HomeMy WebLinkAbout2024-07-26 IMC Agenda and docs INTERTIE MANAGEMENT COMMITTEE (IMC) REGULAR MEETING July 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. AGENDA APPROVAL
5. PUBLIC COMMENTS
6. APPROVAL OF PRIOR MINUTES – June 21, 2024
7. NEW BUSINESS
A. Annual Meeting and Election of Officers
8. OLD BUSINESS
9. COMMITTEE REPORTS
A. Budget to Actuals
B. IOC Committee
i. Primary Frequency Response Policy - DRAFT
C. Operator Report
10. MEMBERS COMMENTS
11. NEXT MEETING DATE – September 27, 2024
12. ADJOURNMENT
Alaska Energy Authority
AK Intertie Budget to Actual Revenues and Expenses
07/01/2023 to 06/30/2024
DRAFT - REVISED
Page 1 of 4
FY24 Approved
Budget
BUDGET
07/01/2023 -
06/30/2024 Actuals
YTD Actuals as a
% of Total
Annual Budget
OVER (UNDER)
YTD Variance
Revenue From Utilities
AKI-GVEA 3,631,114 3,631,114 3,896,647 107%265,533
AKI-CEA 471,717 471,717 471,717 100%-
AKI-MEA 654,520 654,520 674,787 103%20,266
Total Revenue From Utilities 4,757,352 4,757,352 5,043,151 106%285,799
Interest - - 106,406 0% 106,406
Other - - 113,875 0%113,875
Total Revenues 4,757,352 4,757,352 5,263,432 111%506,080
Total Revenues 4,757,352 4,757,352 5,263,432 111%506,080
56600 Misc Transmission Expense
Alaska Energy Authority
AK Intertie-Cell Phone Comm. Svc. for Wx Monitorng 13,000 13,000 12,007 92%(993)
AK Intertie-Miscellaneous Studies as Needed 516,000 516,000 57,544 11%(458,456)
Alaska Energy Authority Total 529,000 529,000 69,551 13%(459,449)
Golden Valley Electric
AK Intertie-Private Line Telephone Service SCADA 6,000 6,000 2,315 39%(3,685)
Golden Valley Electric Total 6,000 6,000 2,315 39%(3,685)
56601 Weather Monitoring Batteries
Alaska Energy Authority
AK Intertie-SLMS Support & Intertie Ground Patrol 175,000 175,000 133,342 76%(41,658)
Alaska Energy Authority Total 175,000 175,000 133,342 76%(41,658)
56700 Rents
Alaska Energy Authority
AK Intertie-Alaska Railroad 1,000 1,000 1,000 100%-
Alaska Energy Authority Total 1,000 1,000 1,000 100%-
Matanuska Electric Association
AK Intertie-Talkeetna Storage 7,200 7,200 7,200 100%-
Matanuska Electric Association Total 7,200 7,200 7,200 100%-
56900 Maintenance of Structures
Matanuska Electric Association
AK Intertie-Maintenance of Structures 150,000 150,000 414 0%(149,586)
Matanuska Electric Association Total 150,000 150,000 414 0%(149,586)
57000 Maintenance of Station Equip
Chugach Electric Association
AK Intertie-Teeland Substation 175,000 175,000 147,994 85%(27,006)
AK Intertie-Douglas Substation Communications - - 4,123 0%4,123
Chugach Electric Association Total 175,000 175,000 152,118 87%(22,882)
Golden Valley Electric
AK Intertie-Healy, Cantwell, Goldhill 125,000 125,000 81,744 65%(43,256)
AK Intertie-Cantwell 4S2 Switch Repair 306,000 306,000 748 0%(305,252)
AK Intertie-Capacitor Spares 20,000 20,000 - 0%(20,000)
AK Intertie-Healy&Goldhill Digital Fault Recorders - - 6,046 0%6,046
AK Intertie-Goldhill SVC Cooling - - 2,059 0%2,059
Golden Valley Electric Total 451,000 451,000 90,597 20%(360,403)
Matanuska Electric Association
AK Intertie-Douglas Substation 25,000 25,000 5,181 21%(19,819)
Matanuska Electric Association Total 25,000 25,000 5,181 21%(19,819)
57100 Maint of OH Lines
Golden Valley Electric
AK Intertie-Northern Maintenance 150,000 150,000 99,237 66%(50,763)
AK Intertie-Landing Pads 75,000 75,000 - 0%(75,000)
Golden Valley Electric Total 225,000 225,000 99,237 44%(125,763)
ALASKA ENERGY AUTHORITY
AK INTERTIE BUDGET TO ACTUAL REVENUE AND EXPENSES
FOR THE PERIOD 07/01/2023 THROUGH 06/30/2024
Page 2 of 4
FY24 Approved
Budget
BUDGET
07/01/2023 -
06/30/2024 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 06/30/2024
AK Intertie-Special Patrols (Incl Foundation Insp) - - 6,510 0% 6,510
AK Intertie-Southern Maint. (Incl Ground Insp)140,000 140,000 - 0%(140,000)
AK Intertie-Equipment Repair & Replacement 350,000 350,000 175,712 50%(174,288)
Matanuska Electric Association Total 490,000 490,000 182,222 37%(307,778)
57101 Extra Ord Maint of OH Lines
Golden Valley Electric
AK Intertie-Re-level Structures & Adjust Guys 80,000 80,000 - 0%(80,000)
Golden Valley Electric Total 80,000 80,000 - 0%(80,000)
57102 Maint OH Lines-ROW Clearing
AK Intertie-Northern ROW Clearing 550,000 550,000 626,189 114%76,189
AK Intertie-Northern ROW Remote Sensing 400,000 400,000 321,675 80%(78,325)
AK Intertie-Repair Tower 531 Foundation 150,000 150,000 154,915 103%4,915
AK Intertie-Repair Tower 532 Foundation 150,000 150,000 154,915 103%4,915
Golden Valley Electric Total 1,250,000 1,250,000 1,257,694 101%7,694
Matanuska Electric Association
AK Intertie-Southern ROW Clearing 500,000 500,000 - 0%(500,000)
AK Intertie-Southern ROW Remote Sensing 125,000 125,000 100,523 80%(24,477)
Matanuska Electric Association Total 625,000 625,000 100,523 16%(524,477)
58306 Misc Admin
Alaska Energy Authority
AK Intertie-IMC Admin Cost (Audit, Meeting, Legal)20,000 20,000 20,512 103%512
Alaska Energy Authority Total 20,000 20,000 20,512 103%512
58401 Insurance Premiums
Alaska Energy Authority
AK Intertie-Insurance 22,200 22,200 22,673 102%473
Alaska Energy Authority Total 22,200 22,200 22,673 102%473
Matanuska Electric Association
AK Intertie-Insurance 14,800 14,800 19,885 134%5,085
Matanuska Electric Association Total 14,800 14,800 19,885 134%5,085
Total Total Expense 4,246,200 4,246,200 2,164,464 51%(2,081,736)
Total Operating Expenses 4,246,200 4,246,200 2,164,464 51%(2,081,736)
71001 Total Expense, Budget
Alaska Energy Authority
Administrative Support Services 230,000 230,000 215,052 94%(14,948)
Alaska Energy Authority Total 230,000 230,000 215,052 94%(14,948)
Total Total Expense 230,000 230,000 215,052 94%(14,948)
Total AEA Administration Expenses 230,000 230,000 215,052 94%(14,948)
Total Expenses 4,476,200 4,476,200 2,379,516 53%(2,096,684)
Surplus (Shortage)281,152 281,152 2,883,916 1026%2,602,764
Page 3 of 4
Alaska Intertie FY24 Budget to Actuals Status Report for the Period 07/01/2023 through 06/30/2024
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 32,601 2,519 - 35,120
Feb 24,740 2,043 - 26,783 Feb 12,498 2,292 - 14,790
Mar 21,230 2,158 - 23,388 Mar 17,370 2,287 - 19,657
Apr 13,470 1,943 - 15,413 Apr 13,581 2,055 - 15,636
May 20,380 1,871 - 22,251 May 12,358 2,194 - 14,552
Jun 31,070 1,835 - 32,905 Jun 6,265 2,205 - 8,470
TOTAL 249,190 25,147 - 274,337 TOTAL 270,743 26,792 - 297,535
INTERTIE PROJECTED ENERGY USAGE TO DATE (MWH)274,337 INTERTIE ACTUAL ENERGY USAGE TO DATE (MWH) 297,535
Budgeted Operating Costs for the Period 4,246,200$ Actual Operating Costs for the Period 2,164,464$
(based on amended budget)
Budgeted Usage Revenue for the Period 3,379,832$ Actual (Billed) Usage Revenue for the Period 3,665,631$
(budgeted rate * projected usage)(budgeted rate * actual usage)
Estimated Budgeted Energy Rate per MWH 12.92$
(based on budgeted costs and usage)
Annual Budgeted Energy Rate (Billed Rate)12.32$ Projected Actual Energy Rate per MWH 6.07$
(based on minimum contract value)(based on actual costs and usage)
Page 4 of 4
Intertie Management Committee Meeting
IOC Report
July 26, 2024
1. Intertie Operating Committee
a. Attached is a draft of the Primary Frequency Response (PFR) policy. The policy outlines
the required PFR Reserves (“fast spin”) to recover from the loss of the largest single
generation on the system. It also defines how the PFR Reserves are allocated between
utilities (load ratio share) and how the PFR Reserves are calculated. A couple items of
note in the policy:
i. The largest generator is not by nameplate rating, but by the utility’s declared
output for the unit.
ii. Tie lines are not included in the PFR Reserves calculation
iii. SILOS and Energy Storage Systems may be used for PFR Reserves
iv. The Reliability Coordinator is responsible for determining PFR Reserves on an
hourly basis
v. Balancing Authorities are responsible for PFT Reserves, not IPPs
b. IPP interconnection regulation requirements were discussed. No specific conclusions or
recommendations were developed. However, there is a general concern about
interconnecting larger IPPs without fully understanding their impact on the system. The
SSS is managing a study on IBR impacts and the results should help guide the discussion
on interconnecting IPPs.
c. The Healy SVC has seen issues recently that are under review by AEA, GVEA, and the
OEM, GE. No definitive solution has been identified yet, but all parties are actively
engaged in the investigation and in resolving the issues.
d. In February GVEA submitted two grant applications on behalf of the IMC, one for
Synchorphasors and one for the Alaska Intertie Snow Load Remediation. Both of those
grants have been approved, however the official award and the ability to spend on the
grants is still pending with DOE. Timing of the award is unknown but expected
sometime later this year. Upon official award, expenses can be charged to the projects
and both projects can kick off in earnest.
2. System Studies Subcommittee
a. EPS is performing a system impact study that focuses on the impacts of upgrading the
Alaska Intertie to 230 KV. The study is ongoing, and results are not anticipated until Q4
or early 2025.
b. An IBR study is out to bid, and bids are due August 23 rd. The preliminary schedule has
this study completed in Q1 of 2025.
3. SCADA and Telecommunications
a. Right-of-way is ongoing at Douglas for the communication upgrades between
Anchorage and Douglas. A preliminary right-of-entry (ROE) agreement has been
executed to allow for the design of the upgrades at Douglas. A final ROW
agreement will need to be executed prior to construction commencing at
Douglas.
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Page 1 of 18
Primary Frequency Response Policy
A. IntroducƟon
1. Title: Primary Frequency Response Policy
2. Number: TBA
3. Purpose:
3.1. This policy defines a process to maintain interconnecƟon frequency
within defined limits during the arrest period.
4. Applicability:
4.1. Balancing AuthoriƟes
4.2. Generator Owners
4.3. Generator Operators
4.4. Obligated EnƟty
4.5. Reliability Coordinator
5. EffecƟve Date: 12 months from adopƟon by the Reliability OrganizaƟon.
B. Requirements
R1. The ConƟngency Reserve requirement, which are reserves acƟvated throughout
the arresƟng and rebound periods and maintained through the recovery period,
for the Railbelt shall not be less than an amount equivalent to 100 percent of the
System Reserve Basis as defined in AKRES-001-2. The ConƟngency Reserve
requirement is allocated among the Balancing AuthoriƟes by the load raƟo share
of a 3-year average of each uƟlity’s coincident peak load, as shown in SecƟon 2 of
the Reference Document.
1.1 The Primary Frequency Response Reserves, which are a subset of
ConƟngency Reserves and acƟvated during the arresƟng period, shall not
be less than an amount equivalent to 100 percent of the expected output
of the Railbelt’s Largest Single Instantaneous GeneraƟng ConƟngency,
LSIGC as defined in this policy. Primary Frequency Response reserves are
allocated by the load raƟo share of a 3-year average of each uƟlity’s
coincident peak load, as shown in SecƟon 2 of the Reference Document.
R2. The Balancing Authority shall idenƟfy Reportable Disturbances and within 14
days of the Disturbance, shall noƟfy the Compliance Monitor and make the
following informaƟon available to all Obligated EnƟƟes: Ɵme of Disturbance, pre-
disturbance frequency, frequency minimum/ maximum, magnitude of
disturbance, and cause of the disturbance.
7/15/2024 Rev 1
Page 2 of 18
R3. The Balancing Authority shall calculate the Primary Frequency Response of each
generaƟng unit in accordance with this standard and SecƟon 3 of the Primary
Frequency Response Reference document. This calculaƟon shall provide a 12-
month average of Primary Frequency Response performance. The measuring
device used to measure performance must provide recordings of individual units
which must be GPS Ɵme synchronized and have a sample rate of no more than
30 milliseconds. This calculaƟon shall be completed annually, per the Reliability
Coordinator’s assigned date, to update each generaƟng unit’s Expected Primary
Frequency Response values.
3.1. The calculaƟon results shall be submiƩed 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 generaƟng unit has not parƟcipated in a minimum of (8) eight
Reportable Disturbances in a 12-month period, its performance shall be
based on a rolling eight average response.
3.3. If a generaƟng unit has not parƟcipated in any Reportable Disturbances,
Primary Frequency Response performance may be determined from unit
load rejecƟon test data from a system disturbance that caused frequency
to deviate more than 0.3 Hz. If there is no data available for the
generaƟng unit, its Expected Primary Frequency Response shall be set to
0 MW.
3.4. If a Generator Owner needs to change their generaƟng unit’s Expected
Primary Frequency Response value earlier than the annual assigned date,
they shall supply the documentaƟon to support the change. Upon
approval from the Reliability Coordinator, the Primary Frequency
Response of the generaƟng unit shall be updated and the Obligated
EnƟƟes shall be noƟfied on the change.
R4. The Balancing Authority may set their Energy Storage Systems to supply Primary
Frequency Response reserves up to the Energy Storage System’s full raƟng. The
following parameters must be provided to the Reliability Coordinator: droop,
ramp rates, and limits. Parameters provided must be defined by a CoordinaƟon
Study. Energy Storage Systems shall be considered a system that can provide
Primary Frequency Response. Performance of the Energy Storage System shall be
tracked as if it is a generaƟng unit.
R5. A Balancing Authority may use SILOS for Primary Frequency Response. Frequency
set points and delay Ɵmes must be set as described in SecƟon 4 of the Reference
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Page 3 of 18
Document when used for Primary Frequency Response and provided to all
Obligated EnƟƟes for confirmaƟon and tracking via ICCP or other approved
method. The performance of the SILOS shall also be tracked based on the set
points and delay Ɵmes as described in SecƟon 4 of the Reference document
when used for Primary Frequency Response.
R6. The Reliability Coordinator shall determine the Primary Frequency Response
ObligaƟon hourly, updated in real Ɵme as necessary, as the Railbelt’s Largest
Single Instantaneous GeneraƟng ConƟngency, LSIGC. The Primary Frequency
Response ObligaƟon is allocated among the Balancing AuthoriƟes as stated in
Requirement R1.1
6.1. If an unscheduled unit is started with a larger maximum thermal raƟng
and output is larger than the previous LSIGC which causes the PFR
ObligaƟon to change, that Balancing Authority shall noƟfy the other
Railbelt Balancing AuthoriƟes of this change as soon as pracƟcable but
within 30 minutes of the unit’s start.
R7. AŌer each calendar month in which one or more Reportable Disturbances occur,
the Reliability Coordinator shall determine and make available to the Obligated
EnƟƟes the InterconnecƟon’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.
R8. Following any Reportable Disturbance that causes the InterconnecƟon’s six
rolling average Primary Frequency Response Performance to be less than the
average PFR ObligaƟon from the last six Reportable Disturbances, the Reliability
Coordinator shall direct any necessary acƟons, aŌer discussion with the
Obligated EnƟƟes, to improve Primary Frequency Response, which may include
but are not limited to the following: direcƟng adjustment of governor deadband
and/or droop seƫngs.
R9. Each Generator Owner shall operate each generaƟng unit that is connected to
the Railbelt with the governor in service (droop acƟve) and responsive to
frequency when the generaƟng unit is online and released for dispatch, unless
the Generator Owner has permission from the Reliability Coordinator for
operaƟng with the governor not in service (droop inacƟve) and the System
Operator has been noƟfied of the status change.
R10. A Balancing Authority shall noƟfy the other Railbelt Balancing AuthoriƟes and
the Reliability Coordinator as soon as pracƟcal but within 30 minutes of the
discovery of a status change (droop acƟve/inacƟve) of a governor and steps
7/15/2024 Rev 1
Page 4 of 18
taken by the Balancing Authority to maintain their Primary Frequency Response
ObligaƟon.
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 for each generaƟng unit, based on parƟcipaƟon in at least eight
Reportable Disturbances as described in SecƟon 5 of the Reference Document.
11.1 The Primary Frequency Response performance shall be the raƟo of the
Actual Primary Frequency Response to the Expected Primary Frequency
Response scaled by the deviaƟon of frequency in the arresƟng 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 generaƟng unit is the annually
updated values, as calculated in Requirement R3. If the available
headroom is less than the Expected PFR listed in the tables at the Ɵme of
the disturbance, the available headroom will be used in the performance
calculaƟon.
11.2 If a generaƟng unit has not parƟcipated 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 generaƟng unit has not parƟcipated in any Reportable Disturbances,
Primary Frequency Response performance may be determined from unit
load rejecƟon test data from a system disturbance that caused frequency
to deviate more than 0.3 Hz.
11.4. A generaƟng unit’s Primary Frequency Response performance during a
Reportable Disturbance may be excluded from the rolling average
calculaƟon by the Balancing Authority due to a legiƟmate operaƟng
condiƟon that prevented normal Primary Frequency Response
performance. Such exclusion must be approved by the Reliability
Coordinator. An example of a condiƟon that may support exclusion of a
generaƟng unit from Reportable Disturbances include:
Data telemetry failure. The Balancing Authority may request raw
data from the Generator Owner as a subsƟtute.
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 SecƟon 6 of the Reference Document. Each Balancing Authority is
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Page 5 of 18
responsible for documenƟng all sources of Primary Frequency Response and
must be shared with the other Balancing AuthoriƟes, via ICCP.
C. Measures
M1. The Reliability Coordinator shall require evidence that each Balancing Authority
was carrying its ConƟngency Reserve allocaƟon and Primary Frequency Response
reserve allocaƟon as required in Requirement R1.
M2. The Balancing Authority shall have evidence it reported each Reportable
Disturbance to the Compliance Monitor and that it made the informaƟon
available to the Obligated EnƟƟes within 14 calendar days aŌer the Disturbance
as required in Requirement R2.
M3. The Balancing Authority shall have evidence it calculated and reported the 12-
month average Primary Frequency Response performance of each generaƟng
unit annually to the Compliance Monitor with supporƟng documentaƟon as
required in Requirement 3. The Balancing Authority must provide evidence that
measurement devices used to measure the PFR of individual units meet the
requirements stated in Requirement R3.
M4. The Balancing Authority shall provide documentaƟon on how Energy Storage
Systems are set to respond to Reportable Disturbances and the parameters listed
in R4 must reflect the CoordinaƟon Study. The Balancing Authority shall also
report the performance of the Energy Storage System when used for Primary
Frequency Response.
M5. Balancing AuthoriƟes using SILOS for Primary Frequency Response shall report
how SILOS are programed with their delay Ɵmes and frequency set points, as
well as their performance if used for Primary Frequency Response. SILOS
informaƟon shall be provided via ICCP when used for Primary Frequency
Response.
M6. The Reliability Coordinator shall provide evidence that the Primary Frequency
Response ObligaƟon was determined hourly as required in Requirement 6. If
there are any changes impacƟng the Primary Frequency Response ObligaƟon, the
Balancing Authority shall provide evidence that they no Ɵfied the other Railbelt
Balancing AuthoriƟes.
M7. The Reliability Coordinator shall provide evidence that the rolling average of the
InterconnecƟon’s combined Primary Frequency Response Performance for the
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Page 6 of 18
last (6) six Reportable Disturbances was calculated and made available to the
Obligated EnƟƟes as required in Requirement 7.
M8. The Balancing Authority shall provide evidence that acƟons were taken to
improve the InterconnecƟon’s Primary Frequency Response if the
InterconnecƟon’s six-Reportable Disturbance rolling average combined Primary
Frequency Response performance was less than the average PFR ObligaƟon from
the last six Reportable Disturbances, as required in Requirement R8. The
Balancing Authority shall be required to increase their Primary Frequency
Response allocaƟon for the next calendar quarter by the amount they were
deficient in.
M9. Each Generator Owner shall have evidence that it no Ɵfied the System Operator
as soon as pracƟcal each Ɵme it discovered a governor status change (droop
acƟve/inacƟve) when the generaƟng unit was online and released for dispatch.
Evidence may include but not limited to operator logs, voice logs, or electronic
communicaƟons.
M10. The Balancing Authority shall have evidence that they noƟfied the other Railbelt
Balancing AuthoriƟes within 30 minutes of each discovery of a status change
(droop acƟve/inacƟve) of a governor. They shall also have evidence of steps
taken to maintain their Primary Frequency Response ObligaƟon.
M11. Each Generator Owner shall have evidence that each of its generaƟng units
achieved a minimum rolling average of Primary Frequency Response
performance of at least 75% of the Expected Primary Frequency Response as
described in Requirement R11. Each Generator Owner shall have documented
evidence of any Reportable Disturbances where the generaƟng unit performance
was excluded from the rolling average calculaƟon.
M12. The Balancing Authority shall have evidence that they dispatched Primary
Frequency Response reserves such that a single unit trip does not cause
Underfrequency Load Shed to occur. Each Balancing Authority is responsible for
documenƟng their sources of Primary Frequency Response and shared with the
other Balancing AuthoriƟes via ICCP.
D. Compliance
C1. Compliance Monitoring Process
C1.1. Compliance Enforcement Authority
Reliability OrganizaƟon
C1.2. Compliance Monitoring Period and Reset Time Frame
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Page 7 of 18
Compliance for the Primary Frequency Response Policy will be evaluated
for each reporƟng period, as determined by the Reliability OrganizaƟon.
C1.3. Data RetenƟon
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 quesƟon that has been
raised regarding the data, the data is to be saved beyond the normal
retenƟon period unƟl the quesƟon is formally resolved.
The BA shall retain all data for ConƟngency Reserve and Primary
Frequency Response Reserve calculaƟons and allocaƟon for
Requirement R1, Measure M1.
The BA shall retain a list of all Reportable Disturbance informaƟon
for Requirement R2, Measure M2.
The BA shall retain all annual PFR performance reports for
Requirement R3, Measure M3.
The BA shall retain all Energy Storage System parameters and
performance reports for Requirement R4, Measure R4
The BA shall retain all SILOS seƫngs informaƟon and performance
reports for Requirement R5, Measure M5.
The BA shall retain all PFR ObligaƟon calculaƟons, and related
methodology and criteria documents for Requirement R6,
Measure M6.
The Reliability Coordinator shall retain all data and calculaƟons
relaƟng to the InterconnecƟon’s combined Primary Frequency
Response, and all evidence of acƟons taken to increase the
InterconnecƟon’s Frequency Response for Requirements R7 and
R8, Measure M7 and M8.
The BA shall retain all evidence of Governor status changes and
communicaƟon of status change for Requirement R9 and R10,
Measure M9 and M10.
The BA shall retain all data and calculaƟons for each generaƟng
unit performance for Requirement R11, Measure M11.
The BA shall retain documents of all sources of PFR for
Requirement R12, Measure M12.
C1.4. AddiƟonal Compliance InformaƟon
None.
C1. Levels of BA Non-Compliance for Requirement R1, Measure M1
C1.1 Level 1 –– A Balancing Authority failed to provide evidence of carrying its
allocated ConƟngency Reserves.
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Level 2 – A Balancing Authority failed to carry its allocated ConƟngency
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 informaƟon
listed in Requirement R1 available to all Obligated EnƟƟes.
Level 2 – A Balancing Authority failed to report a Reportable Disturbance
and make the following informaƟon listed in Requirement R1 available to
all Obligated EnƟƟes.
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
generaƟng unit annually within two weeks of the date determined by the
Reliability Coordinator.
C4. Levels of InterconnecƟon Non-Compliance for Requirement R6, Measure M6
C.4.1 Level 1 – The Reliability Coordinator failed to determine the Primary
Frequency Response ObligaƟon and failed to make the methodology and
criteria for determinaƟon of the PFR ObligaƟon available to the Obligated
EnƟƟes.
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 acƟons
were taken to improve the InterconnecƟon’s Primary Frequency Response
if the InterconnecƟon’s six-Reportable Disturbance rolling average
Primary Frequency Response performance was less than the PFR
ObligaƟon.
C6. Levels of BA Non-Compliance for Requirement R9-R10, Measure R9-R10
C6.1 Level 1– A Balancing Authority failed to inform the other Railbelt
Balancing AuthoriƟes within 30 minutes of a governor status change.
Level 2– A Balancing Authority failed to inform the other Railbelt
Balancing AuthoriƟes 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 generaƟng 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.
E. DefiniƟons
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.
Contingency Reserves The provision of capacity deployed by the Balancing Authority
to meet the Disturbance Control Standard (DCS) and other
Railbelt and Reliability OrganizaƟon conƟngency requirements.
These reserves are activated throughout the arresting and
rebound periods and maintained through the recovery period.
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 unit with the largest expected output is the Largest Single
Instantaneous Generating Contingency (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 Grid, minus the effects of heat
recovery steam generators, 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 ObligaƟon, calculated in MW,
is the amount of Primary Frequency Response reserves that the
Railbelt must carry to avoid Underfrequency Load Shed and is
equal to the Largest Single Instantaneous GeneraƟon
ConƟngency, LSIGC.
Primary Frequency
Response Reserves
PFR
Reserves
A subset of ConƟngency Reserves, that is acƟvated during the
arrest period, which is equivalent to the Arrest Period Reserves.
Reliability Coordinator RC The enƟty that is the highest level of authority who is
responsible for the reliable operaƟon of the Bulk Electric
System, has the Wide Area view of the Bulk Electric System, and
has the operaƟng tools, processes and procedures, including
the authority to prevent or miƟgate emergency operaƟng
situaƟons in both next-day analysis and real-Ɵme operaƟons.
The Reliability Coordinator has the purview that is broad
enough to enable the calculaƟon of InterconnecƟon Reliability
OperaƟng Limits, which may be based on the operaƟng
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parameters of transmission systems beyond any Transmission
Operator’s vision.
Reportable
Disturbance
Reportable Disturbances are contingencies involving any
generating unit trips, transmission line trips, and distribution
level disturbances that result in frequency deviation > 0.3 Hz.
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AƩachment 1
Primary Frequency Response Reference Document
1. IntroducƟon
This Primary Frequency Response Reference Document provides calculaƟons used to determine
Primary Frequency Response ObligaƟons for each uƟlity as required in Requirement 1. This
document also provides a methodology for calculaƟng the Primary Frequency Response
performance of individual generaƟng units following Reportable Disturbances in accordance
with Requirements R3 and R11. The document also provides more informaƟon on SILOS seƫng
provided by the Railbelt ConƟngency Reserves Analysis study done by EPS and dispatching units
using the Primary Frequency Response method as described in the study.
2. ConƟngency Reserve and Primary Frequency Response Reserves AllocaƟon
Requirement 1
R1. The ConƟngency Reserve requirement, which are reserves acƟvated throughout
the arresƟng and rebound periods and maintained through the recovery period,
for the Railbelt shall not be less than an amount equivalent to 100 percent of the
System Reserve Basis as defined in AKRES-001-2. The ConƟngency Reserve
requirement is allocated among the Balancing AuthoriƟes by the load raƟo share
of a 3-year average of each uƟlity’s coincident peak load, as shown in SecƟon 2 of
the Reference Document.
1.1 The Primary Frequency Response Reserves, which are a subset of
ConƟngency Reserves and acƟvated during the arresƟng period, shall not
be less than an amount equivalent to 100 percent of the maximum
expected output of the Railbelt’s Largest Single Instantaneous GeneraƟng
ConƟngency, LSIGC as defined in this policy. Primary Frequency Response
reserves are allocated by the load raƟo share of a 3-year average of each
uƟlity’s coincident peak load, as shown in SecƟon 2 of the Reference
Document.
ConƟngency Reserve and Primary Frequency Response Reserves are allocated by the load raƟo
share based on a 3-year average of each uƟlity’s coincident peak load. The difference between
the calculaƟon of ConƟngency Reserves and PFR Reserves is the value of the Total System
Spinning Reserve ObligaƟon,𝑆𝑅𝑂்௧ , in the equaƟon below. For ConƟngency Reserves, this
value is determined by the System Reserve Basis and for PFR Reserves, this value is determined
by the LSIGC.
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𝑆𝑅𝑂௧௧௬ =𝑆𝑅𝑂்௧ × 𝑃𝐿௦
𝑃𝐿௧
where
𝑆𝑅𝑂௧௧௬ is the Individual UƟlity Spinning Reserve ObligaƟon
𝑆𝑅𝑂்௧ is the Total System Spinning Reserve ObligaƟon based on the System Reserve Basis
𝑃𝐿௦ is a uƟlity’s 3-year average system peak load
𝑃𝐿௧ is the Sum of each uƟlity’s 3-year average peak load, 𝑃𝐿௦
For the given example, the 𝑆𝑅𝑂்௧ , Total Spinning Reserve ObligaƟon, is 60 MW. The 3-year average of
each UƟlity’s Coincident Peak Load was taken from 2020, 2021, and 2022 SCADA data.
UƟlity 3 year avg of System Peak
Load
Symbol
CEA 351.3 MW CEA_Peak Load
MEA 146.4 MW MEA_Peak Load
GVEA 195.3 MW GVEA_Peak Load
HEA 78.1 MW HEA_Peak Load
To calculate CEA’s Spinning Reserve ObligaƟon:
𝑆𝑅𝑂ா =𝑆𝑅𝑂்௧ ∗ 𝐶𝐸𝐴 ௗ
𝐶𝐸𝐴 ௗ +𝑀𝐸𝐴 ௗ +𝐺𝑉𝐸𝐴 ௗ +𝐻𝐸𝐴 ௗ
𝑆𝑅𝑂ா = 60 𝑀𝑊∗351.3 𝑀𝑊
351.3 𝑀𝑊+ 146.4 𝑀𝑊+ 195.3 𝑀𝑊+ 78.1 𝑀𝑊
𝑆𝑅𝑂ா = 27 𝑀𝑊 CEA’s Spinning Reserve ObligaƟon
To calculate GVEA’s Spinning Reserve ObligaƟon:
𝑆𝑅𝑂ீா =𝑆𝑅𝑂்௧ ∗ 𝐺𝑉𝐸𝐴 ௗ
𝐶𝐸𝐴 ௗ +𝑀𝐸𝐴 ௗ +𝐺𝑉𝐸𝐴 ௗ +𝐻𝐸𝐴 ௗ
𝑆𝑅𝑂ீா = 60 𝑀𝑊∗195.3 𝑀𝑊
351.3 𝑀𝑊+ 146.4 𝑀𝑊+ 195.3 𝑀𝑊+ 78.1 𝑀𝑊
𝑆𝑅𝑂ீா = 15 𝑀𝑊 GVEA Spinning Reserve ObligaƟon
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For example, load data from 2020-2022 SCADA Data, the total of each uƟlity’s share of the Spinning
Reserve ObligaƟon is summarized below.
UƟlity 3 year avg of System Peak
Load
CEA 27.3 MW
MEA 11.4 MW
GVEA 15.2 MW
HEA 6.1 MW
3. Primary Frequency Response CalculaƟons of Individual GeneraƟng Unit
Requirement 3
R3. The Balancing Authority shall calculate the Primary Frequency Response of each
generaƟng unit in accordance with this standard and SecƟon 3 of the Primary
Frequency Response Reference document. This calculaƟon shall provide a 12-
month average of Primary Frequency Response performance. The measuring
device used to measure performance must provide recordings of individual units
which must be GPS Ɵme synchronized and have a sample rate of no more than
30 milliseconds. This calculaƟon shall be completed annually, per the Reliability
Coordinator’s assigned date, to update each generaƟng unit’s Expected Primary
Frequency Response values.
3.1. The calculaƟon results shall be submiƩed 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 generaƟng unit has not parƟcipated in a minimum of (8) eight
Reportable Disturbances in a 12-month period, its performance shall be
based on a rolling eight average response.
3.3. If a generaƟng unit has not parƟcipated in any Reportable Disturbances,
Primary Frequency Response performance may be determined from unit
load rejecƟon test data from a system disturbance that caused frequency
to deviate more than 0.3 Hz. If there is no data available for the
generaƟng unit, its Expected Primary Frequency Response shall be set to
0 MW.
3.4. If a Generator Owner needs to change their generaƟng unit’s Expected
Primary Frequency Response value earlier than the annual assigned date,
they shall supply the documentaƟon to support the change. Upon
approval from the Reliability Coordinator, the Primary Frequency
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Response of the generaƟng unit shall be updated and the Obligated
EnƟƟes shall be noƟfied on the change.
To determine the performance of each generaƟng unit 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 calculaƟon shall provide a 12-
month average of unit performance which will be used to update the Expected Primary
Frequency Response values. The PFR of a unit during a Reportable Disturbance using DFR or
Synchrophasor recordings is measured using the following formula:
𝑃𝐹𝑅௧ = (𝑀𝑊ౣ _ೠ −𝑀𝑊౦౨షౚ౩౪౫౨ౘౙ ) ∗
60.0 𝐻𝑧− 59.2 𝐻𝑧
𝑓ିௗ௦௧௨ −𝑓୫୧୬ _௨௧
Where
𝑀𝑊ౣ _ೠ is the unit’s output when unit frequency reaches its minimum.
𝑀𝑊౦౨షౚ౩౪౫౨ౘౙ is the unit’s output before the Disturbance occurs.
𝑃𝐹𝑅௧ is the primary frequency response of the unit during a Reportable Disturbance.
𝑓୫୧୬ _௨௧ is unit’s frequency when the unit reaches its minimum value.
Note that, . ு௭ିହଽ.ଶ ு௭
ೝషೞೠೝ್ೌ ିౣ _ೠ
corresponds to EPS’s method of scaling frequency when
calculaƟng PFR as it provides a safety margin during calculaƟons as described in SecƟon 12.1 of
EPS’s ConƟngency Reserves Analysis report. The report states “frequencies measured across the
system varied by as much as 0.2 Hz… to prevent any individual units from reaching 59.0 and
triggering UFLS, PFR values were scaled to 59.2 Hz.”
The pre-disturbance frequency corresponds to Point A in Figure 1. The frequency minimum or
frequency nadir corresponds to Point C in Figure 1. Primary Frequency Response of a unit is the
measured response between these two points.
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Figure 1: BPS Frequency Control Time Frames
[Source: NERC]
4. Shed In Lieu of Spin (SILOS)
Requirement 5
R5. A Balancing Authority may use SILOS for Primary Frequency Response. Frequency
set points and delay Ɵmes must be set as described in SecƟon 4 of the Reference
Document when used for Primary Frequency Response and provided to all
Obligated EnƟƟes for confirmaƟon and tracking via ICCP or other approved
method. The performance of the SILOS shall also be tracked based on the set
points and delay Ɵmes as described in SecƟon 4 of the Reference document
when used for Primary Frequency Response.
SILOS seƫngs at the Ɵme of the Railbelt ConƟngency Reserves Analysis study did not trigger
before Stage 1 Underfrequency Load Shed due to long delay Ɵmes. The following table,
provided by the study, shows five sets of alternate SILOS seƫngs with shorter delay Ɵmes. 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 Ɵmes are the
detecƟon and relay Ɵme, and not the breaker operaƟng Ɵme.
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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. Primary Frequency Response Performance CalculaƟon
Requirement 11
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 for each generaƟng unit, based on parƟcipaƟon in at least eight
Reportable Disturbances as described in SecƟon 5 of the Reference Document.
11.1 The Primary Frequency Response performance shall be the raƟo of the
Actual Primary Frequency Response to the Expected Primary Frequency
Response scaled by the deviaƟon of frequency in the arresƟng 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 generaƟng unit is the annually
updated values, as calculated in Requirement R3. If the available
headroom is less than the Expected PFR listed in the tables at the Ɵme of
the disturbance, the available headroom will be used in the performance
calculaƟon.
11.2 If a generaƟng unit has not parƟcipated 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 generaƟng unit has not parƟcipated in any Reportable Disturbances,
Primary Frequency Response performance may be determined from unit
load rejecƟon test data from a system disturbance that caused frequency
to deviate more than 0.3 Hz.
11.4. A generaƟng unit’s Primary Frequency Response performance during a
Reportable Disturbance may be excluded from the rolling average
calculaƟon by the Balancing Authority due to a legiƟmate operaƟng
condiƟon that prevented normal Primary Frequency Response
performance. Such exclusion must be approved by the Reliability
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Coordinator. An example of a condiƟon that may support exclusion of a
generaƟng unit from Reportable Disturbances include:
Data telemetry failure. The Balancing Authority may request raw
data from the Generator Owner as a subsƟtute.
This secƟon describes how to calculate the average Primary Frequency Response for each
generaƟng unit over a 12-month period with a minimum of (8) Reportable Disturbances. This is
to establish whether the unit is in compliance with its PFR obligaƟon. 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.
𝐴𝑣𝑔ௗ =[𝑃.𝑈. 𝑃𝐹𝑅௨௧ ]≥ 0.75
Where
𝑃.𝑈. 𝑃𝐹𝑅௨௧ =𝐴𝑐𝑡𝑢𝑎𝑙 𝑃𝐹𝑅௨௧
𝐸𝑥𝑝𝑒𝑐𝑡𝑒𝑑 𝑃𝐹𝑅௨௧ ∗ ∆𝑓
Where
𝐴𝑐𝑡𝑢𝑎𝑙 𝑃𝐹𝑅௧ = (𝑀𝑊ౣ _ೠ −𝑀𝑊౦౨షౚ౩౪౫౨ౘ ) is the measured response of the unit
during the arrest period.
𝐸𝑥𝑝𝑒𝑐𝑡𝑒𝑑 𝑃𝐹𝑅௧ is the expected PFR of the unit or the available headroom on the unit. The
expected PFR used in the calculaƟon is the lesser value of the two.
∆𝑓=𝑓ିௗ௦௧௨ −𝑓୫୧୬ _௨௧ is the frequency deviaƟon from right before the Disturbance
occurs to when the unit’s frequency reaches its minimum value.
If the unit would be considered operaƟng at full capacity, its expected PFR would be set to 0
MW and would sƟll be included to calculate the average performance unless exclusion is
approved by the Reliability Coordinator.
6. Primary Frequency Response Dispatch
Requirement 12
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 SecƟon 6 of the Reference Document. Each Balancing Authority is
responsible for documenƟng all sources of Primary Frequency Response and
must be shared with the other Balancing AuthoriƟes, via ICCP.
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The 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
arresƟng frequency and UFLS prevenƟon 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.
Tables 10, 11, and 12 of the EPS Railbelt ConƟngency Reserves Analysis Study summarizes the
simulated PFR values for each individual unit 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 assumpƟon that the unit has adequate headroom. If the headroom is less than the
Expected PFR of the unit, the lesser of the two values will be assigned to the unit. When
dispatching units, the sum each online unit’s PFR must be equal to or greater than the Largest
Single Instantaneous GeneraƟon ConƟngency. As required in Requirement 13, Primary
Frequency Response reserves shall be dispatched such that a single unit trip does not cause an
Underfrequency Load Shed event to occur.
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Primary Frequency Response Policy
A. Introduction
1. Title: Primary Frequency Response Policy
2. Number: TBA
3. Purpose:
3.1. This policy 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 Contingency Reserve requirement, which are reserves activated throughout
the arresting and rebound periods and maintained through the recovery period,
for the Railbelt shall not be less than an amount equivalent to 100 percent of the
System Reserve Basis as defined in AKRES-001-2. The Contingency Reserve
requirement is allocated among the Balancing Authorities by the load ratio share
of a 3-year average of each utility’s coincident peak load, as shown in Section 2 of
the Reference Document.
1.1 The Primary Frequency Response Reserves, which are a subset of
Contingency Reserves and activated during the arresting period, shall not
be less than an amount equivalent to 100 percent of the expected output
of the Railbelt’s Largest Single Instantaneous Generating Contingency,
LSIGC as defined in this policy. Primary Frequency Response reserves are
allocated by the load ratio share of a 3-year average of each utility’s
coincident peak load, as shown in Section 2 of the Reference Document.
R2. 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, frequency minimum/ maximum, magnitude of
disturbance, and cause of the disturbance.
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R3. The Balancing Authority shall calculate the Primary Frequency Response of each
generating unit in accordance with this standard and Section 3 of the Primary
Frequency Response Reference document. This calculation shall provide a 12-
month average of Primary Frequency Response performance. The measuring
device used to measure performance must provide recordings of individual units
which must be GPS time synchronized and have a sample rate of no more than
30 milliseconds. This calculation shall be completed annually, per the Reliability
Coordinator’s assigned date, to update each generating unit’s Expected Primary
Frequency Response values.
3.1. The calculation results shall be submitted 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 generating unit 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.
3.3. If a generating unit has not participated in any Reportable Disturbances,
Primary Frequency Response performance may be determined from unit
load rejection test data from a system disturbance that caused frequency
to deviate more than 0.3 Hz. If there is no data available for the
generating unit, its Expected Primary Frequency Response shall be set to
0 MW.
3.4. If a Generator Owner needs to change their generating unit’s Expected
Primary Frequency Response value earlier than the annual assigned date,
they shall supply the documentation to support the change. Upon
approval from the Reliability Coordinator, the Primary Frequency
Response of the generating unit shall be updated and the Obligated
Entities shall be notified on the change.
R4. The Balancing Authority may set their Energy Storage Systems to supply Primary
Frequency Response reserves up to the Energy Storage System’s full rating. The
following parameters must be provided to the Reliability Coordinator: droop,
ramp rates, and limits. Parameters provided must be defined by a Coordination
Study. Energy Storage Systems shall be considered a system that can provide
Primary Frequency Response. Performance of the Energy Storage System shall be
tracked as if it is a generating unit.
R5. 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
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Document when used for Primary Frequency Response and provided to all
Obligated Entities for confirmation and tracking via ICCP or other approved
method. The performance of the SILOS shall also be tracked based on the set
points and delay times as described in Section 4 of the Reference document
when used for Primary Frequency Response.
R6. The Reliability Coordinator shall determine the Primary Frequency Response
Obligation hourly, updated in real time as necessary, as the Railbelt’s Largest
Single Instantaneous Generating Contingency, LSIGC. The Primary Frequency
Response Obligation is allocated among the Balancing Authorities as stated in
Requirement R1.1
6.1. If an unscheduled unit is started with a larger maximum thermal rating
and output is larger than the previous LSIGC which causes the PFR
Obligation to change, that 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.
R7. 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.
R8. Following any Reportable Disturbance that causes the Interconnection’s six
rolling average Primary Frequency Response Performance to be less than the
average PFR Obligation from the last six Reportable Disturbances, the Reliability
Coordinator shall direct any necessary actions, after discussion with the
Obligated Entities, to improve Primary Frequency Response, which may include
but are not limited to the following: directing adjustment of governor deadband
and/or droop settings.
R9. Each Generator Owner shall operate each generating unit that is connected to
the Railbelt with the governor in service (droop active) and responsive to
frequency when the generating unit is online and released for dispatch, unless
the Generator Owner has permission from the Reliability Coordinator for
operating with the governor not in service (droop inactive) and the System
Operator has been notified of the status change.
R10. 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 (droop active/inactive) of a governor and steps
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taken by the Balancing Authority to maintain their Primary Frequency Response
Obligation.
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 for each generating unit, based on participation in at least eight
Reportable Disturbances as described in Section 5 of the Reference Document.
11.1 The Primary Frequency Response performance shall be the ratio of the
Actual Primary Frequency Response to the Expected Primary Frequency
Response scaled by the deviation of frequency in the arresting 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 generating unit is the annually
updated values, as calculated in Requirement R3. If the available
headroom is less than the Expected PFR listed in the tables at the time of
the disturbance, the available headroom will be used in the performance
calculation.
11.2 If a generating unit has not participated 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 generating unit has not participated in any Reportable Disturbances,
Primary Frequency Response performance may be determined from unit
load rejection test data from a system disturbance that caused frequency
to deviate more than 0.3 Hz.
11.4. A generating unit’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. Such exclusion must be approved by the Reliability
Coordinator. An example of a condition that may support exclusion of a
generating unit from Reportable Disturbances include:
Data telemetry failure. The Balancing Authority may request raw
data from the Generator Owner as a substitute.
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 Section 6 of the Reference Document. Each Balancing Authority is
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responsible for documenting all sources of Primary Frequency Response and
must be shared with the other Balancing Authorities, via ICCP.
C. Measures
M1. The Reliability Coordinator shall require evidence that each Balancing Authority
was carrying its Contingency Reserve allocation and Primary Frequency Response
reserve allocation as required in Requirement R1.
M2. 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 R2.
M3. The Balancing Authority shall have evidence it calculated and reported the 12-
month average Primary Frequency Response performance of each generating
unit annually to the Compliance Monitor with supporting documentation as
required in Requirement 3. The Balancing Authority must provide evidence that
measurement devices used to measure the PFR of individual units meet the
requirements stated in Requirement R3.
M4. The Balancing Authority shall provide documentation on how Energy Storage
Systems are set to respond to Reportable Disturbances and the parameters listed
in R4 must reflect the Coordination Study. The Balancing Authority shall also
report the performance of the Energy Storage System when used for Primary
Frequency Response.
M5. Balancing Authorities using SILOS for Primary Frequency Response shall report
how SILOS are programed with their delay times and frequency set points, as
well as their performance if used for Primary Frequency Response. SILOS
information shall be provided via ICCP when used for Primary Frequency
Response.
M6. The Reliability Coordinator shall provide evidence that the Primary Frequency
Response Obligation was determined hourly as required in Requirement 6. If
there are any changes impacting the Primary Frequency Response Obligation, the
Balancing Authority shall provide evidence that they notified the other Railbelt
Balancing Authorities.
M7. The Reliability Coordinator shall provide evidence that the rolling average of the
Interconnection’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 Entities as required in Requirement 7.
M8. The Balancing Authority shall provide evidence that actions were taken to
improve the Interconnection’s Primary Frequency Response if the
Interconnection’s six-Reportable Disturbance rolling average combined Primary
Frequency Response performance was less than the average PFR Obligation from
the last six Reportable Disturbances, as required in Requirement R8. The
Balancing Authority shall be required to increase their Primary Frequency
Response allocation for the next calendar quarter by the amount they were
deficient in.
M9. Each Generator Owner shall have evidence that it notified the System Operator
as soon as practical each time it discovered a governor status change (droop
active/inactive) when the generating unit was online and released for dispatch.
Evidence may include but not limited to operator logs, voice logs, or electronic
communications.
M10. The Balancing Authority shall have evidence that they notified the other Railbelt
Balancing Authorities within 30 minutes of each discovery of a status change
(droop active/inactive) of a governor. They shall also have evidence of steps
taken to maintain their Primary Frequency Response Obligation.
M11. Each Generator Owner shall have evidence that each of its generating units
achieved a minimum rolling average of Primary Frequency Response
performance of at least 75% of the Expected Primary Frequency Response as
described in Requirement R11. Each Generator Owner shall have documented
evidence of any Reportable Disturbances where the generating unit performance
was excluded from the rolling average calculation.
M12. The Balancing Authority shall have evidence that they dispatched Primary
Frequency Response reserves such that a single unit trip does not cause
Underfrequency Load Shed to occur. Each Balancing Authority is responsible for
documenting their sources of Primary Frequency Response and shared with the
other Balancing Authorities via ICCP.
D. Compliance
C1. Compliance Monitoring Process
C1.1. Compliance Enforcement Authority
Reliability Organization
C1.2. Compliance Monitoring Period and Reset Time Frame
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Compliance for the Primary Frequency Response Policy will be evaluated
for each reporting period, as determined by the Reliability Organization.
C1.3. Data Retention
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 question that has been
raised regarding the data, the data is to be saved beyond the normal
retention period until the question is formally resolved.
• The BA shall retain all data for Contingency Reserve and Primary
Frequency Response Reserve calculations and allocation for
Requirement R1, Measure M1.
• The BA shall retain a list of all Reportable Disturbance information
for Requirement R2, Measure M2.
• The BA shall retain all annual PFR performance reports for
Requirement R3, Measure M3.
• The BA shall retain all Energy Storage System parameters and
performance reports for Requirement R4, Measure R4
• The BA shall retain all SILOS settings information and performance
reports for Requirement R5, Measure M5.
• The BA shall retain all PFR Obligation calculations, and related
methodology and criteria documents for Requirement R6,
Measure M6.
• The Reliability Coordinator shall retain all data and calculations
relating to the Interconnection’s combined Primary Frequency
Response, and all evidence of actions taken to increase the
Interconnection’s Frequency Response for Requirements R7 and
R8, Measure M7 and M8.
• The BA shall retain all evidence of Governor status changes and
communication of status change for Requirement R9 and R10,
Measure M9 and M10.
• The BA shall retain all data and calculations for each generating
unit performance for Requirement R11, Measure M11.
• The BA shall retain documents of all sources of PFR for
Requirement R12, Measure M12.
C1.4. Additional Compliance Information
None.
C1. Levels of BA Non-Compliance for Requirement R1, Measure M1
C1.1 Level 1 –– A Balancing Authority failed to provide evidence of carrying its
allocated Contingency Reserves.
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Level 2 – A Balancing Authority failed to carry its allocated Contingency
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 information
listed in Requirement R1 available to all Obligated Entities.
Level 2 – A Balancing Authority failed to report a Reportable Disturbance
and make the following information listed in Requirement R1 available to
all Obligated Entities.
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
generating unit annually within two weeks of the date determined by the
Reliability Coordinator.
C4. Levels of Interconnection Non-Compliance for Requirement R6, Measure M6
C.4.1 Level 1 – The Reliability Coordinator failed to determine the Primary
Frequency Response Obligation and failed to make the methodology and
criteria for determination of the PFR Obligation available to the Obligated
Entities.
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 actions
were taken to improve the Interconnection’s Primary Frequency Response
if the Interconnection’s six-Reportable Disturbance rolling average
Primary Frequency Response performance was less than the PFR
Obligation.
C6. Levels of BA Non-Compliance for Requirement R9-R10, Measure R9-R10
C6.1 Level 1– A Balancing Authority failed to inform the other Railbelt
Balancing Authorities within 30 minutes of a governor status change.
Level 2– A Balancing Authority failed to inform the other Railbelt
Balancing Authorities 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 generating 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.
E. Definitions
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.
Contingency Reserves The provision of capacity deployed by the Balancing Authority
to meet the Disturbance Control Standard (DCS) and other
Railbelt and Reliability Organization contingency requirements.
These reserves are activated throughout the arresting and
rebound periods and maintained through the recovery period.
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 unit with the largest expected output is the Largest Single
Instantaneous Generating Contingency (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 Grid, minus the effects of heat
recovery steam generators, 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 Obligation, calculated in MW,
is the amount of Primary Frequency Response reserves that the
Railbelt must carry to avoid Underfrequency Load Shed and is
equal to the Largest Single Instantaneous Generation
Contingency, LSIGC.
Primary Frequency
Response Reserves
PFR
Reserves
A subset of Contingency Reserves, that is activated during the
arrest period, which is equivalent to the Arrest Period Reserves.
Reliability Coordinator RC The entity that is the highest level of authority who is
responsible for the reliable operation of the Bulk Electric
System, has the Wide Area view of the Bulk Electric System, and
has the operating tools, processes and procedures, including
the authority to prevent or mitigate emergency operating
situations in both next-day analysis and real-time operations.
The Reliability Coordinator has the purview that is broad
enough to enable the calculation of Interconnection Reliability
Operating Limits, which may be based on the operating
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parameters of transmission systems beyond any Transmission
Operator’s vision.
Reportable
Disturbance
Reportable Disturbances are contingencies involving any
generating unit trips, transmission line trips, and distribution
level disturbances that result in frequency deviation > 0.3 Hz.
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Attachment 1
Primary Frequency Response Reference Document
1. Introduction
This Primary Frequency Response Reference Document provides calculations used to determine
Primary Frequency Response Obligations for each utility as required in Requirement 1. This
document also provides a methodology for calculating the Primary Frequency Response
performance of individual generating units following Reportable Disturbances in accordance
with Requirements R3 and R11. The document also provides more information on SILOS setting
provided by the Railbelt Contingency Reserves Analysis study done by EPS and dispatching units
using the Primary Frequency Response method as described in the study.
2. Contingency Reserve and Primary Frequency Response Reserves Allocation
Requirement 1
R1. The Contingency Reserve requirement, which are reserves activated throughout
the arresting and rebound periods and maintained through the recovery period,
for the Railbelt shall not be less than an amount equivalent to 100 percent of the
System Reserve Basis as defined in AKRES-001-2. The Contingency Reserve
requirement is allocated among the Balancing Authorities by the load ratio share
of a 3-year average of each utility’s coincident peak load, as shown in Section 2 of
the Reference Document.
1.1 The Primary Frequency Response Reserves, which are a subset of
Contingency Reserves and activated during the arresting period, shall not
be less than an amount equivalent to 100 percent of the maximum
expected output of the Railbelt’s Largest Single Instantaneous Generating
Contingency, LSIGC as defined in this policy. Primary Frequency Response
reserves are allocated by the load ratio share of a 3-year average of each
utility’s coincident peak load, as shown in Section 2 of the Reference
Document.
Contingency Reserve and Primary Frequency Response Reserves are allocated by the load ratio
share based on a 3-year average of each utility’s coincident peak load. The difference between
the calculation of Contingency Reserves and PFR Reserves is the value of the Total System
Spinning Reserve Obligation,𝑆𝑆𝑆𝑆𝑆𝑆𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇, in the equation below. For Contingency Reserves, this
value is determined by the System Reserve Basis and for PFR Reserves, this value is determined
by the LSIGC.
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𝑆𝑆𝑆𝑆𝑆𝑆𝑈𝑈𝑇𝑇𝑈𝑈𝑇𝑇𝑈𝑈𝑇𝑇𝑈𝑈=𝑆𝑆𝑆𝑆𝑆𝑆𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇× 𝑃𝑃𝑃𝑃𝑠𝑠𝑃𝑃𝑃𝑃𝑇𝑇
where 𝑆𝑆𝑆𝑆𝑆𝑆𝑈𝑈𝑇𝑇𝑈𝑈𝑇𝑇𝑈𝑈𝑇𝑇𝑈𝑈 is the Individual Utility Spinning Reserve Obligation 𝑆𝑆𝑆𝑆𝑆𝑆𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇 is the Total System Spinning Reserve Obligation based on the System Reserve Basis 𝑃𝑃𝑃𝑃𝑠𝑠 is a utility’s 3-year average system peak load 𝑃𝑃𝑃𝑃𝑇𝑇 is the Sum of each utility’s 3-year average peak load, 𝑃𝑃𝑃𝑃𝑠𝑠
For the given example, the 𝑆𝑆𝑆𝑆𝑆𝑆𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇, Total Spinning Reserve Obligation, is 60 MW. The 3-year average of
each Utility’s Coincident Peak Load was taken from 2020, 2021, and 2022 SCADA data.
Utility 3 year avg of System Peak
Load
Symbol
CEA 351.3 MW CEA_Peak Load
MEA 146.4 MW MEA_Peak Load
GVEA 195.3 MW GVEA_Peak Load
HEA 78.1 MW HEA_Peak Load
To calculate CEA’s Spinning Reserve Obligation:
𝑆𝑆𝑆𝑆𝑆𝑆𝐶𝐶𝐶𝐶𝐶𝐶=𝑆𝑆𝑆𝑆𝑆𝑆𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇∗ 𝐶𝐶𝐶𝐶𝐶𝐶𝑃𝑃𝑃𝑃𝑇𝑇𝑃𝑃 𝐿𝐿𝑇𝑇𝑇𝑇𝐿𝐿𝐶𝐶𝐶𝐶𝐶𝐶𝑃𝑃𝑃𝑃𝑇𝑇𝑃𝑃 𝐿𝐿𝑇𝑇𝑇𝑇𝐿𝐿+𝑀𝑀𝐶𝐶𝐶𝐶𝑃𝑃𝑃𝑃𝑇𝑇𝑃𝑃 𝐿𝐿𝑇𝑇𝑇𝑇𝐿𝐿+𝐺𝐺𝐺𝐺𝐶𝐶𝐶𝐶𝑃𝑃𝑃𝑃𝑇𝑇𝑃𝑃 𝐿𝐿𝑇𝑇𝑇𝑇𝐿𝐿+𝐻𝐻𝐶𝐶𝐶𝐶𝑃𝑃𝑃𝑃𝑇𝑇𝑃𝑃 𝐿𝐿𝑇𝑇𝑇𝑇𝐿𝐿
𝑆𝑆𝑆𝑆𝑆𝑆𝐶𝐶𝐶𝐶𝐶𝐶=60 𝑀𝑀𝑀𝑀∗351.3 𝑀𝑀𝑀𝑀351.3 𝑀𝑀𝑀𝑀+146.4 𝑀𝑀𝑀𝑀+195.3 𝑀𝑀𝑀𝑀+78.1 𝑀𝑀𝑀𝑀
𝑆𝑆𝑆𝑆𝑆𝑆𝐶𝐶𝐶𝐶𝐶𝐶=27 𝑀𝑀𝑀𝑀 CEA’s Spinning Reserve Obligation
To calculate GVEA’s Spinning Reserve Obligation:
𝑆𝑆𝑆𝑆𝑆𝑆𝐺𝐺𝐺𝐺𝐶𝐶𝐶𝐶=𝑆𝑆𝑆𝑆𝑆𝑆𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇∗ 𝐺𝐺𝐺𝐺𝐶𝐶𝐶𝐶𝑃𝑃𝑃𝑃𝑇𝑇𝑃𝑃 𝐿𝐿𝑇𝑇𝑇𝑇𝐿𝐿𝐶𝐶𝐶𝐶𝐶𝐶𝑃𝑃𝑃𝑃𝑇𝑇𝑃𝑃 𝐿𝐿𝑇𝑇𝑇𝑇𝐿𝐿+𝑀𝑀𝐶𝐶𝐶𝐶𝑃𝑃𝑃𝑃𝑇𝑇𝑃𝑃 𝐿𝐿𝑇𝑇𝑇𝑇𝐿𝐿+𝐺𝐺𝐺𝐺𝐶𝐶𝐶𝐶𝑃𝑃𝑃𝑃𝑇𝑇𝑃𝑃 𝐿𝐿𝑇𝑇𝑇𝑇𝐿𝐿+𝐻𝐻𝐶𝐶𝐶𝐶𝑃𝑃𝑃𝑃𝑇𝑇𝑃𝑃 𝐿𝐿𝑇𝑇𝑇𝑇𝐿𝐿
𝑆𝑆𝑆𝑆𝑆𝑆𝐺𝐺𝐺𝐺𝐶𝐶𝐶𝐶=60 𝑀𝑀𝑀𝑀∗195.3 𝑀𝑀𝑀𝑀351.3 𝑀𝑀𝑀𝑀+146.4 𝑀𝑀𝑀𝑀+195.3 𝑀𝑀𝑀𝑀+78.1 𝑀𝑀𝑀𝑀
𝑆𝑆𝑆𝑆𝑆𝑆𝐺𝐺𝐺𝐺𝐶𝐶𝐶𝐶=15 𝑀𝑀𝑀𝑀 GVEA Spinning Reserve Obligation
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For example, load data from 2020-2022 SCADA Data, the total of each utility’s share of the Spinning
Reserve Obligation is summarized below.
Utility 3 year avg of System Peak
Load
CEA 27.3 MW
MEA 11.4 MW
GVEA 15.2 MW
HEA 6.1 MW
3. Primary Frequency Response Calculations of Individual Generating Unit
Requirement 3
R3. The Balancing Authority shall calculate the Primary Frequency Response of each
generating unit in accordance with this standard and Section 3 of the Primary
Frequency Response Reference document. This calculation shall provide a 12-
month average of Primary Frequency Response performance. The measuring
device used to measure performance must provide recordings of individual units
which must be GPS time synchronized and have a sample rate of no more than
30 milliseconds. This calculation shall be completed annually, per the Reliability
Coordinator’s assigned date, to update each generating unit’s Expected Primary
Frequency Response values.
3.1. The calculation results shall be submitted 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 generating unit 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.
3.3. If a generating unit has not participated in any Reportable Disturbances,
Primary Frequency Response performance may be determined from unit
load rejection test data from a system disturbance that caused frequency
to deviate more than 0.3 Hz. If there is no data available for the
generating unit, its Expected Primary Frequency Response shall be set to
0 MW.
3.4. If a Generator Owner needs to change their generating unit’s Expected
Primary Frequency Response value earlier than the annual assigned date,
they shall supply the documentation to support the change. Upon
approval from the Reliability Coordinator, the Primary Frequency
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Response of the generating unit shall be updated and the Obligated
Entities shall be notified on the change.
To determine the performance of each generating unit 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 calculation shall provide a 12-
month average of unit performance which will be used to update the Expected Primary
Frequency Response values. The PFR of a unit during a Reportable Disturbance using DFR or
Synchrophasor recordings is measured using the following formula:
𝑃𝑃𝑃𝑃𝑆𝑆𝑈𝑈𝑈𝑈𝑈𝑈𝑇𝑇=(𝑀𝑀𝑀𝑀𝑓𝑓min _𝑢𝑢𝑢𝑢𝑢𝑢𝑢𝑢−𝑀𝑀𝑀𝑀𝑓𝑓pre−disturbance )∗60.0 𝐻𝐻𝐻𝐻−59.2 𝐻𝐻𝐻𝐻𝑓𝑓𝑝𝑝𝑝𝑝𝑃𝑃−𝐿𝐿𝑈𝑈𝑠𝑠𝑇𝑇𝑑𝑑𝑝𝑝𝑑𝑑𝑇𝑇𝑈𝑈𝑑𝑑𝑃𝑃−𝑓𝑓min _𝑑𝑑𝑈𝑈𝑈𝑈𝑇𝑇
Where
𝑀𝑀𝑀𝑀𝑓𝑓min _𝑢𝑢𝑢𝑢𝑢𝑢𝑢𝑢 is the unit’s output when unit frequency reaches its minimum. 𝑀𝑀𝑀𝑀𝑓𝑓pre−disturbance is the unit’s output before the Disturbance occurs. 𝑃𝑃𝑃𝑃𝑆𝑆𝑈𝑈𝑈𝑈𝑈𝑈𝑇𝑇 is the primary frequency response of the unit during a Reportable Disturbance. 𝑓𝑓min _𝑑𝑑𝑈𝑈𝑈𝑈𝑇𝑇 is unit’s frequency when the unit reaches its minimum value.
Note that, 60.0 𝐻𝐻𝐻𝐻−59.2 𝐻𝐻𝐻𝐻𝑓𝑓𝑝𝑝𝑝𝑝𝑝𝑝−𝑑𝑑𝑢𝑢𝑑𝑑𝑢𝑢𝑢𝑢𝑝𝑝𝑑𝑑𝑑𝑑𝑢𝑢𝑑𝑑𝑝𝑝−𝑓𝑓min _𝑢𝑢𝑢𝑢𝑢𝑢𝑢𝑢 corresponds to EPS’s method of scaling frequency when
calculating PFR as it provides a safety margin during calculations as described in Section 12.1 of
EPS’s Contingency Reserves Analysis report. The report states “frequencies measured across the
system varied by as much as 0.2 Hz… to prevent any individual units from reaching 59.0 and
triggering UFLS, PFR values were scaled to 59.2 Hz.”
The pre-disturbance frequency corresponds to Point A in Figure 1. The frequency minimum or
frequency nadir corresponds to Point C in Figure 1. Primary Frequency Response of a unit is the
measured response between these two points.
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Figure 1: BPS Frequency Control Time Frames
[Source: NERC]
4. Shed In Lieu of Spin (SILOS)
Requirement 5
R5. 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 when used for Primary Frequency Response and provided to all
Obligated Entities for confirmation and tracking via ICCP or other approved
method. The performance of the SILOS shall also be tracked based on the set
points and delay times as described in Section 4 of the Reference document
when used for Primary Frequency Response.
SILOS settings at the time of the Railbelt Contingency Reserves Analysis study did not trigger
before Stage 1 Underfrequency Load Shed due to long delay times. The following table,
provided by the study, 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.
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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. Primary Frequency Response Performance Calculation
Requirement 11
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 for each generating unit, based on participation in at least eight
Reportable Disturbances as described in Section 5 of the Reference Document.
11.1 The Primary Frequency Response performance shall be the ratio of the
Actual Primary Frequency Response to the Expected Primary Frequency
Response scaled by the deviation of frequency in the arresting 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 generating unit is the annually
updated values, as calculated in Requirement R3. If the available
headroom is less than the Expected PFR listed in the tables at the time of
the disturbance, the available headroom will be used in the performance
calculation.
11.2 If a generating unit has not participated 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 generating unit has not participated in any Reportable Disturbances,
Primary Frequency Response performance may be determined from unit
load rejection test data from a system disturbance that caused frequency
to deviate more than 0.3 Hz.
11.4. A generating unit’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. Such exclusion must be approved by the Reliability
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Coordinator. An example of a condition that may support exclusion of a
generating unit from Reportable Disturbances include:
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 over a 12-month period with a minimum of (8) Reportable Disturbances. 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.
𝐶𝐶𝐴𝐴𝐴𝐴𝑃𝑃𝑃𝑃𝑝𝑝𝑈𝑈𝑇𝑇𝐿𝐿=[𝑃𝑃.𝑈𝑈. 𝑃𝑃𝑃𝑃𝑆𝑆𝑑𝑑𝑈𝑈𝑈𝑈𝑇𝑇]≥0.75
Where 𝑃𝑃.𝑈𝑈. 𝑃𝑃𝑃𝑃𝑆𝑆𝑑𝑑𝑈𝑈𝑈𝑈𝑇𝑇=𝐶𝐶𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴 𝑃𝑃𝑃𝑃𝑆𝑆𝑑𝑑𝑈𝑈𝑈𝑈𝑇𝑇𝐶𝐶𝐸𝐸𝐸𝐸𝐸𝐸𝐴𝐴𝐴𝐴𝐸𝐸𝐸𝐸 𝑃𝑃𝑃𝑃𝑆𝑆𝑑𝑑𝑈𝑈𝑈𝑈𝑇𝑇∗∆𝑓𝑓
Where 𝐶𝐶𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴 𝑃𝑃𝑃𝑃𝑆𝑆𝑈𝑈𝑈𝑈𝑈𝑈𝑇𝑇=(𝑀𝑀𝑀𝑀𝑓𝑓min _𝑢𝑢𝑢𝑢𝑢𝑢𝑢𝑢−𝑀𝑀𝑀𝑀𝑓𝑓pre−disturbance ) is the measured response of the unit
during the arrest period.
𝐶𝐶𝐸𝐸𝐸𝐸𝐸𝐸𝐴𝐴𝐴𝐴𝐸𝐸𝐸𝐸 𝑃𝑃𝑃𝑃𝑆𝑆𝑈𝑈𝑈𝑈𝑈𝑈𝑇𝑇 is the expected PFR of the unit or the available headroom on the unit. The
expected PFR used in the calculation is the lesser value of the two.
∆𝑓𝑓=𝑓𝑓𝑝𝑝𝑝𝑝𝑃𝑃−𝐿𝐿𝑈𝑈𝑠𝑠𝑇𝑇𝑑𝑑𝑝𝑝𝑑𝑑𝑇𝑇𝑈𝑈𝑑𝑑𝑃𝑃−𝑓𝑓min _𝑑𝑑𝑈𝑈𝑈𝑈𝑇𝑇 is the frequency deviation from right before the Disturbance
occurs to when the unit’s frequency reaches its minimum value.
If the unit would be considered operating at full capacity, its expected PFR would be set to 0
MW and would still be included to calculate the average performance unless exclusion is
approved by the Reliability Coordinator.
6. Primary Frequency Response Dispatch
Requirement 12
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 Section 6 of the Reference Document. Each Balancing Authority is
responsible for documenting all sources of Primary Frequency Response and
must be shared with the other Balancing Authorities, via ICCP.
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The 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
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.
Tables 10, 11, and 12 of the EPS Railbelt Contingency Reserves Analysis Study summarizes the
simulated PFR values for each individual unit 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 assumption that the unit has adequate headroom. If the headroom is less than the
Expected PFR of the unit, the lesser of the two values will be assigned to the unit. When
dispatching units, the sum each online unit ’s PFR must be equal to or greater than the Largest
Single Instantaneous Generation Contingency. As required in Requirement 13, Primary
Frequency Response reserves shall be dispatched such that a single unit trip does not cause an
Underfrequency Load Shed event to occur.
Intertie Management Committee Meeting
Operator Report
July 26, 2024
1. Alaska Intertie usage report
a. MWh usage – Measured at Douglas Substation, YTD
GVEA MEA Total
i. July – June FY24 270,743 26,792 297,535
ii. July – June FY23 228,005 38,665 266,670
iii. Delta - FY24 to FY23 18.74% (-30.71%) 11.57%
2. Alaska Intertie trips to report
No Alaska Intertie outages to report
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 Time MW
Tripped
Pre-Trip
Frequency
(Hz)
High /Low
Frequency
(Hz)
Frequency
Response
(MW/0.1Hz)
Southern Tie
Trip 5/12/2024 3:24:00 23.8 60.04 59.64 6.0
EGS Unit Trip 6/14/2024 14:15:38 16.9 60.02 59.77 6.9
Healy 2 Trip 6/30/2024 20:30:42 60.0(est) 60.02 59.06 6.2