HomeMy WebLinkAbout2024-09-27 IMC Agenda and docs
INTERTIE MANAGEMENT COMMITTEE (IMC)
REGULAR MEETING
September 27, 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 – July 26, 2024
7. NEW BUSINESS
8. OLD BUSINESS
9. COMMITTEE REPORTS
A. Budget Update Mark Ziesmer
B. IOC Committee Jon Sinclair
i. Primary Frequency Response Policy DRAFT
C. Operator Report Russell Thornton
10. MEMBERS COMMENTS
11. NEXT MEETING DATE – December 6, 2024
12. ADJOURNMENT
Intertie Management Committee Meeting
IOC Report
September 27, 2024
1. Intertie Operating Committee
a. The Douglas Substation control enclosure has been experiencing frost jacking resulting
in an elevation change of approximately 8” between the east and west ends. EPS has
evaluated the situation and recommends remedial action. Two possible options are
moving the enclosure and installing deeper piles or cutting the existing piles and
insulating around them to prevent future jacking. Cost estimates are around $200k.
The IOC recommends following up with EPS to determine which option is likely to be the
best long-term solution, and then moving forward. These costs were not in the 2025
budget. Once a direction is determined the IOC will provide a recommendation for
approval by the IMC.
b. Attached is the draft Primary Frequency Response (PFR) policy that is pending IMC
approval. Upon approval from the IMC, the IOC recommends moving the PFR to either
the RRC or the BPMC for final approval and incorporation into the standards. An
appropriate standard to attach the policy to would be AKBAL-002, under R2.
c. The Healy SVC has seen issues recently resulting in the SVC tripping offline. The 2025
budget includes funding to have GE, the OEM, investigate the issues and provide
recommendations to resolve it.
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.
e. The two UFLS events that occurred in August were discussed. Studies on unit controls
and the possibility of spinning for tie lines took up most of the discussion. Eash utility
was going to have internal discussions on spinning for tie lines and will report back to
the IOC in October.
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. The scope of the study includes looking at 230 kV upgrades from Bradley
to Healy.
b. Six proposals have been received for a system wide IBR study and these proposals are
currently under review. A contract is anticipated to be executed early in the fourth
quarter and preliminary results of the study are anticipated in Q2 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.
4. Engineering, Relay, and Reliability
a. The maintenance contract with GE for the northern SVC’s will be up in 2026.
AEA currently administers this contract and requested that the existing
maintenance contract be reviewed, and a recommendation given on whether or
not to extend the contract. The Engineering, Relay, and Reliability subcommittee
will be performing this review and providing the recommendation.
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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.
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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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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
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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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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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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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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.
Intertie Management Committee Meeting
Operator Report
September 27, 2024
1. Alaska Intertie usage report
a. MWh usage – Measured at Douglas Substation, YTD
GVEA MEA Total
i. July – August FY25 18,429 4,609 23,038
ii. July – August FY24 40,150 4,306 44,456
iii. Delta - FY24 to FY23 (-54.1%) 7.04% (-48.2%)
2. Alaska Intertie trips to report
There were two trips of the Alaska Intertie in the month of August. The August 12 trip of the
intertie resulted in significant oscillations in the resulting island that included Chugach and
MEA. The trip was due to a single line to ground fault on the Teeland to Douglas line. HEA was
already islanded at the time of the event due to Southern Tie being out of service for
construction. During the oscillation two generators tripped one at SPP and one at 2A. Between
these two trips the system went into second stage under frequency load shed. The Oscillation
continued until the SPP operator took SPP out of droop.
A study is in progress to identify the cause and the corrective action to be taken.
The second trip occurred on August 28th. The Alaska Intertie was carrying 14.7 MW when there
was a fault between Teeland and Douglas that cleared. Normal operation of protection was
observed. Maximum frequency of 60.3 Hz was seen south of Teeland.
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)
Bradley 2 Trip 7/24/2024 21.5 60.02 59.78 8.9
NPCC GT3 Trip 7/26/2024 21.0 60.003 59.75 8.2
AK Tie Trip(OSC) 8/12/2024 14.8 59.953 58.574 UFLS S2
SPP 10 Trip 8/12/2024 25.4 59.943 59.533 6.2
SPP 13 Trip 8/18/2024 29.9 60.043 59.6 6.8
Eklutna 1 Trip 8/26/2024 23.3 60.035 59.636 5.8
AK Tie Trip 8/28/2024 27.3 59.984 60.335 7.8
Eklutna 1 Trip 8/28/2024 23.2 60.006 59.759 9.4
Bradley 2 Trip 8/29/2024 28.0 60.046 59.562 5.8
S Tie Trip-UFLS 8/31/2024 59.5 60.012 58.914 UFLS S1
Bradley 2 Trip 9/5/2024 34.2 60.011 59.686 10.5
Bradley 2 Trip 9/8/2024 48.2 59.973 59.567 11.9
69kV Trip (GVEA) 9/9/2024 Unknown 59.994 58.517 Unknown
SOD SVC Event** 9/20/2024 61.729 59.972 59.414 11.1
** Bradley Event Triggered by SVC
When the SVC was brought online at 14:36:02 it started at -20 MVAR. Normal operation would
have the SVC come online at 0 MVAR with a voltage setpoint at the current bus voltage. The
operator of the SVC would then set the SVC for the desired bus voltage setpoint, and it would
ramp to its operating state. SCADA shows the operator starting the SVC but not commanding
the SVC setpoint.
When the SVC starts at -20 MVAR, Bradley Lake unit 1 was operating at 61.729 MW. According
to the Bradley Lake Tesla recorder, Bradley Unit 1 ramps to zero MW output for 7 seconds. This
was captured by the Bradley Tesla and the Chugach and HEA SCADA systems. After 7 seconds
the unit returns to its desired setpoint of 62 MW. At this time there is now known linkage that
could have caused this.
HEA and Chugach are working together to isolate the issues both with the SVC and Bradley Lake
operation.