfing period, as determined by the Reliability Organizafion.
C1.3. Data Retenfion
Each Balancing Authority shall keep the following data or evidence for a
minimum of ten years. If any of the following data for a Balancing
Authority are undergoing a review to address a quesfion that has been
raised regarding the data, the data is to be saved beyond the normal
retenfion period unfil the quesfion is formally resolved.
The BA shall retain all data for Confingency Reserve calculafions
and allocafion for Requirement R1, Measure M1.
The BA shall retain a list of all Reportable Disturbance informafion
for Requirement R2, Measure M2.
The BA shall retain all annual PFR performance reports for
Requirement 3, Measure M3.
The BA shall retain all Energy Storage System parameters and
performance reports for Requirement R4, Measure R5
The BA shall retain all SILOS seftings informafion and performance
reports for Requirement R5, Measure M5.
The BA shall retain all PFR Obligafion calculafions, and related
methodology and criteria documents for Requirement R6,
Measure M6.
The Reliability Coordinator shall retain all data and calculafions
relafing to the Interconnecfion’s combined Primary Frequency
Response, and all evidence of acfions taken to increase the
Interconnecfion’s Frequency Response for Requirements R7 and
R8, Measure M7 and M8.
The BA shall retain all evidence of Governor status changes and
communicafion of status change for Requirement R9 and R10,
Measure M9 and M10.
The BA shall retain all data and calculafions for each generafing
unit performance for Requirement R11, Measure M11.
The BA shall retain all evidence for Requirement R12, Measure 12.
C1.4. Addifional Compliance Informafion
None.
C1. Levels of BA Non-Compliance for Requirement R1, Measure M1
Formatted: Font: Bold
Commented [MAH6]: GVEA’s data retenfion policy is set
to 7 years. What is the reasoning for 10 years?
Formatted: List Paragraph, Bulleted + Level: 1 +
Aligned at: 1.75" + Indent at: 2"
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C1.1 Level 1 _– A Balancing Authority failed to provide evidence of carrying its
allocated Confingency Reserves.
Level 2 – A Balancing Authority failed to carry its allocated Confingency
Reserves.
C2. Levels of BA Non-Compliance for Requirement R2, Measure M2
C2.1 Level _1 – A Balancing Authority failed to report a Reportable Disturbance
within 14 days of the Disturbance and make the following informafion
listed in Requirement R1 available to all Obligated Enfifies.
Level 2 – A Balancing Authority failed to report a Reportable Disturbance
and make the following informafion listed in Requirement R1 available to
all Obligated Enfifies.
C3. Levels of BA Non-Compliance for Requirement R3, Measure M3
C3.1 Level 2_ – A Balancing Authority failed to calculate and submit to the
Compliance Monitor the Expected Primary Frequency Response of each
generafing unit annually within two weeks of date determined by the
Reliability Coordinator.
C4. Levels of Interconnecfion Non-Compliance for Requirement R6, Measure M6
C.4.1 Level 1_ – The Reliability Coordinator failed to determine the Primary
Frequency Response Obligafion and failed to make the methodology and
criteria for determinafion of the PFR Obligafion available to the Obligated
Enfifies.
C5. Levels of BA Non-Compliance for Requirement R7-R8, Measure M7-M8
C5.1 Level 2_– A Balancing Authority failed to provide evidence that acfions
were taken to improve the Interconnecfion’s Primary Frequency Response
if the Interconnecfion’s six-Reportable Disturbance rolling average
Primary Frequency Response performance was less than the PFR
Obligafion.
C6. Levels of BA Non-Compliance for Requirement R9-R10, Measure M9-M10
C6.1 Level _ 1– A Balancing Authority failed to inform the other Railbelt
Balancing Authorifies within 30 minutes of a governor status change.
Level 2– A Balancing Authority failed to inform the other Railbelt
Balancing Authorifies of a governor status change.
C7. Levels of BA Non-Compliance for Requirement R11, Measure M11
C7.1 Level _2– A Generator Owner failed to report and failed to meet a rolling
average Primary Frequency Response performance of 75% of Expected
Primary Frequency Response on each generafing unit.
C8. Levels of BA Non-Compliance for Requirement R12, Measure M12
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C8.1 Level _2– A Balancing Authority failed to dispatch Primary Frequency
Response reserves such that a single unit trip does not cause
Underfrequency Load Shed to occur.
ED. Definifions
Term Acronym Definition
Actual Primary
Frequency Response
Actual
PFR
The measured response,in MW,of a generating unit during the
arrest period of a Reportable Disturbance.
Expected Primary
Frequency Response
Expected
PFR
The expected primary frequency response of a generating unit is
the 12-month average of the generating unit’s performance,
updated annually or the available headroom of the unit at the
time of the disturbance. The lesser of the two values will be used
as the Expected PFR in calculations.
Largest Single
Instantaneous
Generation Continency
LSIGC The maximum thermal rating declared capability of the Llargest
Single Instantaneous Ggenerating unit Ccontingency (or
combination of units with a single point of interconnection, such
as a GSU, forming a single contingency regardless of RAS
applications) 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.
Primary Frequency
Response Obligation
PFRO The Primary Frequency Response Obligafion, calculated in MW,is
the amount of reserves that the Railbelt must carry to avoid
Underfrequency Load Shed and is equal to the Largest Single
Instantaneous Generafion Confingency.
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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Commented [MAH8]: If this is correct, why are we
stafing 0.3 Hz everywhere else in this document
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Aftachment 1
Primary Frequency Response Reference Document
1. Introducfion
This Primary Frequency Response Reference Document provides a methodology for calculafing
the Primary Frequency Response performance of individual generafing units following
Reportable Disturbances in accordance with Requirements R3 and R11. The document also
provides more informafion on SILOS sefting provided by the Railbelt Confingency Reserves
Analysis study done by EPS and dispatching units using the Primary Frequency Response
method as described in the study.
This document provides the methodology for calculafing the Primary Frequency Response (PFR)
and performance of generafing units/generafing facilifies. EPS conducted three studies:
Benchmarking Report V0 which was a PSSE model validafion report, Railbelt Confingency
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 Confingency Reserves
Analysis V2 proposed 2 methods to dispatch Confingency Reserve, or Spin. One method was the
Primary Frequency Response Method, PFR, which will be discussed in this document.
2. Primary Frequency Response Calculafions using Digital Fault Recorders or
Synchrophasor data
Requirement 32
R3. The Balancing Authority shall calculate the Primary Frequency Response of each
generafing unit in accordance with this standard and Secfion 2 of the Primary
Frequency Response Reference document. This calculafion shall provide a 12-
month average of Primary Frequency Response performance. Unit performance
shall be measured through Digital Fault Recorders (DFR) recordings or
Synchrophasor data during the arrest period of Reportable Disturbances. This
calculafion shall be completed annually to update each generafing unit’s
Expected Primary Frequency Response values in Tables 1, 2, and 3 in Appendix A
of the Reference Document, per the Reliability Coordinator’s direcfion.
3.1.The calculafion results shall be submifted to the Compliance Monitor and
made available to the Balancing Authority within two weeks of a date
determined by the Reliability Coordinator.
3.2.If a generafing unit has not parficipated 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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3.3.If a generafing unit has not parficipated in any Reportable Disturbances,
Primary Frequency Response performance may be determined from unit
load rejecfion test data from a system disturbance that caused frequency
to deviate more than 0.3 Hz. If there is no data available for the
generafing unit, its Expected Primary Frequency Response must be set to
0 MW.
R2. The Balancing Authority shall calculate the Primary Frequency Response of each
generafing unit/ generafing facility in accordance with this standard and the
Primary Frequency Response Reference document. This calculafion 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 Secfion 2 of the Reference
Document. This calculafion shall be completed each month for the preceding 12
calendar months.
2.1.The calculafion results shall be submifted 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 generafing unit/generafing facility has not parficipated 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 generafing unit/ generafing facility has not parficipated in any
Reportable Disturbances, Primary Frequency Response performance may
be determined from unit load rejecfion test data.
To determine the performance of each generafing unit/ generafing facility to provide Primary
Frequency Response during a Reportable Disturbance, Disturbance Fault Recorder, DFR,
recordings are used. Synchrophasor data may also be used upon availability. This calculafion
shall provide a 12-month rolling average of unit performance which will be used of the primary
frequency performanceto update the Expected Primary Frequency Response values in Tables 1,
2, and 3 of Appendix A. The PFR of a unit during a Reportable Disturbance using DFR or
Synchrophasor recordings is measured using the following formula:
𝑃𝐹𝑅𝑈𝑛𝑖𝑡= (𝑀𝑊𝑓min _𝑢𝑛𝑖𝑡−𝑀𝑊𝑓pre−disturbance 𝑀𝑊𝑝𝑟𝑒−𝑒𝑣𝑒𝑛𝑡)∗60.0 𝐻𝑧−58.2 𝐻𝑧60.0 −𝑓min _𝑢𝑛𝑖𝑡
Where
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𝑀𝑊𝑓min _𝑢𝑛𝑖𝑡 is the unit’s output when unit frequency reaches its minimum. 𝑀𝑊𝑓pre−disturbance 𝑀𝑊𝑝𝑟𝑒−𝑒𝑣𝑒𝑛𝑡is the unit’s output before the Disturbance occurs. 𝑃𝐹𝑅𝑈𝑛𝑖𝑡 is the primary frequency response of the unit during a Reportable Disturbance. 𝑓min _𝑢𝑛𝑖𝑡 is when the when the unit’s frequency reaches its minimum value.
3. Baftery Energy Storage Systems (BESS)
Requirement 3
R3:The Balancing Authority may set their Baftery Energy Storage Systems to supply
Primary Frequency Response reserves up to the asset’s full rafing as described in
Secfion 3 of the Reference Document. Energy Storage Systems shall be
considered a generafing unit in this standard.
A BESS may be used for Primary Frequency Response up to its rafing. If limits are placed on a
BESS, the Primary Frequency Response of that BESS is only assigned to that limit.
34. Shed In Lieu of Spin (SILOS)
Requirement 54
R5. The Balancing Authority may set their Energy Storage Systems to supply Primary
Frequency Response reserves up to the asset’s full rafing. The following
parameters must be provided to the Reliability Coordinator: droop, ramp rates,
and limits. Parameters provided must be defined by a Coordinafion Study. Energy
Storage Systems shall be considered a generafing unit in this standard.
Performance of the Energy Storage System shall be tracked as if it’s a generafing
unit.
R4: Each Balancing Authority may use SILOS for Primary Frequency Response.
Frequency set points and delay fimes must be set as described in Secfion 4 of the
Reference Document.
SILOS seftings at the fime of the Railbelt Confingency Reserves Analysis studyEPS Study did not
trigger before Stage 1 Underfrequency Load Shed due to long delay fimes. The following table,
provided by the study,shows five sets of alternate SILOS seftings with shorter delay fimes. 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 fimes are the
detecfion and relay fime, and not the breaker operafing fime. Each Balancing Authority shall
report how SILOS are programed with their delay fimes 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. Interconnecfion Minimum Frequency Response (IMFR)
Requirement 5
R5. The Reliability Coordinator shall determine the Interconnecfion Minimum
Frequency Response (IMFR) hourly as the maximum rafing of the Largest Single
Generafing Confingency commifted for the day per Hertz. The IMFR, the
methodology for calculafion and the criteria for determinafion of the IMFR shall
be made available to the Obligated Enfifies as described in Secfion 5 of the
Reference Document.
5.1. If an unscheduled unit, that has a larger maximum rafing 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 Generafing
Confingency. The Balancing Authority shall nofify the other Railbelt
Balancing Authorifies of this change as soon as pracficable but within 30
minutes of the unit’s start.
This secfion of the PFR Reference Document establishes the process to calculate the
Interconnecfion’s Minimum Frequency Response, IMFR. This methodology defines the LSGC,
Largest Single Generafion Confingency, as the declared capability of the largest generafing unit
confingency connected to the Railbelt. The HRSG would not be included in the calculafion of the
LSGC due to the negligible ramp down of the HRSG during the arresfing period
The Interconnecfion Minimum Frequency Response is calculated as the Railbelt’s Primary
Frequency Response Obligafion per Hertz. The Primary Frequency Response Obligafion 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 Obligafion is 60 MW and the IMFR is 60 MW/ 1 Hz or 6.0 MW/0.1.
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46. Primary Frequency Response Performance Calculafion
Requirement 110
R11. The Generator Owner shall meet a minimum 12-month rolling average Primary
Frequency Response performance of 75% of the Expected Primary Frequency
Response Value of each generafing unit, based on parficipafion in at least eight
Reportable Disturbances as described in Secfion 4 of the Reference Document.
11.1 The Primary Frequency Response performance shall be the rafio of the
Actual Primary Frequency Response to the Expected Primary Frequency
Response scaled by the deviafion of frequency in the arresfing period per
Reportable Disturbance. The Actual PFR is the measured response, in
MW, of a generating unit during the arrest period of a Reportable
Disturbance.The Expected PFR of a generafing unit is the annually
updated values in Table 1, 2, and 3 of Appendix A, as calculated in
Requirement R3. If the available headroom is less than the Expected PFR
listed in the tables at the fime of the disturbance, the available headroom
will be used in the performance calculafion.
11.2 If a generafing unit has not parficipated in a minimum of eight Reportable
Disturbances in a 12-month period, performance shall be based on a
rolling average of the previous eight Reportable Disturbances.
11.3. If a generafing unit has not parficipated in any Reportable Disturbances,
Primary Frequency Response performance may be determined from unit
load rejecfion test data from a system disturbance that caused frequency
to deviate more than 0.3 Hz.
R10. Each Generator owner shall meet a minimum 12-month rolling average Primary
Frequency Response performance of 0.75 on each generafing unit/generafing
facility, based on parficipafion in at least eight Reportable Disturbances as
described in Secfion 6 of the Reference Document.
10.1 The Primary Frequency Response performance shall be the rafio of the
Actual Primary Frequency Response to the Expected Primary Frequency
Response during the inifial measurement period following the
Disturbance.
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10.2 If a generafing unit/generafing facility has not parficipated 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 generafing unit/ generafing facility has not parficipated in any
Reportable Disturbances, Primary Frequency Response performance may
be determined from unit load rejecfion test data.
10.4.A generafing unit/generafing facility’s Primary Frequency Response
performance during a Reportable Disturbance may be excluded from the
rolling average calculafion by the Balancing Authority due to a legifimate
operafing condifion that prevented normal Primary Frequency Response
performance. Examples of legifimate operafing condifions that may
support exclusion of a generafing unit from Reportable Disturbances
include, but are not limited to:
Operafion at or near auxiliary equipment operafing 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 subsfitute.
This secfion describes how to calculate the average Primary Frequency Response for each
generafing unit/ generafing facility over a 12 month period with a minimum of (8) Reportable
Disturbances. If a generafing unit/ generafing facility has not parficipated 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 parficipated in at least 8 Reportable Disturbances historically, then
data from unit load rejecfion tests will be used.The unit load rejecfion test will be considered a
Reportable Disturbance so it can be included in the performance calculafion.This is to establish
whether the unit is in compliance with its PFR obligafion. 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. 𝐴𝑣𝑔𝑃𝑒𝑟𝑖𝑜𝑑=[𝑃.𝑈. 𝑃𝐹𝑅𝑢𝑛𝑖𝑡]≥0.75
Where 𝑃.𝑈. 𝑃𝐹𝑅𝑢𝑛𝑖𝑡=𝐴𝑐𝑡𝑢𝑎𝑙𝑃𝐹𝑅𝑢𝑛𝑖𝑡𝐸𝑥𝑝𝑒𝑐𝑡𝑒𝑑𝑃𝐹𝑅𝑢𝑛𝑖𝑡∗∆𝑓
Where
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𝐴𝑐𝑡𝑢𝑎𝑙𝑃𝐹𝑅𝑈𝑛𝑖𝑡= (𝑀𝑊𝑓min _𝑢𝑛𝑖𝑡−𝑀𝑊𝑓pre−disturbance ) is the measured response of the unit
during the arrest period. 𝐸𝑥𝑝𝑒𝑐𝑡𝑒𝑑𝑃𝐹𝑅𝑈𝑛𝑖𝑡 is the expected PFR of the unit taken from Tables 1, 2, and 3 in Appendix A
or the available headroom on the unit. The expected PFR used in the calculafion is the lesser
value of the two. ∆𝑓=𝑓𝑝𝑟𝑒−𝑑𝑖𝑠𝑡𝑢𝑟𝑏𝑎𝑛𝑐𝑒−𝑓min _𝑢𝑛𝑖𝑡 is the frequency deviafion from right before the Disturbance
occurs to when the unit’s frequency reaches its minimum value.
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 calculafion. The If the unit would
be considered operafing at full capacity, so its expected PFR would be set to 0 MW and would
sfill be response is not included to calculate the average performance unless exclusion is
approved by the Reliability Coordinator. If a unit has not run for more than a defined number of
hours and there is no available data from unit load rejecfion tests, Primary Frequency Response
for the unit shall be assigned 0 MW.
57. Primary Frequency Response Dispatch
Requirement 121
R12. Each Balancing Authority must dispatch Primary Frequency Response reserves
such that a single unit trip does not cause Underfrequency Load Shed to occur as
described in Secfion 5 of the Reference Document. 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 and the Balancing Authority selling spin
must state that the spin they are selling is PFR.
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 Secfion 7
of the Reference Document.
The PFR Primary Frequency Response method, described in the EPS study, 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
arresfing frequency and UFLS prevenfion 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.
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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 Railbelt Confingency Reserves Analysis Study summarizes the
simulated PFR values for each individual unit which are referenced in Tables 1, 2, and 3 in
Appendix A of this document which will be updated annually as stated in Requirement R3. This
value is the maximum allowable reserve that can be allocated to a unit under the assumpfion
that the unit has adequate headroom. If the headroom is of a unit is less than the Expected PFR
of that the unit, the response of the unit is equal to the available headroomlesser of the two
values will be assigned to the unit. When dispatching units, the sum of the available response of
each online unit’s PFR must be equal to or greater than the LGSC, as defined in this
documentLargest Single Instantaneous Generafion Confingency. As required in Requirement
131, 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 – Generafing Units Expected Unit Primary Frequency Response
The following tables were provided in the 2021 Railbelt Confingency Reserves Analysis study
completed by EPS. These tables must be updated annually as stated in Requirement R3 of the
Primary Frequency Response Policy.
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 and sShaded rows
have no PFR assigned to that unit
as stated in the EPS study.
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
Commented [MAH10]: Please explain where this data
came from. I’m not very comfortable with this number.
Commented [MAH11]: This is zero. UAF is not a PFR unit.
Attachment 2 – 345 kV Alaska Intertie Modifications
January 22, 2024
RE: 345kV Alaska Intertie Modifications
To Whom It May Concern:
The Douglas Substation (Willow, AK) – Healy Substation (Healy, AK) 345kV transmission line,
commonly referred to as the Alaska Intertie was constructed in the early 1980’s. The 345kV
transmission line was constructed using a mix of guyed X-towers, steel monopoles, and steel 3
pole turning structures. Structure foundations were designed using driven H-pile, concrete
spread footers, as well as Dywidag (groutable anchors) anchors.
An outage in 1989 prompted an investigation and during this investigation it was determined
that a possible imbalanced snow loading caused the conductor to sag too low and contact
vegetation. Over the next several years more investigations were conducted regarding
imbalanced snow loading. The conclusions of these findings resulted in the installation of a
Snow Load Monitoring System (SLMS). The SLMS utilizes inclinometers and load cells placed
at specific locations so that snow loading could be monitored remotely. In 1997 Dyden and
RaLue, Inc. prepared a document titled “Analysis of Unbalanced Snow Loads on the
Anchorage-Fairbanks Intertie” outlining their findings since 1989 as well as some recommended
modifications to reduce these line contacts. Once of the recommended modifications from the
report was to replace the suspension insulators with inverted V-string insulators. While there is
very little information on how this would be implemented, the idea was used to analyze the most
recent PLS CADD model of the Alaska Intertie.
In depth modeling of the Alaska Intertie indicated that a large majority of the transmission line
could experience imbalanced snow loading that would result in line to ground contact. An
imbalanced snow loading occurs when snow accumulates on all of the conductors across a
large area (multiple spans) and then due to some act of nature, usually due to the weight of the
snow or wind, the snow will shed on all of the conductors except for 1 span or 1 wire within a
span. This imbalanced loading causes the insulators on both structures to swing toward the
heavily loaded span resulting in extremely large conductor sag. Uniform snow loading does not
cause any clearance issues or concern as the insulators do not swing into a single span.
Multiple options were considered when trying to address the imbalanced load case with the
most promising solution being as follows:
1. Replace all 345kV suspension insulators (142.5” long) with insulators for a 230kV
installation (76” long)
a. By reducing the length of the insulators, the clearance to ground will be
increased approximately 66.5” or 5.54’.
b. Reducing the length of the insulators also reduces the amount of swing into the
imbalanced span and thereby reducing the sag further
AND
2. Convert all suspension insulators to an inverted and rotated V-string using insulator
lengths of approximately 11’ in order to maintain 230kV clearance between the
conductor and the structure (see image below)
a. By converting all suspension insulators to an inverted and rotated V-string, it is
essentially creating a semi dead-end condition on the insulators. This semi
dead-end condition already has insulators partially angled into each span and
thus reducing the allowable swing
It is recommended that additional analysis be performed to determine the total number of
structures that should have 230kV insulators installed (76”) and how many structures that would
require the Inverted and Rotated V-String insulator configuration. It is possible that the inverted
and rotated V-string configuration does not need to be implemented on all structures.
Image 1: Uniform Radial Ice on 1 Conductor
- Cyan conductor at 30°F no ice
- Yellow conductor at 30°F no ice (very close to cyan conductor)
- Red conductor at 30°F uniform 0.5” radial ice
- Dashed black line is required clearance of 20.19 feet
Image 2: Imbalanced Snow Loading on Span between Structure 458 and 459 without
Inverted V-String configuration
- Cyan conductor at 30°F no ice
- Yellow conductor at 30°F with a 3.6 pound per linear foot snow loading on Span
between 458 and 459
- Red conductor at 30°
- Dashed black line is required clearance of 20.19 feet
- Clearance on yellow conductor is 16.98 feet, less than the required 20.19 feet
Image 3: Imbalanced Snow Loading on Span between Structure 458 and 459
- Cyan conductor at 30°F no ice
- Yellow conductor at 30°F no ice (very close to cyan conductor)
- Red conductor at 30° with a 3.6 pound per linear foot snow loading on Span between
458 and 459
- Dashed black line is required clearance of 20.19 feet
- Clearance went from approximately 57’ on the cyan/yellow to 27’ on the red conductor
Image 4: X-Tower with 230kV Inverted and Rotated V-String Insulators
See also
“Analysis of Unbalanced Snow Loads on the Anchorage-Fairbanks Intertie. Dryden &
LaRue, Inc. March 7, 1997
Sincerely,
Jeremy Forsting, P.E.
Construction Services Manager
Intertie Management Committee Meeting
Operator Report
January 26, 2024
1. Alaska Intertie usage report
a. MWh usage – Measured at Douglas Substation, YTD
GVEA MEA Total
i. July – June FY23 176,070 13,240 189,310
ii. July – June FY22 115,785 23,309 134,305
iii. Delta - FY23 to FY22 52.06% -43.19% 40.96%
2. Alaska Intertie trips to report
Date Event SCADA Indication Cause
09/15/2023
Teeland-Douglas
Trip EGS-Hospital fault Relay Issue
10/09/2023 Douglas-Healy Trip B and C Phase Fault No cause known
10/10/2023 Douglas-Healy Trip B and C Phase Fault No cause known
11/24/2023
Pt. MacKenzie-
Teeland Trip
A-Phase-Ground
Fault
No cause known; RAS activation caused
Douglas 1B1 to open due to initial fault on
the 230kV Pt. MacKenzie to Teeland line.
3. IOC quarterly Reliability Report
For generation trips or transmission line trips where the loss of load is known, the Railbelt-wide
frequency response is calculated. The magnitude of the tripped power and the change in frequency
from the pre-trip value to the peak or nadir are used to calculate the MW/0.1Hz value often known as
‘Beta’. Chugach has calculated the Beta for several events and the table of the results is pasted below.
Events without data for the MW magnitude of the trip were excluded, as were events that did not cause
a frequency deviation greater than 0.2 Hz.
Event Date MW
Tripped
Pre-Trip
Frequency (Hz)
High /Low
Frequency
(Hz)
Frequency
Response
(MW/0.1Hz)
Healy 2 Trip 12/3/2023 44.5 60.04 59.68 12.2
Healy Unit 1 Trip 12/5/2023 15.1 60.01 59.77 6.4
GVEA Northpole GT3
Trip 12/27/2023 33.8 60.03 59.76 12.6
SPP Unit 12 Trip 1/18/2024 36.4 60.01 59.74 13.2
SPP Unit 12 Trip 1/18/2024 41.8 59.93 59.73 20.9