HomeMy WebLinkAbout2024-02-12 IMC Agenda and docs INTERTIE MANAGEMENT COMMITTEE (IMC) SPECIAL MEETING REVISED AGENDA MONDAY, FEBRUARY 12, 2024 12:00 pm Teams Meeting
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Passcode: Q4uRA5 1. CALL TO ORDER
2. ROLL CALL FOR COMMITTEE MEMBERS
3. PUBLIC ROLL CALL
4. PUBLIC COMMENTS
5. AGENDA APPROVAL
6. EXECUTIVE SESSION
7. OLD BUSINESS
A. Resolution 24-01, In Support of Application For Grant – Preventing Outages and Enhancing the Resilience of the Electric Grid Formula Grant – Snowloading Project (with supporting documents) B. Resolution 24-02, In Support of Application For Grant – Preventing Outages and Enhancing the Resilience of Electric Grid Formula Grant – Synchrophasor Project (with supporting documents) 8. MEMBERS COMMENTS
9. NEXT MEETING DATE – March 22, 2024
10. ADJOURNMENT
Intertie Management Committee
Resolution No. 24-01
In Support of Application For Grant
Preventing Outages and Enhancing the Resilience of the Electric Grid Formula Grant
INTRODUCTION
The Alaska Intertie Management Committee is responsible for the management, operation, maintenance, and improvement of the Alaska Intertie Project (Alaska Intertie), subject to the non-delegable duties of the Alaska Energy Authority (AEA). The Alaska Intertie transmission line is part of the Alaska Railbelt transmission backbone. It connects the population centers of Interior Alaska within the GVEA service area with the populations centers of South Central Alaska and Kenai Peninsula.
PURPOSE
The purpose of Resolution 24-01 is to express support for the grant application to the Department of Energy for the Alaska Intertie Snow Load Resiliency Project (the “Project”), and to authorize Golden Valley Electric Association (“GVEA”) to serve as the Sub-Recipient on behalf of the IMC.
IMC RESOLUTION 24-01
WHEREAS, the Intertie Management Committee is responsible for the management, operation, maintenance, and improvement of the Alaska Intertie Project (“Alaska Intertie”), subject to the non-delegable duties of AEA.
WHEREAS, the Alaska Intertie has experienced the impacts of unbalanced snow loading along its 170-mile long, 345kV rated Intertie causing conductors to sag near or at ground level. Public and wildlife safety hazards and disruptive ground fault trip events with widespread load shedding and transmission system instability have resulted from the unbalanced snow loading.
WHEREAS, the current practice used by the IMC to address unbalanced snow loading is to dispatch personnel to patrol the line by snow mobile or helicopter whenever
more than two inches of snow is recorded in Talkeetna near the southern end of the Intertie or when a line fault and trip occurs.
WHEREAS, the IMC finds that the proposed Project scope will both harden and improve the southern 80 miles of the Alaska Intertie (Douglas Substation to Susitna River crossing) and minimize the intermittent and excessive conductor sag caused by unbalanced snow loading.
Page 1 of 3 IMC Resolution 24-01 – In Support of Application for Grant Preventing Outages And Enhancing the Resilience of Electric Grid Formula Grant
Page 2 of 3 IMC Resolution 24-01 – In Support of Application for Grant Preventing Outages And Enhancing the Resilience of Electric Grid Formula Grant
WHEREAS, the IMC finds that the Alaska Intertie hardening and resiliency Project will
increase reliability, and promote development and operation of new renewable
energy projects across the Alaska Railbelt and that the Project will address the
ongoing unbalanced snow loading, and benefit the Intertie by reducing outages and
operating costs, increasing the resiliency of the Intertie and benefit the entire Railbelt.
WHEREAS, attached as Exhibit 1 to this Resolution, and incorporated herein by this reference is the application for the Grant Preventing Outages and Enhancing the Resilience of the Electric Grid Formula Grants, pursuant to the Bipartisan Infrastructure Law – Section 40101(d).
NOW, THEREFORE BE IT RESOLVED THAT, the foregoing recitals and Exhibit are incorporated herein by this reference.
BE IT FURTHER RESOLVED, the IMC is in support of the application for the Project to be filed by GVEA.
BE IT FURTHER RESOLVED, so long as the final application is substantially similar to Exhibit 1, the Chair is authorized to execute any additional documents necessary to prepare a complete application for the Project and to the extent necessary as authorized by the Board of Directors for GVEA, Chugach Electric Association and Matanuska Electric Association.
DATED at Anchorage Alaska, this _____ day of February, 2024.
___________________________________________ Chair, Andrew Laughlin
Attest: ______________________________ Secretary, William Price
Page 3 of 3 IMC Resolution 24-01 – In Support of Application for Grant Preventing Outages And Enhancing the Resilience of Electric Grid Formula Grant
EXHIBIT 1
APPLICATION
Bipartisan Infrastructure Law – Section 40101(d) – PREVENTING
OUTAGES AND ENHANCING THE RESILIENCE OF THE ELECTRIC
GRID FORMULA GRANTS – APPLICATION FORM
Page 1 of 14
Application Instructions
Applications for the Preventing outages and enhancing the resilience of the electric grid formula grants
program will be accepted from January 2nd, 2024 to February 16th, 2024. To apply, please complete
the following application form in its entirety and enclose the required following supplemental supporting
documents. Use of additional space is permissible by attaching supplemental material.
a)Authorization Letter from the eligible entity electing to submit an application, signed
by an authorized representative of the entity
b)Project budget using DOE SF-424 Budget Justification Notebook
c)Eligible Entity Request Form (if applicable)
d)Environmental Questionnaire (NEPA)
e)Resilience Project Subaward Notification Form
Application Form
A.Sub-Recipient Information
Sub-Recipient Name:
Entity Type: An electric grid
operator
Other
If “other”, please describe:
An electric
storage operator
An electricity
generator
A transmission
owner or
operator; or a
State owner of
transmission or
generation assets
without a CPCN
Page 2 of 14
Any other
relevant entity, as
determined by
the Secretary (of
DOE)
Eligible Entity Point of
Contact:
Name:
Title:
Phone:
E-mail:
Address:
B.Project Information
Project Title:
Engineering Design/Permits/Site
Control Costs *: $
Construction Costs †: $
Administrative Expenses ‡: $
Other Miscellaneous Costs§: $
1/3 Eligible Entity Cost Including
In-Kind Match **: $
Total Federal 40101(d) Cost:
(This is your grant request) $
Description of Primary
Service Area:
(counties/cities of
eligible entity)
*Preliminary engineering shall not exceed 15% of overall construction costs and the project shall be constructed
within the desired 5-year period of performance. Provide a line-item level of detail for costs if available.
† Provide a line-item level of detail if available.
‡ Provide a line-item level of detail if available.
§Provide a line-item level of detail if available.
** Provide anticipated cash and in-kind match values if applicable.
Page 3 of 14
Eligible entities if a
joint application:
Proposed electric grid service provided:
(check all that apply)
Weatherization
technologies and
equipment
Fire-resistant
technologies and fire
prevention systems
Monitoring and control
technologies
Undergrounding of
electrical equipment
Utility pole management
Relocation of power
lines or the
reconductoring of power
lines with low-sag,
advanced conductors
Vegetation and fuel load
management
The use or construction
of “distributed energy
sources” (“DERs”) for
enhancing system
adaptive capacity during
disruptive events,
including:
•Microgrids; and
•Battery storage
subcomponents
Adaptive protection
technologies
Advanced modeling
technologies
Other:
Replacement of old
overhead conductors and
underground cables.
Hardening of power
lines, facilities,
substations, of other
systems; and
Page 4 of 14
C.Project Narrative
1.Project Description: Required but not scored
Page 5 of 14
Figure 2 – Location of Alaska Intertie In Central Alaska Transmission Network
Page 6 of 14
2. Population Impacted: 30% or up to 30 points
• Please provide a description of total population served by the proposed project (no
description = 0 points, less than 20,000 served = 3 points, each additional 10,000 served =
3 points with a maximum of 15 points possible).
• Please provide a description of how the proposed project will serve one or more census
tracts defined as a disadvantaged community (no description = 0 points, each census tract
is worth 3 points with a maximum of 15 points possible).
• Disadvantaged communities reporting tool
Page 7 of 14
• Risk Reduction/Resilience Effectiveness: 20% or up to 20 points
• Please describe how the project will reduce the current risk of disruptive events (an event
in which operations of the electric grid are disrupted, preventatively shut off, or cannot
operate safely due to capacity constraints, redundancy and/or equipment failure, etc. (not
at all = 0 points, minimally = up to 3 points, partially = up to 6 points, mostly = up to 9
points, entirely = up to 12 points, and exceeds = up to 15 points).
• A 5 point bonus will be applied to projects which improve or enhance the resilience of
transmission lines or assets of 69kV and above.
Page 8 of 14
3.Extreme Weather, Wildfire, or Natural Disaster Event Adaptation: 15% or up to 15 points
•Please described how the proposed project would mitigate the future risk of disruptive
events whereby operations or the electric grid are disrupted, preventatively shut off, or
cannot operate safely due to extreme weather, wildfire, or natural disaster. Criterion score
should be based on a qualitative assessment of whether the narrative includes details
regarding how the project will reduce future disruptive events caused by extreme weather,
wildfire, or natural disaster (qualitative assessment; not at all = 0 points, minimally = up
to 3 points, partially = up to 6 points, mostly = up to 9 points, entirely = up to 12 points,
and exceeds = up to 15 points).
Page 9 of 14
4. Data Sources: 5% or up to 5 points
•Please provide a description of where the project is documented in a data-driven planning
document and/or has been identified as a provider priority via a board priority/resolution
related to system resiliency, and supporting documentation is referenced and/or the
location of any supporting documentation is referenced and/or the location of any
supporting data or narratives is provided in a linked below (not included = 0 points,
included = 2 points).
•The application should reference which climate change model substantiates predictions to
the changes of future physical environments including impacts to the safety and reliability
of providing energy to utility customers (reference excluded = 0 points, reference
included = 3 points).
Page 10 of 14
5. Implementation Measures: 15% or up to 15 points
The application should include a detailed project schedule that includes design, permits, site control,
and construction timeframe breakouts.
•The application schedule should indicate whether the project will go to construction within
the desired 5-year period of performance. (Construction timeframe not addressed = 0 points,
construction is not proposed within the 5-year period of performance = 0 points, construction
is proposed within the 5-year period of performance = up to 2 points).
•The application schedule should include an appropriate level of detail and proposed
timeframes should be adequate and reasonable, including project staff experience and
availability of staff time during the proposed project period (details and timeframes are not
included = 0 points, schedule details and proposed timeframes are minimally addressed = up
to 3 points, schedule details and proposed timeframes are adequate and reasonable = up to 5
points).
•The application should include a reasonably specific and/or detailed explanation of the extent
to which an eligible entity plans to utilize project labor agreements, local hire agreements,
and/or has or will develop a plan to attract, train, and retain a local workforce including
minority/women owned businesses (explanation excluded = 0 points, specific/detailed
explanation included = up to 5 points).
IDTask ModeWBS Task Name Duration Start Finish Predecessors10Alaska Intertie Tranmission Lines Upgrades1077 daysMon 1/1/24Tue 2/15/2821Project Management66 daysMon 1/1/24Mon 4/1/2431.1Evaluate Electrical System66 daysMon 1/1/24Mon 4/1/2441.1.2Evaluate Intertie25 daysMon 1/1/24Fri 2/2/2451.1.3Grant Info to AEA0 daysFri 2/2/24Fri 2/2/2461.1.4Revise Grant for Submittal10 daysMon 2/5/24Fri 2/16/2471.1.5AEA Submit Application to US DOE for Review1 dayFri 3/1/24Fri 3/1/2481.1.6Project Approved for Funding by US DOE1 dayMon 4/1/24Mon 4/1/2491.1.7Finalize Grant Award Documents0 daysMon 4/1/24Mon 4/1/24102Design90 daysMon 4/1/24Fri 8/2/249112.1Design Transmission Lines Upgrades80 daysMon 4/1/24Fri 7/19/249122.1.0Onboard Project Manager10 daysMon 4/1/24Fri 4/12/249132.1.1Design Transmission Lines Upgrades30 daysMon 4/15/24Fri 5/24/2412142.1.2Prepare RFQ for Independent Line Review30 daysMon 4/15/24Fri 5/24/2413SS152.1.3Independent Line Review ‐ 3rd Party30 daysMon 5/27/24Fri 7/5/2413162.1.4Revise Transmission Line Upgrades10 daysMon 7/8/24Fri 7/19/2415172.2Environmental Impacts45 daysMon 4/15/24Fri 6/14/2412182.2.1Determine Environmental Impacts30 daysMon 4/15/24Fri 5/24/24192.2.2Evaluate Environmental Impacts5 daysMon 5/27/24Fri 5/31/2418202.2.3Determine Options for Environmental Impacts10 daysMon 6/3/24Fri 6/14/2419212.3Historical Impacts45 daysMon 4/15/24Fri 6/14/2412222.3.1Determine Historical Impacts30 daysMon 4/15/24Fri 5/24/24232.3.2Evaluate Historical Impacts5 daysMon 5/27/24Fri 5/31/2422242.3.3Determine Options for Historical Impacts10 daysMon 6/3/24Fri 6/14/2423252.4Cultural Impacts45 daysMon 4/15/24Fri 6/14/2412262.4.1Determine Cultural Impacts30 daysMon 4/15/24Fri 5/24/24272.4.2Evaluate Cultural Impacts5 daysMon 5/27/24Fri 5/31/2426282.4.3Determine Options for Cultural Impacts10 daysMon 6/3/24Fri 6/14/2427292.5Permitting80 daysMon 4/15/24Fri 8/2/2412302.5.1Determine Permitting Requirements30 daysMon 4/15/24Fri 5/24/24312.5.2Determine Permits Needed5 daysMon 5/27/24Fri 5/31/2430322.5.3Acquire Necessary Permits45 daysMon 6/3/24Fri 8/2/2431332.6Easements75 daysMon 4/15/24Fri 7/26/2412342.6.1Determine Easements Required30 daysMon 4/15/24Fri 5/24/24352.6.2Acquire Necessary Easements45 daysMon 5/27/24Fri 7/26/2434362.7Develop Drawings30 daysMon 5/27/24Fri 7/5/2413372.7.2Develop Construction Drawings30 daysMon 5/27/24Fri 7/5/24383Construction860 daysMon 7/8/24Fri 10/22/2737393.1Prepare Bid Documents10 daysMon 7/8/24Fri 7/19/24403.1.1Prepare Solicitation Documents5 daysMon 7/8/24Fri 7/12/24413.1.2Prepare Bid Drawings5 daysMon 7/8/24Fri 7/12/24423.1.3Prepare Construction Contract5 daysMon 7/15/24Fri 7/19/2440,41,37433.2Issue For Bid30 daysMon 7/22/24Fri 8/30/24443.2.1Issue Bid Notice1 dayMon 7/22/24Mon 7/22/2442453.2.2Address Request for Information (RFI)30 daysMon 7/22/24Fri 8/30/2444SS463.3Evaluate Bid Submittals2 daysMon 9/2/24Tue 9/3/2445473.3.1Review Submittals for Completeness1 dayMon 9/2/24Mon 9/2/2445483.3.2Review Submittals for Errors1 dayMon 9/2/24Mon 9/2/2445493.3.3Review Submittals for Omissions1 dayMon 9/2/24Mon 9/2/2445503.3.4Review Submittals for Deviations1 dayMon 9/2/24Mon 9/2/2445513.3.5Review Insurance Documents1 dayMon 9/2/24Mon 9/2/2445523.3.6Review Site Specific Safety Plan1 dayMon 9/2/24Mon 9/2/2445533.3.7Award Construction Contract1 dayTue 9/3/24Tue 9/3/2452543.4Construction Kick0ff5 daysWed 9/4/24Tue 9/10/2453553.4.1Hold Construction Kickoff Meeting1 dayWed 9/4/24Wed 9/4/24563.4.2Address Questions and Concerns5 daysWed 9/4/24Tue 9/10/2452,55SS573.4.3Review Contractor Plan1 dayWed 9/4/24Wed 9/4/24583.5Issue Notice to Proceed860 daysMon 7/8/24Fri 10/22/27593.5.1Issue Notice to Proceed/Construction Start1 dayThu 9/5/24Thu 9/5/2457603.5.2Order Materials180 daysMon 7/8/24Fri 3/14/2537613.5.3Contractor Modify Structures (Phase 1)120 daysMon 5/5/25Fri 10/17/2560623.5.4Contractor Repair Damaged Property (Phase 1)5 daysMon 10/20/25Fri 10/24/2561633.5.5Contractor Modify Structures (Phase 2)120 daysMon 5/4/26Fri 10/16/26643.5.6Contractor Repair Damaged Property (Phase 2)5 daysMon 10/19/26Fri 10/23/2663653.5.7Contractor Modify Structures (Phase 3)120 daysMon 5/3/27Fri 10/15/27663.5.8Contractor Repair Damaged Property (Phase 3)5 daysMon 10/18/27Fri 10/22/2765673.5.9Construction Complete0 daysFri 10/22/27Fri 10/22/2766684Inspection812 daysThu 9/5/24Fri 10/15/2755694.1Construction Inspectors812 daysThu 9/5/24Fri 10/15/2755704.1.1Onboard Inspectors4 daysThu 9/5/24Tue 9/10/2457714.1.2Inspectors on Site During Phase 1239 daysMon 5/5/25Thu 4/2/2661SS724.1.3Inspector to Record and Report Construction Activities Phase 1239 daysMon 5/5/25Thu 4/2/2661SS731.4.1.4Inspectors on Site During Phase 2120 daysMon 5/4/26Fri 10/16/2663SS741.4.1.5Inspector to Record and Report Construction Activities Phase 2120 daysMon 5/4/26Fri 10/16/2663SS751.4.1.6Inspectors on Site During Phase 3120 daysMon 5/3/27Fri 10/15/2765SS761.4.1.7Inspector to Record and Report Construction Activities Phase 3120 daysMon 5/3/27Fri 10/15/2765SS774.2Prepare Inspection Reporting Documents5 daysThu 9/5/24Wed 9/11/24784.2.1Prepare JHS5 daysThu 9/5/24Wed 9/11/24794.2.5Prepare Hardware Insprction Forms5 daysThu 9/5/24Wed 9/11/24804.2.7Prepare Contractor Equipment Inspection Forms5 daysThu 9/5/24Wed 9/11/24815Closeout82 daysMon 10/25/27Tue 2/15/2867825.1Review Documentation31 daysMon 10/25/27Mon 12/6/2767835.1.1Review Inspection Reports30 daysMon 10/25/27Fri 12/3/2767845.1.6Review Final Invoice for Approval1 dayMon 10/25/27Mon 10/25/2762855.1.7Complete Project True‐Up30 daysTue 10/26/27Mon 12/6/2784865.2Accept Documentation46 daysTue 12/7/27Tue 2/8/2885875.2.6Pay Final Contractor Invoice30 daysTue 12/7/27Mon 1/17/28885.2.7Prepare Lessons Learned Documentation10 daysTue 1/18/28Mon 1/31/2887895.2.8Hold Lessons Learned Meeting1 dayTue 2/1/28Tue 2/1/2888905.2.9Hold Project Completion Party1 dayTue 2/8/28Tue 2/8/2889FS+4 days915.3Close Project for Capitalization1 dayTue 2/15/28Tue 2/15/2890FS+4 days925.3.1Close Project for Capitalization1 dayTue 2/15/28Tue 2/15/2890FS+4 days2/24/17/229/39/510/2210/152/15Qtr 3Qtr 4Qtr 1Qtr 2Qtr 3Qtr 4Qtr 1Qtr 2Qtr 3Qtr 4Qtr 1Qtr 2Qtr 3Qtr 4Qtr 1Qtr 2Qtr 3Qtr 4Qtr 1Qtr 2Qtr 3023202420252026202720282024TaskSplitMilestoneSummaryProject SummaryInactive TaskInactive MilestoneInactive SummaryManual TaskDuration-onlyManual Summary RollupManual SummaryStart-onlyFinish-onlyExternal TasksExternal MilestoneDeadlineCriticalCritical SplitProgressManual ProgressPage 1Project: ESS Ghant Chart-JLFDate: Thu 2/1/24
Page 11 of 14
6. Community Engagement: 5% or up to 5 points
• The application should reference any utility public outreach plan for electronic and/or in-
person stakeholder and public outreach associated with identification and development of the
project (reference excluded = 0 points, reference included = up to 5 points).
Page 12 of 14
7. Leveraging Partnerships: 10% or up to 10 points
Please include letters of support from partner organizations (letters of support excluded = 0
points, reference included = 2 points).
Please include a description of how the applicant will provide matching funds (e.g., in-kind and/or
cash contributions) that are equal to 1/3 or more of the federal share of the project cost (non-
federal matching funds equal to 1/3 of federal share = 4 points, every 5% greater than 1/3 of
federal share = 1 additional point with a maximum of 8 points possible).
Page 13 of 14
LIST OF ADDITIONAL DOCUMENTATION SUBMITTED FOR CONSIDERATION
In the space below, please provide a list of additional information submitted for consideration.
The undersigned certifies that this application for a resilience grant is truthful and correct,
and that the applicant is in compliance with, and will continue to comply with, all federal
and state laws including existing credit and federal tax obligations and that they can
indeed commit the entity to these obligations.
Print Name
Signature
Title
Date
Page 14 of 14
Submission
Completed applications must be submitted by email or physical delivered to AEA by 4:00PM on
February 16th, 2024.
Applicants may either submit their applications by (1) attaching their application and supporting
documents to an email and sending it to the AEA grants coordinator, or (2) by having their applications
physically delivered to AEA.
Applicants choosing to submit their application via email are asked to address the email to
grants@akenergyauthority.org with the subject line of “IIJA 40101(D) Subaward Application”.
Applicants are asked to submit the application and applicable documentation in searchable PDF or other
word searchable electronic format. Applicants using this method are encouraged to use delivery receipt
and read receipt. It should be noted that AEA’s email system limits attachments to 40MB and will not
accept .zip files or executables.
Applicants choosing to submit their application via physical delivery method are asked to submit one (1)
electronic version on an electronic storage device (i.e., CD/DVD or thumb drive) in a searchable PDF or
other word searchable electronic format.
Additionally, if a hard copy of the completed application is submitted, AEA requires that the hard copy be
double-sided with minimal binding, including appendices that can be duplicated. Physical delivery of
either of the above must be in a sealed envelope(s) clearly labeled:
From: Applicant Return Address
To: Alaska Energy Authority
Renewable Energy Fund Grant Application
813 West Northern Lights Blvd
Anchorage, AK 99503
Any questions or concerns about filing an application should be directed to:
Grants Coordinator
Alaska Energy Authority
Direct Phone: (907) 771-3081
AEA Main Phone: (907) 771-3000
Email: grants@akenergyauthority.org
IDTask ModeWBS Task Name Duration Start Finish Predecessors10Alaska Intertie Tranmission Lines Upgrades1077 daysMon 1/1/24Tue 2/15/2821Project Management66 daysMon 1/1/24Mon 4/1/2431.1Evaluate Electrical System66 daysMon 1/1/24Mon 4/1/2441.1.2Evaluate Intertie25 daysMon 1/1/24Fri 2/2/2451.1.3Grant Info to AEA0 daysFri 2/2/24Fri 2/2/2461.1.4Revise Grant for Submittal10 daysMon 2/5/24Fri 2/16/2471.1.5AEA Submit Application to US DOE for Review1 dayFri 3/1/24Fri 3/1/2481.1.6Project Approved for Funding by US DOE1 dayMon 4/1/24Mon 4/1/2491.1.7Finalize Grant Award Documents0 daysMon 4/1/24Mon 4/1/24102Design90 daysMon 4/1/24Fri 8/2/249112.1Design Transmission Lines Upgrades80 daysMon 4/1/24Fri 7/19/249122.1.0Onboard Project Manager10 daysMon 4/1/24Fri 4/12/249132.1.1Design Transmission Lines Upgrades30 daysMon 4/15/24Fri 5/24/2412142.1.2Prepare RFQ for Independent Line Review30 daysMon 4/15/24Fri 5/24/2413SS152.1.3Independent Line Review ‐ 3rd Party30 daysMon 5/27/24Fri 7/5/2413162.1.4Revise Transmission Line Upgrades10 daysMon 7/8/24Fri 7/19/2415172.2Environmental Impacts45 daysMon 4/15/24Fri 6/14/2412182.2.1Determine Environmental Impacts30 daysMon 4/15/24Fri 5/24/24192.2.2Evaluate Environmental Impacts5 daysMon 5/27/24Fri 5/31/2418202.2.3Determine Options for Environmental Impacts10 daysMon 6/3/24Fri 6/14/2419212.3Historical Impacts45 daysMon 4/15/24Fri 6/14/2412222.3.1Determine Historical Impacts30 daysMon 4/15/24Fri 5/24/24232.3.2Evaluate Historical Impacts5 daysMon 5/27/24Fri 5/31/2422242.3.3Determine Options for Historical Impacts10 daysMon 6/3/24Fri 6/14/2423252.4Cultural Impacts45 daysMon 4/15/24Fri 6/14/2412262.4.1Determine Cultural Impacts30 daysMon 4/15/24Fri 5/24/24272.4.2Evaluate Cultural Impacts5 daysMon 5/27/24Fri 5/31/2426282.4.3Determine Options for Cultural Impacts10 daysMon 6/3/24Fri 6/14/2427292.5Permitting80 daysMon 4/15/24Fri 8/2/2412302.5.1Determine Permitting Requirements30 daysMon 4/15/24Fri 5/24/24312.5.2Determine Permits Needed5 daysMon 5/27/24Fri 5/31/2430322.5.3Acquire Necessary Permits45 daysMon 6/3/24Fri 8/2/2431332.6Easements75 daysMon 4/15/24Fri 7/26/2412342.6.1Determine Easements Required30 daysMon 4/15/24Fri 5/24/24352.6.2Acquire Necessary Easements45 daysMon 5/27/24Fri 7/26/2434362.7Develop Drawings30 daysMon 5/27/24Fri 7/5/2413372.7.2Develop Construction Drawings30 daysMon 5/27/24Fri 7/5/24383Construction860 daysMon 7/8/24Fri 10/22/2737393.1Prepare Bid Documents10 daysMon 7/8/24Fri 7/19/24403.1.1Prepare Solicitation Documents5 daysMon 7/8/24Fri 7/12/24413.1.2Prepare Bid Drawings5 daysMon 7/8/24Fri 7/12/24423.1.3Prepare Construction Contract5 daysMon 7/15/24Fri 7/19/2440,41,37433.2Issue For Bid30 daysMon 7/22/24Fri 8/30/24443.2.1Issue Bid Notice1 dayMon 7/22/24Mon 7/22/2442453.2.2Address Request for Information (RFI)30 daysMon 7/22/24Fri 8/30/2444SS463.3Evaluate Bid Submittals2 daysMon 9/2/24Tue 9/3/2445473.3.1Review Submittals for Completeness1 dayMon 9/2/24Mon 9/2/2445483.3.2Review Submittals for Errors1 dayMon 9/2/24Mon 9/2/2445493.3.3Review Submittals for Omissions1 dayMon 9/2/24Mon 9/2/2445503.3.4Review Submittals for Deviations1 dayMon 9/2/24Mon 9/2/2445513.3.5Review Insurance Documents1 dayMon 9/2/24Mon 9/2/2445523.3.6Review Site Specific Safety Plan1 dayMon 9/2/24Mon 9/2/2445533.3.7Award Construction Contract1 dayTue 9/3/24Tue 9/3/2452543.4Construction Kick0ff5 daysWed 9/4/24Tue 9/10/2453553.4.1Hold Construction Kickoff Meeting1 dayWed 9/4/24Wed 9/4/24563.4.2Address Questions and Concerns5 daysWed 9/4/24Tue 9/10/2452,55SS573.4.3Review Contractor Plan1 dayWed 9/4/24Wed 9/4/24583.5Issue Notice to Proceed860 daysMon 7/8/24Fri 10/22/27593.5.1Issue Notice to Proceed/Construction Start1 dayThu 9/5/24Thu 9/5/2457603.5.2Order Materials180 daysMon 7/8/24Fri 3/14/2537613.5.3Contractor Modify Structures (Phase 1)120 daysMon 5/5/25Fri 10/17/2560623.5.4Contractor Repair Damaged Property (Phase 1)5 daysMon 10/20/25Fri 10/24/2561633.5.5Contractor Modify Structures (Phase 2)120 daysMon 5/4/26Fri 10/16/26643.5.6Contractor Repair Damaged Property (Phase 2)5 daysMon 10/19/26Fri 10/23/2663653.5.7Contractor Modify Structures (Phase 3)120 daysMon 5/3/27Fri 10/15/27663.5.8Contractor Repair Damaged Property (Phase 3)5 daysMon 10/18/27Fri 10/22/2765673.5.9Construction Complete0 daysFri 10/22/27Fri 10/22/2766684Inspection812 daysThu 9/5/24Fri 10/15/2755694.1Construction Inspectors812 daysThu 9/5/24Fri 10/15/2755704.1.1Onboard Inspectors4 daysThu 9/5/24Tue 9/10/2457714.1.2Inspectors on Site During Phase 1239 daysMon 5/5/25Thu 4/2/2661SS724.1.3Inspector to Record and Report Construction Activities Phase 1239 daysMon 5/5/25Thu 4/2/2661SS731.4.1.4Inspectors on Site During Phase 2120 daysMon 5/4/26Fri 10/16/2663SS741.4.1.5Inspector to Record and Report Construction Activities Phase 2120 daysMon 5/4/26Fri 10/16/2663SS751.4.1.6Inspectors on Site During Phase 3120 daysMon 5/3/27Fri 10/15/2765SS761.4.1.7Inspector to Record and Report Construction Activities Phase 3120 daysMon 5/3/27Fri 10/15/2765SS774.2Prepare Inspection Reporting Documents5 daysThu 9/5/24Wed 9/11/24784.2.1Prepare JHS5 daysThu 9/5/24Wed 9/11/24794.2.5Prepare Hardware Insprction Forms5 daysThu 9/5/24Wed 9/11/24804.2.7Prepare Contractor Equipment Inspection Forms5 daysThu 9/5/24Wed 9/11/24815Closeout82 daysMon 10/25/27Tue 2/15/2867825.1Review Documentation31 daysMon 10/25/27Mon 12/6/2767835.1.1Review Inspection Reports30 daysMon 10/25/27Fri 12/3/2767845.1.6Review Final Invoice for Approval1 dayMon 10/25/27Mon 10/25/2762855.1.7Complete Project True‐Up30 daysTue 10/26/27Mon 12/6/2784865.2Accept Documentation46 daysTue 12/7/27Tue 2/8/2885875.2.6Pay Final Contractor Invoice30 daysTue 12/7/27Mon 1/17/28885.2.7Prepare Lessons Learned Documentation10 daysTue 1/18/28Mon 1/31/2887895.2.8Hold Lessons Learned Meeting1 dayTue 2/1/28Tue 2/1/2888905.2.9Hold Project Completion Party1 dayTue 2/8/28Tue 2/8/2889FS+4 days915.3Close Project for Capitalization1 dayTue 2/15/28Tue 2/15/2890FS+4 days925.3.1Close Project for Capitalization1 dayTue 2/15/28Tue 2/15/2890FS+4 days2/24/17/229/39/510/2210/152/15Qtr 3Qtr 4Qtr 1Qtr 2Qtr 3Qtr 4Qtr 1Qtr 2Qtr 3Qtr 4Qtr 1Qtr 2Qtr 3Qtr 4Qtr 1Qtr 2Qtr 3Qtr 4Qtr 1Qtr 2Qtr 3023202420252026202720282024TaskSplitMilestoneSummaryProject SummaryInactive TaskInactive MilestoneInactive SummaryManual TaskDuration-onlyManual Summary RollupManual SummaryStart-onlyFinish-onlyExternal TasksExternal MilestoneDeadlineCriticalCritical SplitProgressManual ProgressPage 1Project: ESS Ghant Chart-JLFDate: Thu 2/1/24
Alaska Intertie Snow Load Resilency Version:1By:KEPUpdated:2/7/2024Number Materials Total Number Burdened Total ProjectofUnit Cost Materials ofExtended Labor Rate Labor TotalUnits Description ($) ($) Personnel Hours Man-Hours ($/Man-Hr) ($) CostEngineering Design / Permits / Site Control Costs1 Project Management $0.00 $0.00 1 600 600 $150.00 $90,000.00 $90,000.001 Project Design + PLSCAD License $30,000.00 $30,000.00 1 160 160 $150.00 $24,000.00 $54,000.001 Consulting Engineering 1 120 120 $300.00 $36,000.00 $36,000.00326 Construction Management , Site Control + Drone $2,000.00 $2,000.00 1 3 978 $150.00 $146,700.00 $148,700.0030 Drafting - Construction Drawings $0.00 $0.00 2 8 480 $81.50 $39,120.00 $39,120.001 Environmental Engineer $0.00 $0.00 0 0 0 $88.50 $0.00 $0.001 Permiting $0.00 $0.00 0 $88.50 $0.00 $0.0050 Drafting - As-Built Drawings $0.00 $0.00 2 8 800 $81.50 $65,200.00 $65,200.00Sub-Total: $0.00 $32,000.00 899 3138 $401,020.00 $433,020.00GVEA Environmental1 Environmental Engineer $0.00 $0.00 0 0 0 $88.50 $0.00 $0.001 Permit Assistance $0.00 $0.00 0 $88.50 $0.00 $0.000 $0.00 $0.00 0 $88.50 $0.00 $0.00Sub-Total: $0.00 $0.00 0 0 $0.00 $0.00Contractor, Engineering:0 $0.00 $0.00 0 $0.00 $0.00 $0.000 $0.00 $0.00 0 $0.00 $0.00 $0.000 $0.00 $0.00 0 $0.00 $0.00 $0.00Sub-Total: $0.00 $0.00 0 0 $0.00 $0.00Construction Labor:Crews Crew Hrs.163Shorten I Strings 230kV$0.00 $0.00 1 4 652 $1,552.50 $1,012,230.00 $1,012,230.00163Change to 230kV Inverted V$0.00 $0.00 1 10 1630 $1,552.50 $2,530,575.00 $2,530,575.00326Reverse Shield Wire - Optional$0.00 $0.00 1 4 1304 $1,552.50 $2,024,460.00 $2,024,460.00326 Remove Yokes, Retension Guy Wires $0.00 $0.00 1 2 652 $1,552.50 $1,012,230.00 $1,012,230.00326 Flight Time, Setup, Takedown, Cleanup $0.00 $0.00 1 6 1956 $1,552.50 $3,036,690.00 $3,036,690.000 Resag Conductors $0.00 $0.00 0 0 0 $1,552.50 $0.00 $0.00Sub-Total: $0.00 $0.00 26 6194 $9,616,185.00 $9,616,185.00Sub-Total with 20% Contingency $0.00 $0.00 26 6194 $11,539,422.00 $11,539,422.00Construction Materials:163 Shorten I Strings 230kV, new insulators $2,547.00 $415,161.00$415,161.00163 Change to 230kV Inverted V, new insulators $6,036.00 $983,868.00$983,868.00326 Reverse Shield Wire $60.00 $19,560.00$19,560.00326 Remove Yokes, Retension Guy Wires $500.00 $163,000.00$163,000.000 New Insulators $0.00 $0.00$0.00Sub-Total: $1,581,589.00$1,581,589.00Sub-Total with 10% Contingency $1,739,747.90$1,739,747.90Administrative and Miscellaneous:1 Contracting and Legal Review $0.00 $0.00 1 40 40 $300.00 $12,000.00 $12,000.001 GVEA Purchasing - Parts Procurement 1 40 40 $100.00 $4,000.00 $4,000.001 Project Accounting $0.00 $0.00 1 200 200 $120.00 $24,000.00 $24,000.001 Miscellaneous Office Equipment $5,000.00 $5,000.00 1 200 200 $0.00 $0.00 $5,000.00Sub-Total: $0.00 $5,000.00 480 480 $40,000.00 $45,000.00Totals:$1,776,747.90 $11,980,442.00Subtotal $11,675,794 Contingency $2,081,396Project Total $13,757,190
Task No. Towers Towers per Mile Parts and Labor per Tower Cost per Mile Parts and Labor Sub-TotalEngineering Design, Permits, Project and Site Control 326 4.5$1,328 $5,413 $433,020Administrative / Accounting / Miscellaneous 326 4.5$138 $563 $45,000Construction - Shorten I Strings 230kV163 2.0$10,254 $20,892 $1,671,353Construction - Change to 230kV Inverted V163 2.0$25,270 $51,487 $4,118,945Construction - Reverse Shield Wire (Reliability Improvement)326 4.1$7,518 $30,636 $2,450,868Construction - Remove Yokes, Retension Guy Wires 326 4.1$4,276 $17,425 $1,393,976Construction - Flight Time, Setup, Takedown, Cleanup 326 4.1$11,178 $45,550 $3,644,028Totals$52,444 $141,329$11,306,322Totals With Shield Wire$59,962 $171,965$13,757,190Project Scope Grant Cash Match In-KindMinimum Modifications $8,479,741 $2,384,560 $442,020Minimum Modifications + Shield $10,317,892 $2,997,277 $442,020Cost to Mitigate Unbalanced Snow Loading for Southern Half of Alaska IntertieGrant and Matching Funds
Alaska IntertieResiliency Grant ApplicationMatch AllocationOption 1 Option 2 Option 3All Excludes ExcludesUtilityRevenue Admin Admin & CapacityGVEA 69.90% 81.95% 89.13%CEA 14.51% 6.69% 0.00%MEA 15.59% 11.36% 10.87%Total 100.00% 100.00% 100.00%
Alaska Intertie5‐Year Revenue SummaryUtility Revenue FY19 FY20 FY21 FY22 FY23 5‐Year Avg % ShareEnergy 1,576,213.44 1,193,673.00 1,557,628.24 1,764,752.52 1,167,385.60 1,451,930.56 Admin 83,750.04 182,250.00 220,000.00 145,833.28 255,333.33 177,433.33 69.90%Capacity 196,560.00 178,620.00 165,360.00 164,580.00 209,820.00 182,988.00 Total 1,856,523.48 1,554,543.00 1,942,988.24 2,075,165.80 1,632,538.93 1,812,351.89 Energy‐ ‐ ‐ ‐ ‐ ‐ Admin 83,750.04 182,250.00 60,000.00 ‐ ‐ 65,200.01 Included CEACapacity 62,496.00 55,688.22 51,217.00 ‐ ‐ 33,880.24 Total 146,246.04 237,938.22 111,217.00 ‐ ‐ 99,080.25 Energy‐ ‐ ‐ ‐ ‐ ‐ Admin 83,750.04 182,250.00 220,000.00 145,833.28 255,333.33 177,433.33 14.51%Capacity 82,656.00 75,840.22 70,065.00 119,426.00 150,102.00 99,617.84 Total 166,406.04 258,090.22 290,065.00 265,259.28 405,435.33 277,051.17 Energy 112,616.28 219,136.48 196,400.56 222,040.46 135,357.44 177,110.24 Admin 83,750.04 182,250.00 220,000.00 145,833.28 255,333.33 177,433.33 15.59%Capacity 51,408.00 47,091.56 44,078.00 45,365.00 59,718.00 49,532.11 Total 247,774.32 448,478.04 460,478.56 413,238.74 450,408.77 404,075.69 Energy 1,688,829.72 1,412,809.48 1,754,028.80 1,986,792.98 1,302,743.04 1,629,040.80 Admin 335,000.16 729,000.00 720,000.00 437,499.84 766,000.00 597,500.00 100.00%Capacity 393,120.00 357,240.00 330,720.00 329,371.00 419,640.00 366,018.20 Total 2,416,949.88 2,499,049.48 2,804,748.80 2,753,663.82 2,488,383.04 2,592,559.00 GVAMLPCEAMEATotal
Alaska Intertie5‐Year Revenue Summary ‐ Excludes Admin RevenueUtility Revenue FY19 FY20 FY21 FY22 FY23 5‐Year Avg % ShareEnergy 1,576,213.44 1,193,673.00 1,557,628.24 1,764,752.52 1,167,385.60 1,451,930.56 Admin‐ ‐ ‐ ‐ ‐ ‐ 81.95%Capacity 196,560.00 178,620.00 165,360.00 164,580.00 209,820.00 182,988.00 Total 1,772,773.44 1,372,293.00 1,722,988.24 1,929,332.52 1,377,205.60 1,634,918.56 Energy‐ ‐ ‐ ‐ ‐ ‐ Admin‐ ‐ ‐ ‐ ‐ ‐ Included CEACapacity 62,496.00 55,688.22 51,217.00 ‐ ‐ 33,880.24 Total 62,496.00 55,688.22 51,217.00 ‐ ‐ 33,880.24 Energy‐ ‐ ‐ ‐ ‐ ‐ Admin‐ ‐ ‐ ‐ ‐ ‐ 6.69%Capacity 82,656.00 75,840.22 70,065.00 119,426.00 150,102.00 99,617.84 Total 82,656.00 75,840.22 70,065.00 119,426.00 150,102.00 99,617.84 Energy 112,616.28 219,136.48 196,400.56 222,040.46 135,357.44 177,110.24 Admin‐ ‐ ‐ ‐ ‐ ‐ 11.36%Capacity 51,408.00 47,091.56 44,078.00 45,365.00 59,718.00 49,532.11 Total 164,024.28 266,228.04 240,478.56 267,405.46 195,075.44 226,642.36 Energy 1,688,829.72 1,412,809.48 1,754,028.80 1,986,792.98 1,302,743.04 1,629,040.80 Admin‐ ‐ ‐ ‐ ‐ ‐ 100.00%Capacity 393,120.00 357,240.00 330,720.00 329,371.00 419,640.00 366,018.20 Total 2,081,949.72 1,770,049.48 2,084,748.80 2,316,163.98 1,722,383.04 1,995,059.00 GVAMLPCEAMEATotal
Alaska Intertie5‐Year Revenue Summary ‐ Excludes Admin & Capacity RevenueUtility Revenue FY19 FY20 FY21 FY22 FY23 5‐Year Avg % ShareEnergy 1,576,213.44 1,193,673.00 1,557,628.24 1,764,752.52 1,167,385.60 1,451,930.56 Admin‐ ‐ ‐ ‐ ‐ ‐ 89.13%Capacity‐ ‐ ‐ ‐ ‐ ‐ Total 1,576,213.44 1,193,673.00 1,557,628.24 1,764,752.52 1,167,385.60 1,451,930.56 Energy‐ ‐ ‐ ‐ ‐ ‐ Admin‐ ‐ ‐ ‐ ‐ ‐ Included CEACapacity‐ ‐ ‐ ‐ ‐ ‐ Total‐ ‐ ‐ ‐ ‐ ‐ Energy‐ ‐ ‐ ‐ ‐ ‐ Admin‐ ‐ ‐ ‐ ‐ ‐ 0.00%Capacity‐ ‐ ‐ ‐ ‐ ‐ Total‐ ‐ ‐ ‐ ‐ ‐ Energy 112,616.28 219,136.48 196,400.56 222,040.46 135,357.44 177,110.24 Admin‐ ‐ ‐ ‐ ‐ ‐ 10.87%Capacity‐ ‐ ‐ ‐ ‐ ‐ Total 112,616.28 219,136.48 196,400.56 222,040.46 135,357.44 177,110.24 Energy 1,688,829.72 1,412,809.48 1,754,028.80 1,986,792.98 1,302,743.04 1,629,040.80 Admin‐ ‐ ‐ ‐ ‐ ‐ 100.00%Capacity‐ ‐ ‐ ‐ ‐ ‐ Total 1,688,829.72 1,412,809.48 1,754,028.80 1,986,792.98 1,302,743.04 1,629,040.80 GVAMLPCEAMEATotal
ALASKA INTERTIE REVENUE VARIANCE REPORT FY23
MWH ACTUAL USAGE Jul‐22 Aug‐22 Sep‐22 Oct‐22 Nov‐22 Dec‐22 Jan‐23 Feb‐23 Mar‐23 Apr‐23 May‐23 Jun‐23 TOTAL
MWH MWH MWH MWH MWH MWH MWH MWH MWH MWH MWH MWH MWH
GVEA 10,865 19,648 21,418 35,865 16,159 16,826 13,942 36,444 20,752 13,294 15,603 7,189 228,005
CURRENT VARIANCE (21,436) (17,093) (16,178) (4,874) (19,624) (18,935) (21,601) 6,047 (12,542) (25,243) (17,574) (31,463) (200,516)
YTD VARIANCE (21,436) (38,529) (54,707) (59,581) (79,205) (98,140) (119,741) (113,694) (126,236) (151,479) (169,053) (200,516)
MLP ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
CURRENT VARIANCE ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
YTD VARIANCE ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
CEA ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
CURRENT VARIANCE ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
YTD VARIANCE ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
MEA 2,252 2,239 2,080 2,205 2,213 2,535 2,363 2,162 2,355 2,132 2,247 1,654 26,437
CURRENT VARIANCE 334 271 129 202 (56) 80 224 144 184 226 380 (157) 1,961
YTD VARIANCE 334 605 734 936 880 960 1,184 1,328 1,512 1,738 2,118 1,961
TOTAL 13,117 21,887 23,498 38,070 18,372 19,361 16,305 38,606 23,107 15,426 17,850 8,843 254,442
CURRENT VARIANCE (21,102) (16,822) (16,049) (4,672) (19,680) (18,855) (21,377) 6,191 (12,358) (25,017) (17,194) (31,620) (198,555)
YTD VARIANCE (21,102) (37,924) (53,973) (58,645) (78,325) (97,180) (118,557) (112,366) (124,724) (149,741) (166,935) (198,555)
ACTUAL REVENUES
Jul‐22 Aug‐22 Sep‐22 Oct‐22 Nov‐22 Dec‐22 Jan‐23 Feb‐23 Mar‐23 Apr‐23 May‐23 Jun‐23 Jun‐23
Rate per MWH 5.12$ 5.12$ 5.12$ 5.12$ 5.12$ 5.12$ 5.12$ 5.12$ 5.12$ 5.12$ 5.12$ 5.12$
GVEA Energy Charges 55,629$ 100,598$ 109,660$ 183,629$ 82,734$ 86,149$ 71,383$ 186,593$ 106,250$ 68,065$ 79,887$ 36,808$ 1,167,386
GVEA Administrative Charges 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 255,333
GVEA Cost of Improvements ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
GVEA Capacity Charges 209,820$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ 209,820
YTD Actuals 286,727$ 408,602$ 539,540$ 744,447$ 848,458$ 955,885$ 1,048,546$ 1,256,417$ 1,383,945$ 1,473,288$ 1,574,453$ 1,632,539$ 1,632,539
YTD Variance (109,752)$ (197,268)$ (280,100)$ (305,055)$ (405,530)$ (502,477)$ (613,074)$ (582,113)$ (646,328)$ (775,572)$ (865,551)$ (1,026,642)$
CEA Energy Charges ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
CEA Administrative Charges 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 255,333
CEA Cost of Improvements ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
CEA Capacity Charges 150,102$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ 150,102
YTD Actuals 171,380$ 192,658$ 213,935$ 235,213$ 256,491$ 277,769$ 299,046$ 320,324$ 341,602$ 362,880$ 384,158$ 405,435$ 405,435
YTD Variance ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$
MEA Energy Charges 11,530$ 11,464$ 10,650$ 11,290$ 11,331$ 12,979$ 12,099$ 11,069$ 12,058$ 10,916$ 11,505$ 8,468$ 135,357
MEA Administrative Charges 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 255,333
MEA Cost of Improvements ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
MEA Capacity Charges 59,718$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ 59,718
YTD Actuals 92,526$ 125,267$ 157,195$ 189,762$ 222,371$ 256,628$ 290,004$ 322,351$ 355,686$ 387,880$ 420,663$ 450,409$ 450,409
YTD Variance 1,710$ 3,098$ 3,758$ 4,792$ 4,506$ 4,915$ 6,062$ 6,799$ 7,741$ 8,899$ 10,844$ 10,040$
TOTAL ENERGY CHARGES 67,159$ 112,061$ 120,310$ 194,918$ 94,065$ 99,128$ 83,482$ 197,663$ 118,308$ 78,981$ 91,392$ 45,276$ 1,302,743
TOTAL ADMINISTRATIVE CHARGES 63,833$ 63,833$ 63,833$ 63,833$ 63,833$ 63,833$ 63,833$ 63,833$ 63,833$ 63,833$ 63,833$ 63,833$ 766,000
TOTAL COST OF IMPROVEMENTS ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
TOTAL CAPACITY CHARGES 419,640$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ 419,640
YTD TOTAL REVENUES 550,632$ 726,527$ 910,670$ 1,169,422$ 1,327,320$ 1,490,282$ 1,637,597$ 1,899,093$ 2,081,234$ 2,224,048$ 2,379,274$ 2,488,383$ 2,488,383
YTD TOTAL VARIANCE (108,042)$ (194,171)$ (276,342)$ (300,262)$ (401,024)$ (497,562)$ (607,012)$ (575,314)$ (638,587)$ (766,674)$ (854,707)$ (1,016,602)$
MWH PROJECTIONS Jul‐22 Aug‐22 Sep‐22 Oct‐22 Nov‐22 Dec‐22 Jan‐23 Feb‐23 Mar‐23 Apr‐23 May‐23 Jun‐23 Jun‐23
MWH MWH MWH MWH MWH MWH MWH MWH MWH MWH MWH MWH MWH
GVEA 32,301 36,741 37,596 40,739 35,783 35,761 35,543 30,397 33,294 38,537 33,177 38,652 428,521
YTD 32,301 69,042 106,638 147,377 183,160 218,921 254,464 284,861 318,155 356,692 389,869 428,521
MLP ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
YTD ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
CEA ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
YTD ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
MEA 1,918 1,968 1,951 2,003 2,269 2,455 2,139 2,018 2,171 1,906 1,867 1,811 24,476
YTD 1,918 3,886 5,837 7,840 10,109 12,564 14,703 16,721 18,892 20,798 22,665 24,476
TOTAL 34,219 38,709 39,547 42,742 38,052 38,216 37,682 32,415 35,465 40,443 35,044 40,463 452,997
YTD 34,219 72,928 112,475 155,217 193,269 231,485 269,167 301,582 337,047 377,490 412,534 452,997
BUDGETED REVENUES
Jul‐22 Jul‐22 Aug‐22 Sep‐22 Oct‐22 Nov‐22 Dec‐22 Jan‐23 Feb‐23 Mar‐23 Apr‐23 May‐23 Jun‐23
Budgeted Rate per MWH 5.12$ 5.12$ 5.12$ 5.12$ 5.12$ 5.12$ 5.12$ 5.12$ 5.12$ 5.12$ 5.12$ 5.12$
GVEA Energy Charges 165,381$ 188,114$ 192,492$ 208,584$ 183,209$ 183,096$ 181,980$ 155,633$ 170,465$ 197,309$ 169,866$ 197,898$ 2,194,028
GVEA Administrative Charges 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 255,333
GVEA Cost of Improvements ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
GVEA Capacity Charges 209,820$ 209,820
YTD 396,479$ 605,871$ 819,640$ 1,049,501$ 1,253,988$ 1,458,362$ 1,661,620$ 1,838,531$ 2,030,274$ 2,248,861$ 2,440,005$ 2,659,181$ 2,659,181
CEA Energy Charges ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
CEA Administrative Charges 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 255,333
CEA Cost of Improvements ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
CEA Capacity Charges 150,102$ 150,102
YTD 171,380$ 192,658$ 213,935$ 235,213$ 256,491$ 277,769$ 299,046$ 320,324$ 341,602$ 362,880$ 384,158$ 405,435$ 405,435
MEA Energy Charges 9,820$ 10,076$ 9,989$ 10,255$ 11,617$ 12,570$ 10,952$ 10,332$ 11,116$ 9,759$ 9,559$ 9,272$ 125,317
MEA Administrative Charges 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 21,278$ 255,333
MEA Cost of Improvements ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
MEA Capacity Charges 59,718$ 59,718
YTD 90,816$ 122,170$ 153,437$ 184,970$ 217,865$ 251,712$ 283,942$ 315,552$ 347,945$ 378,982$ 409,818$ 440,368$ 440,368
TOTAL ENERGY CHARGES 175,201$ 198,190$ 202,481$ 218,839$ 194,826$ 195,666$ 192,932$ 165,965$ 181,581$ 207,068$ 179,425$ 207,171$ 2,319,345
TOTAL ADMINISTRATIVE CHARGES 63,833$ 63,833$ 63,833$ 63,833$ 63,833$ 63,833$ 63,833$ 63,833$ 63,833$ 63,833$ 63,833$ 63,833$ 766,000
TOTAL COST OF IMPROVEMENTS ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
TOTAL CAPACITY CHARGES 419,640$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ 419,640
YTD 658,675$ 920,698$ 1,187,012$ 1,469,684$ 1,728,344$ 1,987,843$ 2,244,608$ 2,474,407$ 2,719,821$ 2,990,722$ 3,233,981$ 3,504,985$ 3,504,985
(1,016,602)
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ALASKA INTERTIE REVENUE VARIANCE REPORT FY22
MWH ACTUAL USAGE Jul‐21 Aug‐21 Sep‐21 Oct‐21 Nov‐21 Dec‐21 Jan‐22 Feb‐22 Mar‐22 Apr‐22 May‐22 Jun‐22 TOTAL
MWH MWH MWH MWH MWH MWH MWH MWH MWH MWH MWH MWH MWH
GVEA 4,815 12,415 3,283 13,008 8,519 6,423 20,852 36,168 30,015 24,644 27,507 11,533 199,182
CURRENT VARIANCE (6,235) 3,442 (10,466) (15,733) (1,652) (2,539) 8,809 27,655 24,398 12,196 18,260 (20,741) 37,394
YTD VARIANCE (6,235) (2,793) (13,259) (28,992) (30,644) (33,183) (24,374) 3,281 27,679 39,875 58,135 37,394
MLP ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
CURRENT VARIANCE ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
YTD VARIANCE ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
CEA ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
CURRENT VARIANCE ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
YTD VARIANCE ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
MEA 1,863 1,905 1,870 1,959 2,300 2,343 2,350 1,996 2,207 2,019 2,143 2,106 25,061
CURRENT VARIANCE 68 (103) (82) 138 514 295 (45) (74) 39 221 177 166 1,314
YTD VARIANCE 68 (35) (117) 21 535 830 785 711 750 971 1,148 1,314
TOTAL 6,678 14,320 5,153 14,967 10,819 8,766 23,202 38,164 32,222 26,663 29,650 13,639 224,243
CURRENT VARIANCE (6,167) 3,339 (10,548) (15,595) (1,138) (2,244) 8,764 27,581 24,437 12,417 18,437 (20,575) 38,708
YTD VARIANCE (6,167) (2,828) (13,376) (28,971) (30,109) (32,353) (23,589) 3,992 28,429 40,846 59,283 38,708
ACTUAL REVENUES
Jul‐21 Aug‐21 Sep‐21 Oct‐21 Nov‐21 Dec‐21 Jan‐22 Feb‐22 Mar‐22 Apr‐22 May‐22 Jun‐22 TOTAL
Rate per MWH 8.86$ 8.86$ 8.86$ 8.86$ 8.86$ 8.86$ 8.86$ 8.86$ 8.86$ 8.86$ 8.86$ 8.86$
GVEA Energy Charges 42,661$ 109,997$ 29,087$ 115,251$ 75,478$ 56,908$ 184,749$ 320,448$ 265,933$ 218,346$ 243,712$ 102,182$ 1,764,753
GVEA Administrative Charges 8,819$ 8,819$ 8,819$ 8,819$ 8,819$ 8,819$ 8,819$ 8,819$ 8,819$ 8,819$ 8,819$ 48,819$ 145,833
GVEA Cost of Improvements ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
GVEA Capacity Charges 164,580$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ 164,580
YTD Actuals 216,060$ 334,877$ 372,784$ 496,854$ 581,152$ 646,879$ 840,447$ 1,169,715$ 1,444,467$ 1,671,633$ 1,924,164$ 2,075,166$ 2,075,166
YTD Variance (55,242)$ (24,746)$ (117,475)$ (256,869)$ (271,506)$ (294,001)$ (215,954)$ 29,070$ 245,236$ 353,293$ 515,076$ 371,311$
MLP Energy Charges ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
MLP Administrative Charges ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
MLP Cost of Improvements ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
MLP Capacity Charges ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
YTD Actuals ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
YTD Variance ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$
CEA Energy Charges ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
CEA Administrative Charges 8,819$ 8,819$ 8,819$ 8,819$ 8,819$ 8,819$ 8,819$ 8,819$ 8,819$ 8,819$ 8,819$ 48,819$ 145,833
CEA Cost of Improvements ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
CEA Capacity Charges 119,426$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ 119,426
YTD Actuals 128,245$ 137,065$ 145,884$ 154,704$ 163,523$ 172,343$ 181,162$ 189,982$ 198,801$ 207,620$ 216,440$ 265,259$ 265,259
YTD Variance ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ 40,000$
MEA Energy Charges 16,506$ 16,878$ 16,568$ 17,357$ 20,378$ 20,759$ 20,821$ 17,685$ 19,554$ 17,888$ 18,987$ 18,659$ 222,040
MEA Administrative Charges 8,819$ 8,819$ 8,819$ 8,819$ 8,819$ 8,819$ 8,819$ 8,819$ 8,819$ 8,819$ 8,819$ 48,819$ 145,833
MEA Cost of Improvements ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
MEA Capacity Charges 45,365$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ 45,365
YTD Actuals 70,691$ 96,388$ 121,776$ 147,952$ 177,150$ 206,728$ 236,368$ 262,872$ 291,246$ 317,954$ 345,760$ 413,239$ 413,239
YTD Variance 602$ (310)$ (1,037)$ 186$ 4,740$ 7,354$ 6,955$ 6,299$ 6,645$ 8,603$ 10,171$ 51,642$
TOTAL ENERGY CHARGES 59,167$ 126,875$ 45,656$ 132,608$ 95,856$ 77,667$ 205,570$ 338,133$ 285,487$ 236,234$ 262,699$ 120,842$ 1,986,793
TOTAL ADMINISTRATIVE CHARGES 26,458$ 26,458$ 26,458$ 26,458$ 26,458$ 26,458$ 26,458$ 26,458$ 26,458$ 26,458$ 26,458$ 146,458$ 437,500
TOTAL COST OF IMPROVEMENTS ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
TOTAL CAPACITY CHARGES 329,371$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ 329,371
YTD TOTAL REVENUES 414,996$ 568,330$ 640,444$ 799,510$ 921,824$ 1,025,950$ 1,257,978$ 1,622,569$ 1,934,514$ 2,197,207$ 2,486,364$ 2,753,664$ 2,753,664
YTD TOTAL VARIANCE (54,640)$ (25,056)$ (118,511)$ (256,683)$ (266,766)$ (286,648)$ (208,999)$ 35,369$ 251,881$ 361,896$ 525,247$ 462,953$
MWH PROJECTIONS Jul‐21 Aug‐21 Sep‐21 Oct‐21 Nov‐21 Dec‐21 Jan‐22 Feb‐22 Mar‐22 Apr‐22 May‐22 Jun‐22 TOTAL
MWH MWH MWH MWH MWH MWH MWH MWH MWH MWH MWH MWH MWH
GVEA 11,050 8,973 13,749 28,741 10,171 8,962 12,043 8,513 5,617 12,448 9,247 32,274 161,788
YTD 11,050 20,023 33,772 62,513 72,684 81,646 93,689 102,202 107,819 120,267 129,514 161,788
MLP ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
YTD ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
CEA ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
YTD ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
MEA 1,795 2,008 1,952 1,821 1,786 2,048 2,395 2,070 2,168 1,798 1,966 1,940 23,747
YTD 1,795 3,803 5,755 7,576 9,362 11,410 13,805 15,875 18,043 19,841 21,807 23,747
TOTAL 12,845 10,981 15,701 30,562 11,957 11,010 14,438 10,583 7,785 14,246 11,213 34,214 185,535
YTD 12,845 23,826 39,527 70,089 82,046 93,056 107,494 118,077 125,862 140,108 151,321 185,535
BUDGETED REVENUES
Jul‐21 Aug‐21 Sep‐21 Oct‐21 Nov‐21 Dec‐21 Jan‐22 Feb‐22 Mar‐22 Apr‐22 May‐22 Jun‐22 TOTAL
Budgeted Rate per MWH 8.86$ 8.86$ 8.86$ 8.86$ 8.86$ 8.86$ 8.86$ 8.86$ 8.86$ 8.86$ 8.86$ 8.86$
GVEA Energy Charges 97,903$ 79,501$ 121,816$ 254,645$ 90,115$ 79,403$ 106,701$ 75,425$ 49,767$ 110,289$ 81,928$ 285,948$ 1,433,442
GVEA Administrative Charges 8,819$ 8,819$ 8,819$ 8,819$ 8,819$ 8,819$ 8,819$ 8,819$ 8,819$ 8,819$ 8,819$ 8,819$ 105,833
GVEA Cost of Improvements ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
GVEA Capacity Charges 164,580$ 164,580
YTD 271,302$ 359,623$ 490,258$ 753,723$ 852,657$ 940,880$ 1,056,401$ 1,140,645$ 1,199,231$ 1,318,340$ 1,409,088$ 1,703,855$ 1,703,855
MLP Energy Charges ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
MLP Administrative Charges ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
MLP Cost of Improvements ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
MLP Capacity Charges ‐$ ‐
YTD ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
CEA Energy Charges ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
CEA Administrative Charges 8,819$ 8,819$ 8,819$ 8,819$ 8,819$ 8,819$ 8,819$ 8,819$ 8,819$ 8,819$ 8,819$ 8,819$ 105,833
CEA Cost of Improvements ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
CEA Capacity Charges 119,426$ 119,426
YTD 128,245$ 137,065$ 145,884$ 154,704$ 163,523$ 172,343$ 181,162$ 189,982$ 198,801$ 207,620$ 216,440$ 225,259$ 225,259
MEA Energy Charges 15,904$ 17,791$ 17,295$ 16,134$ 15,824$ 18,145$ 21,220$ 18,340$ 19,208$ 15,930$ 17,419$ 17,188$ 210,398
MEA Administrative Charges 8,819$ 8,819$ 8,819$ 8,819$ 8,819$ 8,819$ 8,819$ 8,819$ 8,819$ 8,819$ 8,819$ 8,819$ 105,833
MEA Cost of Improvements ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
MEA Capacity Charges 45,365$ 45,365
YTD 70,088$ 96,698$ 122,813$ 147,766$ 172,410$ 199,374$ 229,413$ 256,573$ 284,601$ 309,351$ 335,589$ 361,597$ 361,597
TOTAL ENERGY CHARGES 113,807$ 97,292$ 139,111$ 270,779$ 105,939$ 97,549$ 127,921$ 93,765$ 68,975$ 126,220$ 99,347$ 303,136$ 1,643,840
TOTAL ADMINISTRATIVE CHARGES 26,458$ 26,458$ 26,458$ 26,458$ 26,458$ 26,458$ 26,458$ 26,458$ 26,458$ 26,458$ 26,458$ 26,458$ 317,500
TOTAL COST OF IMPROVEMENTS ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
TOTAL CAPACITY CHARGES 329,371$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ 329,371
YTD 469,636$ 593,386$ 758,955$ 1,056,193$ 1,188,590$ 1,312,597$ 1,466,976$ 1,587,200$ 1,682,633$ 1,835,311$ 1,961,117$ 2,290,711$ 2,290,711
462,953
C:\Users\jbertolini\AppData\Local\Microsoft\Windows\INetCache\Content.Outlook\EHDWSOC9\Resiliency Grant Application Potential Match Allocation 2024 Page 1 of 1
ALASKA INTERTIE REVENUE VARIANCE REPORT FY21
MWH ACTUAL USAGE Jul‐20 Aug‐20 Sep‐20 Oct‐20 Nov‐20 Dec‐20 Jan‐21 Feb‐21 Mar‐21 Apr‐21 May‐21 Jun‐21 TOTAL
MWH MWH MWH MWH MWH MWH MWH MWH MWH MWH MWH MWH MWH
GVEA 2,248 7,617 12,672 14,089 14,115 14,530 16,895 23,148 14,870 29,470 17,993 6,975 174,622
CURRENT VARIANCE (3,752) (383) 5,672 4,089 6,115 5,530 6,895 13,148 8,870 17,470 7,993 975 72,622
YTD VARIANCE (3,752) (4,135) 1,537 5,626 11,741 17,271 24,166 37,314 46,184 63,654 71,647 72,622
MLP ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
CURRENT VARIANCE ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
YTD VARIANCE ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
CEA ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
CURRENT VARIANCE ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
YTD VARIANCE ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
MEA 786 1,628 1,651 1,817 2,065 2,154 2,197 2,082 2,210 1,855 1,821 1,752 22,018
CURRENT VARIANCE (1,321) (376) (233) 106 350 114 (257) 74 355 105 (190) (250) (1,523)
YTD VARIANCE (1,321) (1,697) (1,930) (1,824) (1,474) (1,360) (1,617) (1,543) (1,188) (1,083) (1,273) (1,523)
TOTAL 3,034 9,245 14,323 15,906 16,180 16,684 19,092 25,230 17,080 31,325 19,814 8,727 196,640
CURRENT VARIANCE (5,073) (759) 5,439 4,195 6,465 5,644 6,638 13,222 9,225 17,575 7,803 725 71,099
YTD VARIANCE (5,073) (5,832) (393) 3,802 10,267 15,911 22,549 35,771 44,996 62,571 70,374 71,099
ACTUAL REVENUES
Jul‐20 Aug‐20 Sep‐20 Oct‐20 Nov‐20 Dec‐20 Jan‐21 Feb‐21 Mar‐21 Apr‐21 May‐21 Jun‐21 TOTAL
Rate per MWH 8.92$ 8.92$ 8.92$ 8.92$ 8.92$ 8.92$ 8.92$ 8.92$ 8.92$ 8.92$ 8.92$ 8.92$
GVEA Energy Charges 20,052$ 67,944$ 113,034$ 125,674$ 125,906$ 129,608$ 150,703$ 206,480$ 132,640$ 262,872$ 160,498$ 62,217$ 1,557,628
GVEA Administrative Charges 15,000$ 15,000$ 15,000$ 15,000$ 20,000$ 20,000$ 20,000$ 20,000$ 20,000$ 20,000$ 20,000$ 20,000$ 220,000
GVEA Cost of Improvements ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
GVEA Capacity Charges 165,360$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ 165,360
YTD Actuals 200,412$ 283,356$ 411,390$ 552,064$ 697,970$ 847,577$ 1,018,281$ 1,244,761$ 1,397,401$ 1,680,274$ 1,860,771$ 1,942,988$ 1,942,988
YTD Variance (33,468)$ (36,884)$ 13,710$ 50,184$ 109,730$ 164,057$ 230,561$ 352,841$ 436,961$ 597,794$ 674,091$ 687,788$
MLP Energy Charges ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
MLP Administrative Charges 15,000$ 15,000$ 15,000$ 15,000$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ 60,000
MLP Cost of Improvements ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
MLP Capacity Charges 51,217$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ 51,217
YTD Actuals 66,217$ 81,217$ 96,217$ 111,217$ 111,217$ 111,217$ 111,217$ 111,217$ 111,217$ 111,217$ 111,217$ 111,217$ 111,217
YTD Variance ‐$ ‐$ ‐$ ‐$ (15,000)$ (30,000)$ (45,000)$ (60,000)$ (75,000)$ (90,000)$ (105,000)$ (120,000)$
CEA Energy Charges ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
CEA Administrative Charges 15,000$ 15,000$ 15,000$ 15,000$ 20,000$ 20,000$ 20,000$ 20,000$ 20,000$ 20,000$ 20,000$ 20,000$ 220,000
CEA Cost of Improvements ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
CEA Capacity Charges 70,065$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ 70,065
YTD Actuals 85,065$ 100,065$ 115,065$ 130,065$ 150,065$ 170,065$ 190,065$ 210,065$ 230,065$ 250,065$ 270,065$ 290,065$ 290,065
YTD Variance ‐$ ‐$ ‐$ ‐$ 5,000$ 10,000$ 15,000$ 20,000$ 25,000$ 30,000$ 35,000$ 40,000$
MEA Energy Charges 7,011$ 14,522$ 14,727$ 16,208$ 18,420$ 19,214$ 19,597$ 18,571$ 19,713$ 16,547$ 16,243$ 15,628$ 196,401
MEA Administrative Charges 15,000$ 15,000$ 15,000$ 15,000$ 20,000$ 20,000$ 20,000$ 20,000$ 20,000$ 20,000$ 20,000$ 20,000$ 220,000
MEA Cost of Improvements ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
MEA Capacity Charges 44,078$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ 44,078
YTD Actuals 66,089$ 95,611$ 125,338$ 156,545$ 194,965$ 234,179$ 273,776$ 312,348$ 352,061$ 388,607$ 424,851$ 460,479$ 460,479
YTD Variance (11,783)$ (15,137)$ (17,216)$ (16,270)$ (8,148)$ (2,131)$ 576$ 6,236$ 14,403$ 20,340$ 23,645$ 26,415$
TOTAL ENERGY CHARGES 27,063$ 82,465$ 127,761$ 141,882$ 144,326$ 148,821$ 170,301$ 225,052$ 152,354$ 279,419$ 176,741$ 77,845$ 1,754,029
TOTAL ADMINISTRATIVE CHARGES 60,000$ 60,000$ 60,000$ 60,000$ 60,000$ 60,000$ 60,000$ 60,000$ 60,000$ 60,000$ 60,000$ 60,000$ 720,000
TOTAL COST OF IMPROVEMENTS ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
TOTAL CAPACITY CHARGES 330,720$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ 330,720
YTD TOTAL REVENUES 417,783$ 560,249$ 748,010$ 949,891$ 1,154,217$ 1,363,038$ 1,593,339$ 1,878,390$ 2,090,744$ 2,430,163$ 2,666,904$ 2,804,749$ 2,804,749
YTD TOTAL VARIANCE (45,251)$ (52,021)$ (3,506)$ 33,914$ 91,582$ 141,926$ 201,137$ 319,077$ 401,364$ 558,133$ 627,736$ 634,203$
MWH PROJECTIONS Jul‐20 Aug‐20 Sep‐20 Oct‐20 Nov‐20 Dec‐20 Jan‐21 Feb‐21 Mar‐21 Apr‐21 May‐21 Jun‐21 TOTAL
MWH MWH MWH MWH MWH MWH MWH MWH MWH MWH MWH MWH MWH
GVEA 6,000 8,000 7,000 10,000 8,000 9,000 10,000 10,000 6,000 12,000 10,000 6,000 102,000
YTD 6,000 14,000 21,000 31,000 39,000 48,000 58,000 68,000 74,000 86,000 96,000 102,000
MLP ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
YTD ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
CEA ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
YTD ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
MEA 2,107 2,004 1,884 1,711 1,715 2,040 2,454 2,008 1,855 1,750 2,011 2,002 23,541
YTD 2,107 4,111 5,995 7,706 9,421 11,461 13,915 15,923 17,778 19,528 21,539 23,541
TOTAL 8,107 10,004 8,884 11,711 9,715 11,040 12,454 12,008 7,855 13,750 12,011 8,002 125,541
YTD 8,107 18,111 26,995 38,706 48,421 59,461 71,915 83,923 91,778 105,528 117,539 125,541
BUDGETED REVENUES
Jul‐20 Aug‐20 Sep‐20 Oct‐20 Nov‐20 Dec‐20 Jan‐21 Feb‐21 Mar‐21 Apr‐21 May‐21 Jun‐21 TOTAL
Budgeted Rate per MWH 8.92$ 8.92$ 8.92$ 8.92$ 8.92$ 8.92$ 8.92$ 8.92$ 8.92$ 8.92$ 8.92$ 8.92$
GVEA Energy Charges 53,520$ 71,360$ 62,440$ 89,200$ 71,360$ 80,280$ 89,200$ 89,200$ 53,520$ 107,040$ 89,200$ 53,520$ 909,840
GVEA Administrative Charges 15,000$ 15,000$ 15,000$ 15,000$ 15,000$ 15,000$ 15,000$ 15,000$ 15,000$ 15,000$ 15,000$ 15,000$ 180,000
GVEA Cost of Improvements ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
GVEA Capacity Charges 165,360$ 165,360
YTD 233,880$ 320,240$ 397,680$ 501,880$ 588,240$ 683,520$ 787,720$ 891,920$ 960,440$ 1,082,480$ 1,186,680$ 1,255,200$ 1,255,200
MLP Energy Charges ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
MLP Administrative Charges 15,000$ 15,000$ 15,000$ 15,000$ 15,000$ 15,000$ 15,000$ 15,000$ 15,000$ 15,000$ 15,000$ 15,000$ 180,000
MLP Cost of Improvements ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
MLP Capacity Charges 51,217$ 51,217
YTD 66,217$ 81,217$ 96,217$ 111,217$ 126,217$ 141,217$ 156,217$ 171,217$ 186,217$ 201,217$ 216,217$ 231,217$ 231,217
CEA Energy Charges ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
CEA Administrative Charges 15,000$ 15,000$ 15,000$ 15,000$ 15,000$ 15,000$ 15,000$ 15,000$ 15,000$ 15,000$ 15,000$ 15,000$ 180,000
CEA Cost of Improvements ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
CEA Capacity Charges 70,065$ 70,065
YTD 85,065$ 100,065$ 115,065$ 130,065$ 145,065$ 160,065$ 175,065$ 190,065$ 205,065$ 220,065$ 235,065$ 250,065$ 250,065
MEA Energy Charges 18,794$ 17,876$ 16,805$ 15,262$ 15,298$ 18,197$ 21,890$ 17,911$ 16,547$ 15,610$ 17,938$ 17,858$ 209,986
MEA Administrative Charges 15,000$ 15,000$ 15,000$ 15,000$ 15,000$ 15,000$ 15,000$ 15,000$ 15,000$ 15,000$ 15,000$ 15,000$ 180,000
MEA Cost of Improvements ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
MEA Capacity Charges 44,078$ 44,078
YTD 77,872$ 110,748$ 142,553$ 172,816$ 203,113$ 236,310$ 273,200$ 306,111$ 337,658$ 368,268$ 401,206$ 434,064$ 434,064
TOTAL ENERGY CHARGES 72,314$ 89,236$ 79,245$ 104,462$ 86,658$ 98,477$ 111,090$ 107,111$ 70,067$ 122,650$ 107,138$ 71,378$ 1,119,826
TOTAL ADMINISTRATIVE CHARGES 60,000$ 60,000$ 60,000$ 60,000$ 60,000$ 60,000$ 60,000$ 60,000$ 60,000$ 60,000$ 60,000$ 60,000$ 720,000
TOTAL COST OF IMPROVEMENTS ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
TOTAL CAPACITY CHARGES 330,720$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ 330,720
YTD 463,034$ 612,270$ 751,515$ 915,978$ 1,062,635$ 1,221,112$ 1,392,202$ 1,559,313$ 1,689,380$ 1,872,030$ 2,039,168$ 2,170,546$ 2,170,546
634,203
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ALASKA INTERTIE REVENUE VARIANCE REPORT FY20
MWH ACTUAL USAGE Jul‐19 Aug‐19 Sep‐19 Oct‐19 Nov‐19 Dec‐19 Jan‐20 Feb‐20 Mar‐20 Apr‐20 May‐20 Jun‐20 TOTAL
MWH MWH MWH MWH MWH MWH MWH MWH MWH MWH MWH MWH MWH
GVEA 14,996 17,753 3,638 10,207 9,686 10,837 16,001 14,144 8,747 7,630 6,113 4,073 123,825
CURRENT VARIANCE 6,246 11,453 (3,862) (293) (814) 1,737 4,251 644 1,747 (24,370) (1,387) (11,427) (16,075)
YTD VARIANCE 6,246 17,699 13,837 13,544 12,730 14,467 18,718 19,362 21,109 (3,261) (4,648) (16,075)
MLP ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
CURRENT VARIANCE ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
YTD VARIANCE ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
CEA ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
CURRENT VARIANCE ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
YTD VARIANCE ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
MEA 2,164 2,039 1,956 1,752 1,774 1,900 2,513 2,046 2,194 1,566 1,358 1,470 22,732
CURRENT VARIANCE 84 90 61 204 536 416 452 142 202 (119) (586) (447) 1,035
YTD VARIANCE 84 174 235 439 975 1,391 1,843 1,985 2,187 2,068 1,482 1,035
TOTAL 17,160 19,792 5,594 11,959 11,460 12,737 18,514 16,190 10,941 9,196 7,471 5,543 146,557
CURRENT VARIANCE 6,330 11,543 (3,801) (89) (278) 2,153 4,703 786 1,949 (24,489) (1,973) (11,874) (15,040)
YTD VARIANCE 6,330 17,873 14,072 13,983 13,705 15,858 20,561 21,347 23,296 (1,193) (3,166) (15,040)
ACTUAL REVENUES
Jul‐19 Aug‐19 Sep‐19 Oct‐19 Nov‐19 Dec‐19 Jan‐20 Feb‐20 Mar‐20 Apr‐20 May‐20 Jun‐20 TOTAL
Rate per MWH 9.64$ 9.64$ 9.64$ 9.64$ 9.64$ 9.64$ 9.64$ 9.64$ 9.64$ 9.64$ 9.64$ 9.64$
GVEA Energy Charges 144,561$ 171,139$ 35,070$ 98,395$ 93,373$ 104,469$ 154,250$ 136,348$ 84,321$ 73,553$ 58,929$ 39,264$ 1,193,673
GVEA Administrative Charges 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 182,250
GVEA Cost of Improvements ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
GVEA Capacity Charges 178,620$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ 178,620
YTD Actuals 338,369$ 524,695$ 574,953$ 688,536$ 797,097$ 916,753$ 1,086,190$ 1,237,726$ 1,337,234$ 1,425,975$ 1,500,092$ 1,554,543$ 1,554,543
YTD Variance 60,211$ 170,618$ 133,389$ 130,564$ 122,717$ 139,462$ 180,442$ 186,650$ 203,491$ (31,436)$ (44,807)$ (154,963)$
MLP Energy Charges ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
MLP Administrative Charges 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 182,250
MLP Cost of Improvements ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
MLP Capacity Charges 55,688$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ 55,688
YTD Actuals 70,876$ 86,063$ 101,251$ 116,438$ 131,626$ 146,813$ 162,001$ 177,188$ 192,376$ 207,563$ 222,751$ 237,938$ 237,938
YTD Variance ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$
CEA Energy Charges ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
CEA Administrative Charges 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 182,250
CEA Cost of Improvements ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
CEA Capacity Charges 75,840$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ 75,840
YTD Actuals 91,028$ 106,215$ 121,403$ 136,590$ 151,778$ 166,965$ 182,153$ 197,340$ 212,528$ 227,715$ 242,903$ 258,090$ 258,090
YTD Variance ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$
MEA Energy Charges 20,861$ 19,656$ 18,856$ 16,889$ 17,101$ 18,316$ 24,225$ 19,723$ 21,150$ 15,096$ 13,091$ 14,171$ 219,136
MEA Administrative Charges 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 182,250
MEA Cost of Improvements ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
MEA Capacity Charges 47,092$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ 47,092
YTD Actuals 83,140$ 117,983$ 152,027$ 184,104$ 216,392$ 249,896$ 289,309$ 324,220$ 360,557$ 390,841$ 419,120$ 448,478$ 448,478
YTD Variance 810$ 1,677$ 2,265$ 4,232$ 9,399$ 13,409$ 17,767$ 19,133$ 21,081$ 19,934$ 14,284$ 9,975$
TOTAL ENERGY CHARGES 165,422$ 190,795$ 53,926$ 115,285$ 110,474$ 122,785$ 178,475$ 156,072$ 105,471$ 88,649$ 72,020$ 53,435$ 1,412,809
TOTAL ADMINISTRATIVE CHARGES 60,750$ 60,750$ 60,750$ 60,750$ 60,750$ 60,750$ 60,750$ 60,750$ 60,750$ 60,750$ 60,750$ 60,750$ 729,000
TOTAL COST OF IMPROVEMENTS ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
TOTAL CAPACITY CHARGES 357,240$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ 357,240
YTD TOTAL REVENUES 583,412$ 834,957$ 949,633$ 1,125,668$ 1,296,893$ 1,480,427$ 1,719,652$ 1,936,474$ 2,102,695$ 2,252,095$ 2,384,865$ 2,499,049$ 2,499,049
YTD TOTAL VARIANCE 61,021$ 172,296$ 135,654$ 134,796$ 132,116$ 152,871$ 198,208$ 205,783$ 224,571$ (11,503)$ (30,522)$ (144,988)$
MWH PROJECTIONS Jul‐19 Aug‐19 Sep‐19 Oct‐19 Nov‐19 Dec‐19 Jan‐20 Feb‐20 Mar‐20 Apr‐20 May‐20 Jun‐20 TOTAL
MWH MWH MWH MWH MWH MWH MWH MWH MWH MWH MWH MWH MWH
GVEA 8,750 6,300 7,500 10,500 10,500 9,100 11,750 13,500 7,000 32,000 7,500 15,500 139,900
YTD 8,750 15,050 22,550 33,050 43,550 52,650 64,400 77,900 84,900 116,900 124,400 139,900
MLP ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
YTD ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
CEA ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
YTD ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
MEA 2,080 1,949 1,895 1,548 1,238 1,484 2,061 1,904 1,992 1,685 1,944 1,917 21,697
YTD 2,080 4,029 5,924 7,472 8,710 10,194 12,255 14,159 16,151 17,836 19,780 21,697
TOTAL 10,830 8,249 9,395 12,048 11,738 10,584 13,811 15,404 8,992 33,685 9,444 17,417 161,597
YTD 10,830 19,079 28,474 40,522 52,260 62,844 76,655 92,059 101,051 134,736 144,180 161,597
BUDGETED REVENUES
Jul‐19 Aug‐19 Sep‐19 Oct‐19 Nov‐19 Dec‐19 Jan‐20 Feb‐20 Mar‐20 Apr‐20 May‐20 Jun‐20 TOTAL
Budgeted Rate per MWH 9.64$ 9.64$ 9.64$ 9.64$ 9.64$ 9.64$ 9.64$ 9.64$ 9.64$ 9.64$ 9.64$ 9.64$
GVEA Energy Charges 84,350$ 60,732$ 72,300$ 101,220$ 101,220$ 87,724$ 113,270$ 130,140$ 67,480$ 308,480$ 72,300$ 149,420$ 1,348,636
GVEA Administrative Charges 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 182,250
GVEA Cost of Improvements ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
GVEA Capacity Charges 178,620$ 178,620
YTD 278,158$ 354,077$ 441,565$ 557,972$ 674,380$ 777,291$ 905,749$ 1,051,076$ 1,133,744$ 1,457,411$ 1,544,899$ 1,709,506$ 1,709,506
MLP Energy Charges ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
MLP Administrative Charges 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 182,250
MLP Cost of Improvements ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
MLP Capacity Charges 55,688$ 55,688
YTD 70,876$ 86,063$ 101,251$ 116,438$ 131,626$ 146,813$ 162,001$ 177,188$ 192,376$ 207,563$ 222,751$ 237,938$ 237,938
CEA Energy Charges ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
CEA Administrative Charges 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 182,250
CEA Cost of Improvements ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
CEA Capacity Charges 75,840$ 75,840
YTD 91,028$ 106,215$ 121,403$ 136,590$ 151,778$ 166,965$ 182,153$ 197,340$ 212,528$ 227,715$ 242,903$ 258,090$ 258,090
MEA Energy Charges 20,051$ 18,788$ 18,268$ 14,923$ 11,934$ 14,306$ 19,868$ 18,357$ 19,203$ 16,243$ 18,740$ 18,480$ 209,162
MEA Administrative Charges 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 15,188$ 182,250
MEA Cost of Improvements ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
MEA Capacity Charges 47,092$ 47,092
YTD 82,330$ 116,306$ 149,761$ 179,872$ 206,993$ 236,487$ 271,542$ 305,086$ 339,477$ 370,908$ 404,835$ 438,503$ 438,504
TOTAL ENERGY CHARGES 104,401$ 79,520$ 90,568$ 116,143$ 113,154$ 102,030$ 133,138$ 148,497$ 86,683$ 324,723$ 91,040$ 167,900$ 1,557,797
TOTAL ADMINISTRATIVE CHARGES 60,750$ 60,750$ 60,750$ 60,750$ 60,750$ 60,750$ 60,750$ 60,750$ 60,750$ 60,750$ 60,750$ 60,750$ 729,000
TOTAL COST OF IMPROVEMENTS ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
TOTAL CAPACITY CHARGES 357,240$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ 357,240
YTD 522,391$ 662,662$ 813,979$ 990,872$ 1,164,776$ 1,327,556$ 1,521,444$ 1,730,691$ 1,878,124$ 2,263,597$ 2,415,387$ 2,644,037$ 2,644,038
(144,989)
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ALASKA INTERTIE REVENUE VARIANCE REPORT FY19
MWH ACTUAL USAGE Jul‐18 Aug‐18 Sep‐18 Oct‐18 Nov‐18 Dec‐18 Jan‐19 Feb‐19 Mar‐19 Apr‐19 May‐19 Jun‐19 TOTAL
MWH MWH MWH MWH MWH MWH MWH MWH MWH MWH MWH MWH MWH
GVEA 39,260 22,824 12,120 33,235 15,846 22,635 19,505 12,571 8,936 33,981 31,380 16,383 268,676
CURRENT VARIANCE 23,855 3,690 4,766 23,589 9,019 14,938 (3,720) (11,699) (3,178) 3,660 2,550 5,119 72,589
YTD VARIANCE 23,855 27,545 32,311 55,900 64,919 79,857 76,137 64,438 61,260 64,920 67,470 72,589
MLP ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
CURRENT VARIANCE ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
YTD VARIANCE ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
CEA ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
CURRENT VARIANCE ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
YTD VARIANCE ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
MEA 2,123 1,972 1,931 1,589 1,233 1,511 2,112 1,836 1,903 1,789 2,033 2,039 22,071
CURRENT VARIANCE 22 (158) (29) (207) (705) (510) (18) 69 147 130 96 150 (1,013)
YTD VARIANCE 22 (136) (165) (372) (1,077) (1,587) (1,605) (1,536) (1,389) (1,259) (1,163) (1,013)
TOTAL 41,383 24,796 14,051 34,824 17,079 24,146 21,617 14,407 10,839 35,770 33,413 18,422 290,747
CURRENT VARIANCE 23,877 3,532 4,737 23,382 8,314 14,428 (3,738) (11,630) (3,031) 3,790 2,646 5,269 71,576
YTD VARIANCE 23,877 27,409 32,146 55,528 63,842 78,270 74,532 62,902 59,871 63,661 66,307 71,576
ACTUAL REVENUES
Jul‐18 Aug‐18 Sep‐18 Oct‐18 Nov‐18 Dec‐18 Jan‐19 Feb‐19 Mar‐19 Apr‐19 May‐19 Jun‐19 TOTAL
Rate per MWH 10.60$ 10.60$ 10.60$ 10.60$ 10.60$ 10.60$ 0.24$ 0.24$ 0.24$ 0.24$ 0.24$ 0.24$
GVEA Energy Charges 416,156$ 241,934$ 128,472$ 352,291$ 167,968$ 239,931$ 4,681$ 3,017$ 2,145$ 8,155$ 7,531$ 3,932$ 1,576,213
GVEA Administrative Charges 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 83,750
GVEA Cost of Improvements ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
GVEA Capacity Charges 196,560$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ 196,560
YTD Actuals 619,695$ 868,609$ 1,004,060$ 1,363,330$ 1,538,277$ 1,785,187$ 1,796,847$ 1,806,844$ 1,815,967$ 1,831,102$ 1,845,612$ 1,856,523$ 1,856,523
YTD Variance 252,863$ 291,977$ 342,497$ 592,540$ 688,141$ 846,484$ 845,615$ 842,834$ 842,084$ 842,994$ 843,636$ 844,876$
MLP Energy Charges ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
MLP Administrative Charges 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 83,750
MLP Cost of Improvements ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
MLP Capacity Charges 62,496$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ 62,496
YTD Actuals 69,475$ 76,454$ 83,434$ 90,413$ 97,392$ 104,371$ 111,350$ 118,329$ 125,309$ 132,288$ 139,267$ 146,246$ 146,246
YTD Variance ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$
CEA Energy Charges ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
CEA Administrative Charges 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 83,750
CEA Cost of Improvements ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
CEA Capacity Charges 82,656$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ 82,656
YTD Actuals 89,635$ 96,614$ 103,594$ 110,573$ 117,552$ 124,531$ 131,510$ 138,489$ 145,469$ 152,448$ 159,427$ 166,406$ 166,406
YTD Variance ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$
MEA Energy Charges 22,504$ 20,903$ 20,469$ 16,843$ 13,070$ 16,017$ 507$ 441$ 457$ 429$ 488$ 489$ 112,616
MEA Administrative Charges 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 83,750
MEA Cost of Improvements ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
MEA Capacity Charges 51,408$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ 51,408
YTD Actuals 80,891$ 108,773$ 136,221$ 160,044$ 180,093$ 203,088$ 210,574$ 217,994$ 225,430$ 232,839$ 240,306$ 247,774$ 247,774
YTD Variance 233$ (1,442)$ (1,749)$ (3,943)$ (11,416)$ (16,822)$ (16,824)$ (16,806)$ (16,769)$ (16,736)$ (16,711)$ (16,673)$
TOTAL ENERGY CHARGES 438,660$ 262,838$ 148,941$ 369,134$ 181,037$ 255,948$ 5,188$ 3,458$ 2,601$ 8,585$ 8,019$ 4,421$ 1,688,830
TOTAL ADMINISTRATIVE CHARGES 27,917$ 27,917$ 27,917$ 27,917$ 27,917$ 27,917$ 27,917$ 27,917$ 27,917$ 27,917$ 27,917$ 27,917$ 335,000
TOTAL COST OF IMPROVEMENTS ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
TOTAL CAPACITY CHARGES 393,120$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ 393,120
YTD TOTAL REVENUES 859,696$ 1,150,451$ 1,327,308$ 1,724,359$ 1,933,313$ 2,217,177$ 2,250,282$ 2,281,657$ 2,312,175$ 2,348,676$ 2,384,612$ 2,416,950$ 2,416,950
YTD TOTAL VARIANCE 253,096$ 290,535$ 340,748$ 588,597$ 676,725$ 829,662$ 828,791$ 826,028$ 825,315$ 826,258$ 826,925$ 828,203$
MWH PROJECTIONS Jul‐18 Aug‐18 Sep‐18 Oct‐18 Nov‐18 Dec‐18 Jan‐19 Feb‐19 Mar‐19 Apr‐19 May‐19 Jun‐19 TOTAL
MWH MWH MWH MWH MWH MWH MWH MWH MWH MWH MWH MWH MWH
GVEA 15,405 19,134 7,354 9,646 6,827 7,697 23,225 24,270 12,114 30,321 28,830 11,264 196,087
YTD 15,405 34,539 41,893 51,539 58,366 66,063 89,288 113,558 125,672 155,993 184,823 196,087
MLP ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
YTD ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
CEA ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
YTD ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
MEA 2,101 2,130 1,960 1,796 1,938 2,021 2,130 1,767 1,756 1,659 1,937 1,889 23,084
YTD 2,101 4,231 6,191 7,987 9,925 11,946 14,076 15,843 17,599 19,258 21,195 23,084
TOTAL 17,506 21,264 9,314 11,442 8,765 9,718 25,355 26,037 13,870 31,980 30,767 13,153 219,171
YTD 17,506 38,770 48,084 59,526 68,291 78,009 103,364 129,401 143,271 175,251 206,018 219,171
BUDGETED REVENUES
Jul‐18 Aug‐18 Sep‐18 Oct‐18 Nov‐18 Dec‐18 Jan‐19 Feb‐19 Mar‐19 Apr‐19 May‐19 Jun‐19 TOTAL
Budgeted Rate per MWH 10.60$ 10.60$ 10.60$ 10.60$ 10.60$ 10.60$ 0.24$ 0.24$ 0.24$ 0.24$ 0.24$ 0.24$
GVEA Energy Charges 163,293$ 202,820$ 77,952$ 102,248$ 72,366$ 81,588$ 5,550$ 5,799$ 2,895$ 7,245$ 6,889$ 2,692$ 731,337
GVEA Administrative Charges 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 83,750
GVEA Cost of Improvements ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
GVEA Capacity Charges 196,560$ 196,560
YTD 366,832$ 576,632$ 661,563$ 770,790$ 850,135$ 938,703$ 951,232$ 964,010$ 973,884$ 988,108$ 1,001,976$ 1,011,647$ 1,011,647
MLP Energy Charges ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
MLP Administrative Charges 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 83,750
MLP Cost of Improvements ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
MLP Capacity Charges 62,496$ 62,496
YTD 69,475$ 76,454$ 83,434$ 90,413$ 97,392$ 104,371$ 111,350$ 118,329$ 125,309$ 132,288$ 139,267$ 146,246$ 146,246
CEA Energy Charges ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
CEA Administrative Charges 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 83,750
CEA Cost of Improvements ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
CEA Capacity Charges 82,656$ 82,656
YTD 89,635$ 96,614$ 103,594$ 110,573$ 117,552$ 124,531$ 131,510$ 138,489$ 145,469$ 152,448$ 159,427$ 166,406$ 166,406
MEA Energy Charges 22,271$ 22,578$ 20,776$ 19,038$ 20,543$ 21,423$ 509$ 422$ 420$ 396$ 463$ 451$ 129,289
MEA Administrative Charges 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 6,979$ 83,750
MEA Cost of Improvements ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
MEA Capacity Charges 51,408$ 51,408
YTD 80,658$ 110,215$ 137,970$ 163,987$ 191,509$ 219,911$ 227,399$ 234,800$ 242,199$ 249,575$ 257,017$ 264,447$ 264,447
TOTAL ENERGY CHARGES 185,564$ 225,398$ 98,728$ 121,285$ 92,909$ 103,011$ 6,059$ 6,221$ 3,314$ 7,641$ 7,352$ 3,143$ 860,626
TOTAL ADMINISTRATIVE CHARGES 27,917$ 27,917$ 27,917$ 27,917$ 27,917$ 27,917$ 27,917$ 27,917$ 27,917$ 27,917$ 27,917$ 27,917$ 335,000
TOTAL COST OF IMPROVEMENTS ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐
TOTAL CAPACITY CHARGES 393,120$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ ‐$ 393,120
YTD 606,600$ 859,915$ 986,560$ 1,135,762$ 1,256,588$ 1,387,515$ 1,421,491$ 1,455,629$ 1,486,860$ 1,522,418$ 1,557,687$ 1,588,747$ 1,588,747
0
Original Budget projections 2/14/19 Amended Budget projections
Original Budget rates and revenues 2/14/19 Amended Budget rates and revenues
C:\Users\jbertolini\AppData\Local\Microsoft\Windows\INetCache\Content.Outlook\EHDWSOC9\Resiliency Grant Application Potential Match Allocation 2024 Page 1 of 1
Page 1 of 3 IMC Resolution 24-02 In Support of Grant Application – Synchrophasor Project
Intertie Management Committee
Resolution No. 24-02
In Support of Application For Grant Preventing Outages and Enhancing the Resilience of the Electric Grid Formula Grant – Synchrophasor Project
INTRODUCTION
The Alaska Intertie Management Committee is responsible for the management, operation, maintenance, and improvement of the Alaska Intertie Project (Alaska Intertie), subject to the non-delegable duties of the Alaska Energy Authority (AEA). The Alaska Intertie transmission line is part of the Alaska Railbelt transmission backbone. It connects the population centers of Interior Alaska within the GVEA service area with the populations centers of South-Central Alaska and Kenai Peninsula.
PURPOSE
The purpose of Resolution 24-02 is to express support for the grant application to the Department of Energy for the construction of a Synchrophasor Data Collection Network (the “Project”), to provide a data collection network for unified wide area monitoring, reporting and analysis, and to authorize Golden Valley Electric Association (“GVEA”), Chugach Electric Association (“CEA”), Matanuska Electric Association (“MEA”), and Homer Electric Association (“HEA”) to serve as the Sub-Recipients on behalf of the IMC.
IMC RESOLUTION 24-02
WHEREAS, the Intertie Management Committee is responsible for the management, operation, maintenance, and improvement of the Alaska Intertie Project (“Alaska Intertie”), subject to the non-delegable duties of AEA.
WHEREAS, the Alaska Intertie and the Railbelt have experienced disruptive oscillation events between 2018 and 2021. After multiple studies and investigations were performed to identify the cause, a sub-committee of the Alaska Intertie Operating Committee (“IOC”) developed a plan for a communal system to stream, store and analyze synchrophasor data from high-speed data recorders at 12 key Railbelt substations.
WHEREAS, in October 2022, a formal request for proposals was prepared and issued by the IOC for a turn-key synchrophasor system. Electric Power Group (EPG) was chosen Based in part on the fact that EPG’s synchrophasor and disturbance reporting software applications are used by CAISO, PJM, ERCOT, TVA, NYISO, NERC and other regional reliability entities.
WHEREAS, A contract with EPG has not yet been signed, but funding for a pilot project was approved in the 2024 budget of the IOC and preparations are underway.
Page 2 of 3 IMC Resolution 24-02 In Support of Grant Application – Synchrophasor Project
WHEREAS, The Project will address the system wide oscillation events. In addition, it will aid in
the mitigation of future risk of disruptive events, as well as support reliable and safe operation of
a future low carbon Railbelt electric grid with high levels of renewable energy flowing end to end
between Interior Alaska and the Kenai Peninsula.
WHEREAS, Benefits from the Project also include early detection and identification of instability, assistance with grid planning, and improved system models validated by continuous empirical data, leading to a more sustainable and hardened grid, among other things.
WHEREAS, attached and incorporated herein by this reference is Exhibit 1, the Application pursuant to the Bipartisan Infrastructure Law – Section 40101(d).
NOW, THEREFORE BE IT RESOLVED THAT, the foregoing recitals and Exhibit are incorporated herein by this reference.
BE IT FURTHER RESOLVED, the IMC is in support of the application for the Project to be filed by GVEA, CEA, MEA and HEA.
BE IT FURTHER RESOLVED, so long as the final application is substantially similar to Exhibit 1, and to the extent necessary as authorized by the Board of Directors for each of the utilities
applying for the Grant for the Project, the Chair is authorized to execute any additional documents
necessary to prepare a complete application for the Project.
DATED at Anchorage Alaska, this _____ day of February, 2024.
___________________________________________ Chair, Andrew Laughlin Attest: ______________________________ Secretary, William Price
Page 3 of 3 IMC Resolution 24-02 In Support of Grant Application – Synchrophasor Project
EXHIBIT 1
APPLICATION
Bipartisan Infrastructure Law – Section 40101(d) – PREVENTING
OUTAGES AND ENHANCING THE RESILIENCE OF THE ELECTRIC
GRID FORMULA GRANTS – APPLICATION FORM
Page 1 of 14
Application Instructions
Applications for the Preventing outages and enhancing the resilience of the electric grid formula grants
program will be accepted from January 2nd, 2024 to February 16th, 2024. To apply, please complete
the following application form in its entirety and enclose the UHTXLUHGfollowing supplemental supporting
documents. Use of additional space is permissible by attaching supplemental material.
D Authorization Letter from the HOLJLEOHHQWLW\HOHFWLQJWRVXEPLWDQDSSOLFDWLRQVLJQHG
E\DQDXWKRUL]HGUHSUHVHQWDWLYHRIWKHHQWLW\
E Project budget XVLQJDOE 6)Budget Justification Notebook
F Eligible Entity Request Form LIDSSOLFDEOH
G Environmental Questionnaire 1(3$
H Resilience Project Subaward Notification Form
Application Form
A. Sub-Recipient Information
Sub-Recipient Name:
Entity Type: An electric grid
operator
Other
If “other”, please describe:
An electric
storage operator
An electricity
generator
A transmission
owner or
operator; or a
State owner of
transmission or
generation assets
without a CPCN
CEA - GVEA - MEA - HEA
xx
xx
xx
xx
Page 2 of 14
Any other
relevant entity, as
determined by
the Secretary (of
DOE)
Eligible Entity Point of
Contact:
Name:
Title:
Phone:
E-mail:
Address:
B. Project Information
Project Title:
Engineering Design/Permits/Site
Control Costs*: $
Construction Costs †: $
Administrative Expenses ‡: $
Other Miscellaneous Costs §: $
1/3 Eligible Entity Cost Including
In-Kind Match **: $
Total Federal 40101(d) Cost:
(This is your grant request) $
Description of Primary
Service Area:
(counties/cities of
eligible entity)
*Preliminary engineering shall not exceed 15% of overall construction costs and the project shall be constructed
within the desired 5-year period of performance. Provide a line-item level of detail for costs if available.
† Provide a line-item level of detail if available.
‡ Provide a line-item level of detail if available.
§Provide a line-item level of detail if available.
** Provide anticipated cash and in-kind match values if applicable.
The project covers all communities connected to the Alaska Railbelt
transmission network - between Fairbanks and Homer. The main
population centers are within the Fairbanks North Star Borough,
Matanuska-Susitna Borough, city of Anchorage and Kenai Peninsula Borough,
Keith Palchikoff
Grid Modernization Manager
907-451-5640
kepalchikoff@gvea.com
758 Illinois St., Fairbanks AK
Alaska Railbelt Synchrophasor and Disturbance Reporting System
148,650
1,784,042
167,200
50,050
533,444
1,616,497
Page 3 of 14
Eligible entities if a
joint application:
Proposed electric grid service provided:
(check all that apply)
Weatherization
technologies and
equipment
Fire-resistant
technologies and fire
prevention systems
Monitoring and control
technologies
Undergrounding of
electrical equipment
Utility pole management
Relocation of power
lines or the
reconductoring of power
lines with low-sag,
advanced conductors
Vegetation and fuel load
management
The use or construction
of “distributed energy
sources” (“DERs”) for
enhancing system
adaptive capacity during
disruptive events,
including:
x Microgrids; and
x Battery storage
subcomponents
Adaptive protection
technologies
Advanced modeling
technologies
2WKHU
Replacement of old
overhead conductors and
underground cables.
Hardening of power
lines, facilities,
substations, of other
systems; and
Xxx
xx
xx
X
X
Page 4 of 14
C. Project Narrative
1. Project Description: Required but not scored
This project will increase the resiliency of the Alaska Railbelt transmission system through construction of a
centralized, state of the art, synchrophasor data collection network for unified wide area monitoring, disruptive
event reporting and analysis and stable operation of higher penetrations of inverter based resources.
The project is a partnership of four Railbelt utilities - GVEA, CEA, MEA and HEA. Each will construct or
supplement an individual phasor data concentrator (PDC) system at their utility headquarters to collect and
store synchrophasor data from phasor measurement units (PMU) at Railbelt transmission substations. The
data from these four regional PDC systems will be shared in real time between themselves and with a central
system hosted in a secure data center.
The central system will have software applications for advanced modeling, stability analysis and disturbance
reporting. Grid operators and engineers at each utility will have concurrent access to a unified set of wide area
visualizations and alerts.
The system will improve compliance with current Alaska reliability standards and help inform grid planners and
reliability organizations with future updates to the standards.
The figures on the following pages illustrate the area covered by the system, the data collection topology and
coordinated project implementation and operation plan. Substation PMUs will be added or upgraded as
needed.
Background:
Railbelt wide disruptive oscillation events occurred between 2018 and 2021. Multiple studies and
investigations were performed to identify the cause. Recommendations were made to increase the use of
power system stabilizers / power system dampeners and to improve the accuracy of Railbelt planning models.
To improve the ongoing Railbelt oscillation remediation effort, a sub-committee of the Alaska Intertie
Operating Committee (IOC) developed a plan for a communal system to stream, store and analyze
synchrophasor data from high speed data recorders (PMU) at 12 key Railbelt substations. The PMU data
recorders are part of network of approximately $2 million of underutilized recorders installed at 45
transmission substations across the Railbelt transmission system. For the past 20 years regional
synchrophasor data networks have successfully been used throughout the Continental US electric grid for
oscillation detection, source location and situational awareness of transmission system stability. In Alaska,
CEA uses synchrophasor data to monitor areas of the South Central transmission network however the overall
Railbelt does not have a coordinated and centralized system.
In October 2022, a formal request for proposals was issued for a turn-key synchrophasor system and
advertised during a public presentation at the November NWPPA E&O Conference in Anchorage. Four
proposals were received, reviewed and ranked and and Pasadena, California based Electric Power Group
(EPG) was chosen. EPG synchrophasor and disturbance reporting software applications are used by CAISO,
PJM, ERCOT, TVA, NYISO, NERC and other regional reliability entities.
A contract with EPG has not yet been signed. Funding for a pilot project was approved in the 2024 budget of
the Intertie Operating Committee and preparations are underway.
Page 5 of 14
The system built with this project will provide two categories of capabilities -
1) Real time Applications for Situation Awareness of the Bulk Electric System:
Oscillation Detection
Intertie Phase Angle Monitoring for Power Transfer Stability Monitoring
Frequency Event Detection
Voltage Stability Monitoring
Railbelt Wide Situational Awareness
Immediate Access to a Detailed Disturbance Report after a Disruptive Event
State Estimation
2) Study Mode Applications -
Regulatory / Reliability / Renewable Plant Interconnection Compliance
Black Start / Contingency Response Training
Transmission System Model Validation and Accuracy Improvements
Power Plant Machine Model Validation and Accuracy Improvements
Post Disturbance Event Analysis and Forensics
Operator Training
Oscillation Mitigation Planning and Validation of Improvements
Project Cost:
The project will cost approximately $2 million spread over five years. The table below
is an example of expenditures each year. Depending on the project work flow, the
amounts could shift between years. The current operating budget for the Alaska
Intertie includes synchrophasor project funding that could be applied to the cash
match amount. Over the five year project schedule, the four Railbelt utilities will
contribute, on average, $23,000 each of internal labor (in-kind match). The combined
cash and in-kind labor represent 1/3 of the grant amount.
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Intertie Operating CommitteeGVEA Project ManagerGVEA Relay and ProtectionGVEA SCADA / Metering / TelecomCEA Project ManagerCEA Relay and ProtectionCEA SCADA / Metering / TelecomHEA Project ManagerHEA Relay and ProtectionHEA SCADA / Metering / TelecomMEA Project ManagerMEA Relay and ProtectionMEA SCADA / Metering / TelecomSystem Studies SubcommitteeSynchrophasor System VendorsRoles and ResponsibilitiesSystem VendorCEAMEAHEAGVEAProject ImplementationProject OperationRailbelt Cyber Security Working GroupRailbelt Reliability CouncilProject Commissioning<HDUV<HDUDQG/DWHU
Page 6 of 14
2. Population Impacted: 30% or up to 30 points
x Please provide a description of total population served by the proposed project (no
description = 0 points, less than 20,000 served = 3 points, each additional 10,000 served =
3 points with a maximum of 15 points possible).
x Please provide a description of how the proposed project will serve one or more census
tracts defined as a disadvantaged community (no description = 0 points, each census tract
is worth 3 points with a maximum of 15 points possible).
x Disadvantaged communities reporting tool
Improved resiliency of the interconnected Alaska Railbelt transmission network will benefit
a population size of approximately 550,000. The main population centers reside within
the:
Fairbanks North Star Borough, population 95,655
Matanuska-Susitna Borough, population 107,081
Municipality of Anchorage, population 287,145
Kenai Peninsula Borough, population 58,789
The Alaska Railbelt has many disadvantaged communities (DAC). Five of these, and their
census track identification numbers, are listed below.
Nenana, Tract 02290000200 ;
Fairbanks (two census tracks), 02090000300, 0209000100 ;
Houston, 02170000401 ;
Big Lake, 0217000501
In addition - Municipality of Anchorage, 10 or more DAC census tracts
A more resilient and efficient Railbelt transmission network will positively impact DAC
burdens by:
• Reducing the cost of electricity in the identified DACs
• Improving air quality via reduction of oil-fired power generation
• Providing jobs and training opportunities in surrounding DACs
• Increasing clean energy resilience state-wide and in surrounding DACS
• Increasing diversity in the workforce
• Reducing precursor emissions in an Environmental Protection Agency designated
Serious Non-Attainment Area (Fairbanks)
Page 7 of 14
x Risk Reduction/Resilience Effectiveness: 20% or up to 20 points
x Please describe how the project will reduce the current risk of disruptive events (an event
in which operations of the electric grid are disrupted, preventatively shut off, or cannot
operate safely due to capacity constraints, redundancy and/or equipment failure, etc. (not
at all = 0 points, minimally = up to 3 points, partially = up to 6 points, mostly = up to 9
points, entirely = up to 12 points, and exceeds = up to 15 points).
x A 5 point bonus will be applied to projects which improve or enhance the resilience of
transmission lines or assets of 69kV and above.
The synchrophasor system project will reduce the current risk of disruptive events,
providing:
More informative, timely and accessible analysis of disruptive events allowing for
informed application of corrective measures / reliable operating practices;
Pre-emptive detection, identification and source location of Railbelt oscillations. System
operators can take action to isolate the source and prevent a disruptive event;
Coordinated operation between regional balancing authorities;
Dynamic calculation of system inertia to ensure adequacy of contingency reserves for
primary frequency response.
Since this project is is for resiliency to the bulk electric system (BES), instead of using
the IEEE distribution system reliability indices SAIDI, SAIFI, CAIFI to quantify an
estimated reduction in disruptive events, an example is provided for the type of
disruptive events this project will help prevent and improvements to compliance with
the Alaska Reliability Standards.
Adequate reserve energy is needed for primary frequency response following a
contingency event. Without adequate generation available for primary frequency
response, the islanded Alaska grid experiences a rapid frequency decay and
widespread load shedding.
The synchrophasor system will alert system operators of low or changing system inertia
and need for additional fast spinning reserves. It will also provide detailed reports
documenting the primary frequency response of each on-line generator. This analysis
will facilitate improvement to dispatching practices to prevent under frequency events.
The synchrophasor system will provide the analysis and documentation for compliance
with Railbelt Reliability modeling (MOD) and balancing (BAL) Standards, including the
upcoming Primary Frequency Response policy.
Page 8 of 14
3. Extreme Weather, Wildfire, or Natural Disaster Event Adaptation: 15% or up to 15 points
x Please described how the proposed project would mitigate the future risk of disruptive
events whereby operations or the electric grid are disrupted, preventatively shut off, or
cannot operate safely due to extreme weather, wildfire, or natural disaster. Criterion score
should be based on a qualitative assessment of whether the narrative includes details
regarding how the project will reduce future disruptive events caused by extreme weather,
wildfire, or natural disaster (qualitative assessment; not at all = 0 points, minimally = up
to 3 points, partially = up to 6 points, mostly = up to 9 points, entirely = up to 12 points,
and exceeds = up to 15 points).
This project will mitigate the future risk of disruptive events and support reliable and safe operation of a future low carbon
Railbelt electric grid with high levels of renewable energy flowing end to end between Interior Alaska and the Kenai Peninsula.
NERC, regional reliability entities in the Continental US and utilities for isolated / islanded electric grids (Hawaii) report instability
and disruptive events caused by high penetration of inverter based resources. Reference listed on last page of this application.
The Alaska Railbelt is planning for a lower carbon future through increased integration and reliance on inverter based resources.
A recent study from the Alaska Center for Energy and Power (ACEP) envisions the Railbelt grid powered by 100% renewable
energy by 2050.
Synchrophasor data, combined with other variations of higher frequency measurements, will provide early detection and
identification of instability. This will allow system operators to notify plant personnel or take corrective action to prevent a
disruptive event.
Synchrophasor system applications will provide estimates of system strength (short circuit current), inertia, voltage stability and
IBR Ride Through Capability - key attributes of the bulk electric system impacted by inverter based resources. When these
attributes shift outside the expected ranges, the SCADA and EMS systems, used by the regional balancing authorities, can
receive alerts directly from the synchrophasor system.
Grid planning and operations engineers will benefit from improved system models validated by continuous empirical data
sampled at a high frequency.
The performance of the system and ability to reduce disruptive events will be measured and documented with ongoing
assessments.
During and following commissioning, a recurring Key Performance Indicator (KPI) report will quantify the system value.
Improvement to Railbelt Real Time Operation
1. Synchrophasor system availability / up time – how reliable is the software system
2. Number of Railbelt disturbance events captured, reported to designated recipients within xx minutes with root cause analysis
3. Number of Railbelt stability / oscillation alarms reported and acted upon by system
dispatchers.
4. Number of Railbelt oscillation sources detected.
5. Changes to Alaska Intertie capacity utilization due to real time stability reporting
6. Changes to Railbelt spinning reserve requirements due to inertia calculation
Improvements to Railbelt Engineering and Reliability Analysis
1. Number of PSS/E model checks and corrections
2. Number of Railbelt reliability standard compliance efforts – e.g... machine model validation
reports / updated performed
3. Railbelt oscillation analysis report completed with recommendations for improvements, if
needed.
4. Railbelt reserves performance analysis, inertia analysis and options for adjusting /
optimizing reserve requirements.
Page 9 of 14
4. Data Sources: 5% or up to 5 points
x Please provide a description of where the project is documented in a data-driven planning
document and/or has been identified as a provider priority via a board priority/resolution
related to system resiliency, and supporting documentation is referenced and/or the
location of any supporting documentation is referenced and/or the location of any
supporting data or narratives is provided in a linked below (not included = 0 points,
included = 2 points).
x The application should reference which climate change model substantiates predictions to
the changes of future physical environments including impacts to the safety and reliability
of providing energy to utility customers (reference excluded = 0 points, reference
included = 3 points).
Since 2022, the Railbelt synchrophasor project has been identified in Railbelt planning
documents.
The 2022 / 2023 and 2023 / 2024 budgets for the Intertie Management Committee
(IMC) included funding for a synchrophasor system pilot project. Approval of these
synchrophasor project budgets were based an extensive data-driven research into
solutions for improving resilience to inter-area oscillations. Various reports and
cost/benefit evaluations were presented to the Intertie Operating Committee (IOC) for
recommendation to the IMC.
These report and investigations include;
Synchrophasor System Memorandum Feb27_2023.pdf - recommendation to the IOC
for a turn-key project contract with Electric Power Group to provide a synchrophasor
system. Project and contract was deferred to 2024 budget.
Synchrophasor ROI Feb15_2023.xlsx - return on investment analysis of pursuing a
synchrophasor project. Contains a list of benefits and annual value.
Analysis of Low Frequency Oscillations in Alaska Railbelt System, Siemens PTI, May
2020
Budget planning and justification memos, Intertie Management Committee, 2023 and
2024
Climate Model:
https://uaf-snap.org/
https://arcticeds.org/report/community/AK382#results - GFDL-CM3 RCP 4.5, 6.0 and
8.5 (NOAA coupled climate model)
Page 10 of 14
5. Implementation Measures: 15% or up to 15 points
The application should include a detailed project schedule that includes design, permits, site control,
and construction timeframe breakouts.
x The application schedule should indicate whether the project will go to construction within
the desired 5-year period of performance. (Construction timeframe not addressed = 0 points,
construction is not proposed within the 5-year period of performance = 0 points, construction
is proposed within the 5-year period of performance = up to 2 points).
x The application schedule should include an appropriate level of detail and proposed
timeframes should be adequate and reasonable, including project staff experience and
availability of staff time during the proposed project period (details and timeframes are not
included = 0 points, schedule details and proposed timeframes are minimally addressed = up
to 3 points, schedule details and proposed timeframes are adequate and reasonable = up to 5
points).
x The application should include a reasonably specific and/or detailed explanation of the extent
to which an eligible entity plans to utilize project labor agreements, local hire agreements,
and/or has or will develop a plan to attract, train, and retain a local workforce including
minority/women owned businesses (explanation excluded = 0 points, specific/detailed
explanation included = up to 5 points).
This project will start and complete within five years of the grant award. Refer to the detailed project schedule included with this application.
The project consists of three phases.
Phase 1 - April 2, 2024 through November 20, 2025
a. Utilities, with assistance from EPG, will complete setup or modification of local phasor data concentrators
b. Setup and commissioning of secure central server with software applications
c. Setup and commissioning of secure communication data links between utilities and central system.
Phase 2 - March 2, 2026 through June 15, 2028
a. Add PMUs as needed.
b. Commission or tune remaining software applications not completed during initial phase
Phase 3 - June 16, 2028 through April 27, 2029
a. Add PMUs as needed.
b. Commission and tune applications for improved monitoring and stability assessment of renewable energy projects (Inverter Based
Resources).
The Railbelt Synchrophasor and Event Reporting project will provide an overall economic benefit, increase reliability, and facilitate
development and operation of new clean energy projects across the Alaska Railbelt. The project will utilize the local work force of each of the
Railbelt utilities and specialty services from synchrophasor system contractors. Within each utility, the job clarifications expected to participate
in this project include - engineers, system dispatchers, electricians, IT staff, project accountants, drafting, GIS technicians and various
administrative staff.
The project will help the Alaska Railbelt utilities attract, train and retain engineering and technical staff by providing exposure and experience
with software tools and technology in wide use in other regions of the US electric grid and not in wide use in Alaska.
The Workforce:
Project work will performed under collective bargaining agreements with the International Brotherhood of Electrical Workers (IBEW) and the
International Union of Operating Engineers (IUOE). Each utility has collective bargaining agreements with the respective unions and personnel
are classified differently at each utility.
Wages:
This project will support the local economy through the recognition of organized labor and the provision of prevailing wages. The Railbelt
utilities work with workforce development partners and labor unions to form agreements that protect workers’ rights and pay them fair,
equitable wages for the work being performed.
Page 11 of 14
6. Community Engagement: 5% or up to 5 points
x The application should reference any utility public outreach plan for electronic and/or in-
person stakeholder and public outreach associated with identification and development of the
project (reference excluded = 0 points, reference included = up to 5 points).
A one hour public presentation of this project was delivered at the November 2022
Northwest Power Producers Association (NWPPA) annual conference in Anchorage.
The conference attendees were from utilities throughout Alaska and other
stakeholders interested in the future of Alaska's electric grid. A copy of the
presentation is attached for reference.
Future outreach to the public and other stakeholders include:
1) In-person meetings with the Member Advisory Committees (MAC) of GVEA and
CEA;
The MAC consists of utility customers selected to represent the customer base and
provide input / feedback to utility planning / project efforts.
2) A project update presentation at the 2024 NWPPA Conference and other Alaska
utility industry groups;
3) Public presentation, discussion and comments during meetings of the Intertie
Management Committee, Intertie Operating Committee and Bradley Lake Project
Management Committee ;
4) Public presentation and comment period for the Alaska state budget (if cash match
is included in Intertie budget versus direct contributions from each utility);
5) Presentation and discussion during meetings of the MEA, CEA, HEA and GVEA
board of directors. These meetings are open to utility member-customers which is the
majority of the Alaska population.
Page 12 of 14
7. Leveraging Partnerships: 10% or up to 10 points
Please include letters of support from partner organizations (letters of support excluded = 0
points, reference included = 2 points).
Please include a description of how the applicant will provide matching funds (e.g., in-kind and/or
cash contributions) that are equal to 1/3 or more of the federal share of the project cost (non-
federal matching funds equal to 1/3 of federal share = 4 points, every 5% greater than 1/3 of
federal share = 1 additional point with a maximum of 8 points possible).
This project and grant application is supported by the Intertie Management
Committee (IMC) and the Intertie Operating Committee (IOC) whose members
include GVEA, MEA, CEA and AEA. The project is also supported by HEA. The
following two pages are letters of support from the chairs of both committees and
HEA.
The total project cost and percentage of matching funds are summarized in Section B
(page 2) of this application. The matching funds consist of 85% in-kind labor and 15%
cash contributions. A complete and detailed list of all project costs and funding
source is in the document "Synchrophasor System Cost Estimate.xlsx" included with
this application. The four Railbelt utilities will agree on a method to split the in-kind
labor and cash match.
Page 13 of 14
LIST OF ADDITIONAL DOCUMENTATION SUBMITTED FOR CONSIDERATION
In the space below, please provide a list of additional information submitted for consideration.
The undersigned certifies that this application for a resilience grant is truthful and correct,
and that the applicant is in compliance with, and will continue to comply with, all federal
and state laws including existing credit and federal tax obligations and that they can
indeed commit the entity to these obligations.
Print Name
Signature
Title
Date
1. Synchrophasor System Cost Estimate.xlsx
2. Synchrophasor System Project Completion Schedule.pdf
3. EPG Year in Review
4. Synchrophasor System - IMC presentation to NWPPA E&O Conference
5. NERC investigation IBR disruptive events and recommendations for improved
monitoring and analysis
Keith Palchikoff
Page 14 of 14
Submission
Completed applications must be submitted by email or physical delivered to AEA by PM on
February 16th, 2024.
Applicants may either submit their applications by (1) attaching their application and supporting
documents to an email and sending it to the AEA grants coordinator, or (2) by having their applications
physically delivered to AEA.
Applicants choosing to submit their application via email are asked to address the email to
grants@akenergyauthority.org with the subject line of “IIJA 40101(D) Subaward Application”.
Applicants are asked to submit the application and applicable documentation in searchable PDF or other
word searchable electronic format. Applicants using this method are encouraged to use delivery receipt
and read receipt. It should be noted that AEA’s email system limits attachments to 40MB and will not
accept .zip files or executables.
Applicants choosing to submit their application via physical delivery method are asked to submit one (1)
electronic version on an electronic storage device (i.e., CD/DVD or thumb drive) in a searchable PDF or
other word searchable electronic format.
Additionally, if a hard copy of the completed application is submitted, AEA requires that the hard copy be
double-sided with minimal binding, including appendices that can be duplicated. Physical delivery of
either of the above must be in a sealed envelope(s) clearly labeled:
From: Applicant Return Address
To: Alaska Energy Authority
Renewable Energy Fund Grant Application
813 West Northern Lights Blvd
Anchorage, AK 99503
Any questions or concerns about filing an application should be directed to:
Grants Coordinator
Alaska Energy Authority
Direct Phone: (907) 771-3081
AEA Main Phone: (907) 771-3000
Email: grants@akenergyauthority.org
Railbelt Synchrophasor and Disturbance Reporting System Version:1By:KEPUpdated:2/2/2024Number Materials Total Number Burdened Total Projectof Unit Cost Materials of Extended Labor Rate Labor TotalUnits Description ($) ($) Personnel Hours Man-Hours ($/Man-Hr) ($) CostEngineering Design / Permits / Site Control Costs4 Project Design - Utility Engineering, In-Kind $0.00 $0.00 1 40 160 $122.00 $19,520.00 $19,520.00 In-Kind1 Project Design - Synchrophasor System Contractor $100,000.00 $100,000.00 0 0 0 $300.00 $0.00 $100,000.00 Grant4 Networking and Communication Design, In-Kind $0.00 $0.00 1 20 80 $130.00 $10,400.00 $10,400.00 In-Kind4 As-Built Drawings and Documentation - Utility, In-Kind $0.00 $0.00 1 16 64$81.50 $5,216.00 $5,216.00 In-KindSub-Total: $0.00 $100,000.00 0 0 $35,136.00 $135,136.00Sub-Total + 10% Contingency$148,649.60Construction Labor:2Utility PDC Server Setup, In-Kind$0.00 $0.00 1 8 16 $122.00 $1,952.00 $1,952.00 In-Kind4Utility PDC Software Setup, In-Kind$0.00 $0.00 1 10 40 $122.00 $4,880.00 $4,880.00 In-Kind4 Utility Project Management,One per Utility, In-Kind $0.00 $0.00 1 4001600 $122.00 $195,200.00 $195,200.00 In-Kind1Contractor's Project Manager$60,000.00 $60,000.00 0 0 0 $0.00 $0.00 $60,000.00 Grant1Synchrophasor Server Setup$10,000.00 $10,000.00 0 0 0 $0.00 $0.00 $10,000.00 Grant1 Sychrophasor Application Installation and Setup $100,000.00 $100,000.00 0 0 0 $0.00 $0.00 $100,000.00 Grant1 Sychrophasor Application Commissioning $200,000.00 $200,000.00 0 0 0 $0.00 $0.00 $200,000.00 Grant3 Sychrophasor System Training $20,000.00 $60,000.00 0 0 0 $0.00 $0.00 $60,000.00 Grant4 Networking and Communication Circuit Setup, In-Kind $0.00 $0.00 1 40 160 $130.00 $20,800.00 $20,800.00 In-KindSub-Total: $390,000.00 $430,000.00 458 1816 $222,832.00 $652,832.00Sub-Total + 10% Contingency$718,115.20Construction Materials:1 Data Center Server $100,000.00 $100,000.00 0 $0.00 $0.00 $100,000.00 Grant1 Software Licenses $490,000.00 $490,000.00 0 $0.00 $0.00 $490,000.00 Grant + Cash Match1 Data Storage Array $100,000.00 $100,000.00 0 $0.00 $0.00 $100,000.00 Grant8 Tesla 4000 PMU or Equivalent $30,000.00 $240,000.00 0 $0.00 $0.00 $240,000.00 Grant2 Utility PDC Server, Cash Match $5,000.00 $10,000.00 0 $0.00 $0.00 $10,000.00 Cash2 Utility PDC Storage, Cash Match $15,000.00 $30,000.00 0 $0.00 $0.00 $30,000.00 CashSub-Total: $0.00 $970,000.00 0 0 $0.00 $970,000.00Sub-Total + 10% Contingency$1,067,000.00Administrative4 Contracting and Legal Review , In-Kind $0.00 $0.00 1 20 80 $300.00 $24,000.00 $24,000.00 In-Kind4 Purchasing - Parts Procurement, In-Kind $0.00 $0.00 1 20 80 $100.00 $8,000.00 $8,000.00 In-Kind4 Project Accounting, In-Kind $0.00 $0.00 1 250 1000 $120.00 $120,000.00 $120,000.00 In-KindSub-Total: $0.00 $0.00 290 1160 $152,000.00 $152,000.00Sub-Total + 10% Contingency$167,200.00Miscellaneous:4 Miscellaneous Office Equipment and Administrative Staff, In-$2,000.00 $8,000.00 1 125 500 $75.00 $37,500.00 $45,500.00 In-KindSub-Total: $0.00 $8,000.00 705 2820 $37,500.00 $45,500.00Sub-Total + 10% Contingency$50,050.00Totals:$490,000.00 $1,508,000.00 6,156 $447,468.00Subtotal $1,955,468.00 Contingency $195,546.80Project Total $2,151,014.80Per YearGrant $1,617,304 $323,461One-Third Match $533,710 $106,742 % SplitIn-Kind Portion of Match $455,468 $91,094 85%Cash Match $78,242 $15,648 15%FundingTotal Project
Year Project CostRailbelt Utilities Combined Cash MatchRailbelt Utilities - In Kind ContributionGrant Contribution1$430,203 $15,648 $91,094 $323,4612$430,203 $15,648 $91,094 $323,4613$430,203 $15,648 $91,094 $323,4614$430,203 $15,648 $91,094 $323,4615$430,203 $15,648 $91,094 $323,461Sub-Totals$2,151,015 $78,242 $455,468 $1,617,304Grant Amount$1,617,304Utility Match$533,710In-Kind Per Utility$113,867Cash per Utility$19,561Five Year Average Project Expenditures by Year
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December 19, 2023
2023 was another active year for Electric Power Group (EPG). The electric industry is at an important
inflection point with the growth in renewables, distributed energy resources and energy transition
initiatives rapidly increasing. To manage this transition, utilities and grid operators are actively investing
in new infrastructure and technologies to ensure grid reliability. For real-time operations, the
management and integration of renewables are a key focus as oscillations and other destabilizing power
system conditions have grown in lockstep with renewables. Synchrophasor technology, with its high-
resolution data rates of 30-60 samples per second, is increasingly becoming the “go-to” solution to
monitor and manage oscillations, invertor-based resources, system inertia, and frequency response.
As the leader in Synchrophasor Technology for more than 20 years, EPG customer activity and
engagement was strong all year. Over the past year, EPG supported customers across North America,
Europe, the Middle East, India, Southeast Asia and Australia. Customer initiatives included:
WAMS and Oscillations Monitoring
x GETCO –EPG, as a sub-contractor to Hitachi Energy, is the sole WAMS software supplier to GETCO
in India for the world’s largest WAMS system with capacity for 1,650 PMUs. EPG successfully
completed Site Acceptance, with project completion expected in early 2024. The WAMS project
at GETCO is state-of-the-art and was the recipient of the India Smart Grid Forum Award.
x TRANSCO – EPG is completing a WAMS project for TRANSCO in Abu Dhabi. EPG is the sole WAMS
software provider, the second such deployment to a member of the GCCIA.
x Dominion – EPG deployed its WAMS platform for use in real-time operations at Dominion.
x ElectraNet – EPG kicked-off a WAMS project for ElectraNet, a leading transmission utility in
Australia. Project is expected to be completed in 2024 and includes PMU data integration with
AEMO and deployment of Inertia Monitoring and System Strength applications.
x Scottish Power – In partnership with GPA, EPG’s Oscillation Monitoring, Detection and Source
Location Software was deployed at Scottish Power.
x PEA – EPG is working with PEA, a distribution company in Thailand, on a WAMS pilot to collect
data from microPMUs, monitoring wind and solar farms; perform offline analysis; and
demonstrate oscillations and IBR ride-through performance.
x Existing Customer Upgrades – Several of our customers, including CAISO, Duke Energy, ERCOT,
NYISO, PJM, SPP and TVA took advantage of the latest version of our software. The most recent
version includes advanced algorithms for Oscillations, including Source Location capabilities.
Integration of Solar Plants
x Shell – EPG kicked-off a project with Shell Energy to deploy an ePDC solution in two data centers
to collect PMU data from several solar plants and share that information with PJM.
x GREENKO – EPG kicked-off a project for GREENKO, a green energy company operating in India.
EPG will deploy its PhasorSmart solution to integrate and collect, visualize,and monitor PMU data
from a solar plant in India.
Linear State Estimator
x Dominion – Following a successful two-year WAMS/LSE pilot, EPG kicked-off a production grade
project to deploy a Synchrophasor based EMS system including LSE, RTCA, and Real-time
Assessments applications.The project is phased with the first two phases nearing completion, and
final solution deployment planned for 2025.
x TVA – EPG has deployed its LSE for a pilot project at TVA, which is currently undergoing testing
and validation. The primary use case is for the LSE to serve as an independent system to EMS.
x AEP – The LSE deployment at AEP has been completed. This is a unique, first of its kind
deployment which covers three different reliability coordinator footprints to provide a unified
solution for AEP Operations. Planning is underway for further integration and upgrades for AEP.
WAMPAC
x Network Rail – EPG completed a project for Network Rail, the largest rail operator in the United
Kingdom, which included deployment of its PhasorSmart platform to monitor phase angles for
the rail system and send alarms to Network Rail’s SCADA system for line closing control action.
Generator Model Validation
x PJM –EPG deployed its Automated Generator Model Validation (GMV) softwarein the Production
environment. GMV allows users to perform the required model validation using PMU data
without having to take generator units offline. The model validation process is fully automated,
performed in near real-time, and is triggered when events and system disturbances are detected.
Application is designed to facilitate NERC reporting requirements.
x NYPA – EPG kicked-off a pilot project of the GMV solution at NYPA at a large hydro plant.
Engineering Analyses: Oscillations Event and PMU Data Analysis
x Oscillation Event Analysis for CAISO and Chile ISO – Oscillations are increasing with greater
invertor-based resources. EPG performed event analysis for CAISO and the ISO in Chile to study
and assess how the power system behaved. These studies provide system operators, support
engineers and planning personnel data on potential system vulnerabilities to guide operating
procedures and capital investment activity.
x PMU Data Analysis – As a part of EPG’s ongoing support services, EPG analyzed PMU data for
both ERCOT and OETC to identify significant events in their systems and make recommendations
of fine-tuning alarms and configurations,such that operators continueto have the most pertinent
information available.
Synchrophasor Integration Activities
x NYISO CIM –EPG executed a project for NYISO to integrate its CIM into EPG’s WAMS to streamline
NYISO’s PMU naming and data sharing across its EMS/SCADA and WAMS.
x Bi-Directional WAMS-EMS Integration at GETCO –EPG implemented a first of its kind integration
of EMS/SCADA into the GETCO WAMS system, its platform for the future. The WAMS visualization
displays EMS/SCADA information side-by-side on single line diagrams in WAMS.
x PI Integration at BPA and SRP – EPG deployed its PI integration adapter to seamlessly integrate
PMU data exchange with the existing PI historian.
NERC / DOE Projects
x NERC –EPG completed a major upgrade of several applications for NERC, which are deployed and
managed by EPG in a secure data center. EPG has been working with NERC for more than 20 years.
x ESAMS – Demonstration of the Eastern Interconnection Situational Awareness Monitoring
System (ESAMS), a platform for real-time notifications of oscillations and phase angles across the
Eastern Interconnection was completed in 2022. EPG deployed ESAMS at Southern Company in
2023. ISO-NE and PJM are evaluating next steps for a cloud deployment of ESAMS in 2024.
x ARPA-E Oscillations Project – Successfully completed the ARPA-E project in collaboration with
UW-Madison.
EPG Application Enhancements and Development
x IBR Ride-through Capability – Implemented the ability to analyze IBR ride-through and dynamic
voltage recovery. Analysis has been automated in PGDA, EPG’s offline analytics tool, which can be
launched and triggered from RTDMS in real-time. Capability will be deployed at ComEd in 2024.
x Oscillation Source Location (OSL) Analysis – OSL using Dissipating Energy flow and Harmonics
implemented in PGDA.
x PV Curve Enhancement – Built PV Curve capabilities into RTDMS. Enhancement is being
implemented at TRANSCO.
x FFT Plot –Real-time FFT Analyticsbuilt into the latest release of RTDMS. Currently in use at NYISO.
x PGDA Integration with RTDMS – EPG’s PGDA tool has been integrated with EPG’s RTDMS (WAMS)
platformwhich allows for seamless sharing of events and data. Events captured in real-time using
RTDMS can be triggered and further analyzed in PGDA.
x 2024 Key Road Map Items – Major roadmap enhancements and development items include
Inertia Monitoring, System Strength, and Generator Model Validation for IBRs.
EPG Led Industry Education and Participation
x EPG Webinars – Hosted monthly webinars in 2023 on topics ranging from LSE, Oscillations, IBRs,
WAMPAC, Inertia Monitoring, Generator Model Validation, Machine Learning, Event Analytics
Integration, and Operator Training with guest speakers from EPG customers AEP, CAISO, Duke
Energy, PJM, and TVA.
x Technical Presentations – EPG made presentations and participated in panel discussions across
multiple forums, including NASPI, NERC SMWG, Lehigh Seminar, DOE Power Sector Data Summit,
ARPA-E Grid Software Conference, and IEEE.
x Working Groups and Standards Development –Active participant across NERC, NASPI, IEEE PSRC,
and CIGRE working groups. EPG team members led the development of the IEEE standard P2664
for the STTP protocol and a report on distribution PMU requirements, which is expected to be
included in an upcoming IEEE standard.
x LSE Book Contribution – Co-authored a book chapter with AEP titled "Linear State Estimator for
the Control Room - AEP's Experience”. The chapter will be featured in an upcoming book titled
“Experiences on use of State Estimation in Power System Grid Operations”.
As we look ahead, we expect many of the industry trends to gain momentum in 2024. EPG continues to
make significant investments in our solutions, our people and infrastructure to support the needs of our
growing customer base. In 2023, EPG formed EPG International Private Limited based in India, to help
support the needs of customers in the Middle East, South Asia and Asia-Pacific regions.
We are grateful for the opportunity to support you and look forward to connecting with you in the New
Year. From all of us at EPG, we wish you Happy Holidays and a Happy New Year.
With gratitude,
The EPG Team
SynchrophasorSystemJohn Bell, CEAMike Tracy, HEANathan Greene, MEAKeith Palchikoff, GVEAWilliam Price, AEANWPPA E&O Conference, AnchorageNovember 3, 2022INTERTIE MANAGEMENT COMMITTEE
OutlineIntroduction of System Studies Subcommittee – John Bell, ChairBackground of Railbelt Oscillation Analysis and Remediation - John BellSynchrophasor Data - Mike TracyRailbelt Project – Keith PalchikoffRailbelt Applications – Keith PalchikoffConclusion – John BellUsing Synchrophasor Data for Phase Angle Monitoring, North American Synchrophasor Initiative, Control Room Solutions Task Team Working Document, May, 2016
SSS IntroductionFirst Intertie Agreement signed in 1985. Subcommittees formed to coordinate projects.Maintains the Railbelt power system model.Manages studies related to Railbelt stability and reliability.Engineering staff from all utilities.Alaska Energy AuthorityChugach ElectricGolden Valley ElectricHomer ElectricMatanuska ElectricIMC Intertie Management CommitteeIOC Intertie Operating CommitteeSSS System Studies Subcommittee
Railbelt Reliability –Oscillation StudyThe SSS studied Railbelt inter-area oscillations with Siemens in 2019.The Siemens study recommended settings for oscillation damping equipment on transmission systems and generation.Settings adjustments were performed, but the SSS needed a method to measure the improvement to system stability.Siemens recommended more dynamic model validation for studying oscillations.
Railbelt Reliability –Forced OscillationsForced oscillations observed during 2020 and 2021.Longer duration, lasting several minutes.Larger power swings, up to 223 MW.Utilities had difficulty identifying the ‘driver’ of the oscillations.Indicated need for monitoring of generators for oscillation participation
www.vecteezy.com/free-vector/alaskahttps://www.naspi.org/Solution -Harness Synchrophasor Technology
Synchrophasor …what is it?“Synchrophasor” = Synchronized + PhasorA complex number representing an analog value that contains magnitude, phase, and a very precise timestamp, that is sampled at a very high rate.High sampling rate facilitates system monitoring and analysis at a level not captured by SCADA.Synchronicity allows for accurate wide area monitoring and analysis in real time, and comprehensive post-event reconstruction and analysis.BPA, “Synchrophasor Installations and Applications at BPA,” NERC SMS Meeting, September 2015.
Synchrophasor Milestones1893 Charles Steinmetz, an engineer at GE, introduced the concept of “phasor” to characterize electrical waveforms in 1893 in a paper entitled “Complex Quantities and Their Use in in Electrical Engineering”1973 Global Positioning System 1979 Symmetrical Component Distance Relay (SCDR) and Symmetrical Component Discrete Fourier Transform (SCDFT) - A. Phadke1988 first synchrophasor prototype constructed1992 first commercial synchrophasor unit.2009 American Recovery and Reinvestment Act (ARRA)“Currently, there are synchrophasor measurement systems in every developed country worldwide” –IEEE Electrification Magazine, March 2021
Synchrophasor Components & Processes
Extant Railbelt Synchrophasor ResourcesERL Phase Disturbance Fault Recorders40+ installations and growingMost Schweitzer Engineering Laboratories (SEL) relays, they are widely deployed throughout the RailbeltRailbelt utilities already have the peripheral devices, what’s needed now is a communications network, an automated centralized data repository, and a means by which Railbelt utilities have access to real-time, system-wide, high speed data, and the tools to interpret that data.
The Railbelt Synchrophasor Project2020•Identify a Need2021 2022•Find a Solution2023• Implement and Test
Pilot Project Scope Defined in RFPObjective:Turn key, scalable, cloud hosted software service to reliably collect, store and interpret Railbelt synchrophasor data for communal access and visibility by transmission system operators and planning, operations and reliability engineers. Big DataAwareness InsightsActionBig Data
Pilot Project Scope Defined in RFPUse cases: Real time, wide area situational awareness for communal and coordinated use by grid operators / grid support engineersCoordinated analysis of Railbelt performance, modes, stability and system models - reliability and planning engineersAwareness InsightsActionBig Data
Pilot Project Scope Defined in RFPVendor Responsibilities:Deliver software as a service (SAS) subscription to NERC CIP compliant, centralized, cloud hosted synchrophasor system - server infrastructure, OS, database, storage and useful, out of the box applications and reports;Provide ongoing software support, education and training for end usersAwareness InsightsActionBig Data
Pilot Project Existing PMU LocationsGoldhill Substation - GVEAWilson Substation - GVEAHealy Substation – GVEA / AEADouglas Substation – MEA / AEATeeland Substation - CEAEklutna Generating Station – MEAUniversity Substation - CEAQuartz Creek Substation – CEABernice Lake / Nikiski plant - HEASoldotna Substation - HEABradley Lake Hydro plant – HEA / AEASullivan Power Plant (Plant 2) - CEAPilot Project Scope -Geography
Alaska Railbelt Synchrophasor Data and ApplicationsCEA PDCPMUPMUGVEA PDCStart with a pilot project = 12 Substations and Power PlantsHEA PDCMEA PDCPMUPMUPMUPMUPMUPMUPMUPMUPMUPMUSynchrophasor Cloud TopologyAlaska Railbelt SynchrophasorData and ApplicationsCEA PDCGVEA PDCHEA PDCMEA PDCPMMUVendor Scope
BenefitsCommunal infrastructure and accessScalable – pilot project may require 3 TB storage per year of online dataSubscription service – avoid IT capital investment / maintenanceFast project implementationRobust reliability and security – data backups, geographic diversityFacilitate access from backup control centers Administration of user access and permissions distributed between each utility.Cloud Computing and StorageAlaska Railbelt Synchrophasor Data and Applications
On Premise Central PDC to Cloud Data Center – IPsec VPN with plain Internet service or dedicated leased circuits? Coordinated with vendor to achieve required performance, latency and cost.Substation PMUs to Utility’s On Premise Central PDC– Utility’s internal communication networks – typically Ethernet but serial allowedCloud Data CommunicationCourtesy of Schweitzer Engineering Labs - https://selinc.com/Three separate underwater fiber optic cables and one one newer terrestrialfiber optic cable (MTA 2020) connect the Railbelt to the Lower 48 datanetworks.
How Do We Establish Compliance Upfront?Independent / third party verificationUse accepted standards - FedRAMP and NIST SP 800-53 Rev 4Railbelt utility (RCSWG) and synchrophasor system vendor SMEProject components are segregated and have no direct control functions.**Classify by use – “Control” for operational decision making – “Data” for information-only, post-event analysis**https://learn.microsoft.com/en-us/azure/azure-government/documentation-government-plan-securityData Security and Cloud CIP Compliance** Microsoft Azure
20+ Year Evolution of Two General Category of ApplicationsOnline / Real timeWide Area Monitoring and Decision Support System for Grid OperatorsGeographic / spatial displays, one-line diagrams, trend lines and tabular reports. Option to exchange data with EMS/SCADA system.Offline / Power System Engineering and PlanningBack office, non-immediate analysis – model validation, disturbance event forensics and reporting, data mining and research on grid dynamics and reliabilityOperator training simulatorApplications
Unified Railbelt Operation and Situational AwarenessAnticipate, Respond and Recover Like Moving from X-ray to MRI technologyCommunal Synchrophasor SystemEMS / SCADA / Inter-Area Communication and CoordinationReal Time Applications –Wide Area Monitoring SystemFuture integration?
Early warning of dynamics issues not readily observed in EMS. Transforming high resolution, synchronized phasor data into actionable information enabling proactive system stability management. Oscillation Detection and Source LocationPhase Angle Monitoring and AlarmingReal-time Effective Inertia -Important for Small Grids and High Penetration of Inverter Based ResourcesWide Area Monitoring (WAMS) ApplicationsRailbelt Pilot Project
Response times can be reduced with oscillation source location tools. Once responsible equipment is identified, corrective action can be takenSource location is a challenging problemAmplitude not always largest at the sourceMany solutions have been proposedWAMS -Oscillation Detection and Source Location
Indication of system loading and stressVisualize Transfer LimitsExpedite Reconnection After IslandingPhase Angle Monitoring and AlarmingKenaiSouth CentralInteriorHEACEAMEAGVEA
Event Analysis / Forensics / Standardized Reporting and RepositoryFrequency Response and Effective InertiaDynamic and Steady State Model ValidationDetailed Investigation and Reporting of Oscillation Modes and Location of Contributing SourcesOffline Applications
Disturbance Reporting Systemhttps://www.naspi.org/sites/default/files/2018-11/pjm_murphy_esams_20181023.pdfExample from An Established System
Model Improvements
In 2021, the IOC System Studies Subcommitteecommissioned a study of Contingency Reserveperformance requirements on the Railbelt…Reserves = $$ and possible Railbelt load shedding and power quality problemsAKRES-001-2 standard references a Reserves Policy –assign Primary Frequency Response rating to each Railbelt machine and allocate reservesFuture standby reserves from large BESS – has cost impacts on battery wear, warranties and capacity available for renewable integration purposes. Source: Eto, et al. LBNL: Use of a Frequency Response Metric to Assess the Planning and Operating Requirements for Reliable Integration of Variable Renewable GenerationFrequency Response and Effective Inertia
#Activity Date1Issue RFP document October 28, 20222RFP Response dueDecember 2, 20223Vendor presentations (shortlisted vendors)December 20224Contract Award January 20235Project Kick-off February 20236Project Planning March, 20237Setup and Configuration May, 20238Initial System Acceptance Testing (ISAT) 4 PMUsJune, 20239Begin Phase II (Remaining 8 PMUs) July, 202310Complete Phase II (Full Pilot System Deployment)August, 202311Final Pilot System Acceptance Testing (FSAT)September, 2023Project Implementation to occur in two phases:1) Configure cloud system, central PDCs and connect to one PMU per utility. Commission and verify functionality –Initial System Acceptance2) Connect remaining 8 PMUs and re-verify functionality with more data streams and grid visibility – final acceptance testingProject Schedule
Roles and ResponsibilitiesIntertie Operating CommitteeCEA Project ManagerCEA Relay and ProtectionCEA SCADA / Metering / TelecomHEA Project ManagerHEA Relay and ProtectionHEA SCADA / Metering / TelecomMEA Project ManagerMEA Relay and ProtectionMEA SCADA / Metering / TelecomSystem Studies SubcommitteeGVEA Project ManagerSynchrophasor System VendorGVEA Relay and ProtectionGVEA SCADA / Metering / TelecomSystem VendorCEAMEAHEAGVEAProject ImplementationProject OperationRailbelt Cyber Security Working GroupRailbelt Reliability CouncilProject Commissioning
Information Overload / Avoiding ComplexitySignal Naming Convention for Data SharingCoordination Between Multiple Utilities and PersonnelTime and Resources for Effective Project Implementation and Ongoing Improvements –Support from Utility And Railbelt ManagementTraining and Acceptance – Learning Curve and AdoptionChallenges
•Communal synchrophasor system enables •Railbelt reliability improvements•Railbelt collaboration and coordination•Improved planning and utilization of resourcesConclusion
813 W Northern Lights Blvd.Anchorage, AK 99503Main: (907) 771-3000Fax: (907) 771-3044akenergyauthority.org@alaskaenergyauthority@alaskaenergyauthorityAlaska Energy AuthorityAEA provides energy solutions to meet the unique needs of Alaska’s ruraland urban communities.33