HomeMy WebLinkAboutAPP_13017-REF R13 StdAppForm_PBVCRenewable Energy Fund Round 13
Grant Application – Standard Form
AEA 21010 Page 1 of 32 7/20/2020
Application Forms and Instructions
This instruction page and the following grant application constitutes the Grant Application Form for Round
13 of the Renewable Energy Fund (REF). A separate application form is available for projects with a primary
purpose of producing heat (see Request for Applications (RFA) Section 1.5). This is the standard form for all
other projects, including projects that will produce heat and electricity. An electronic version of the RFA and
both application forms is available online at: www.akenergyauthority.org/what-we-do/grants-
loans/renewable-energy-fund-ref-grants/2020-ref-application.
What follows are some basic information and instructions for this application:
The Alaska Energy Authority (AEA) expects this application to be used as part of a two-year solicitation
cycle with an opt-out provision in the second year of the cycle.
If you are applying for grants for more than one project, provide separate application forms for each
project.
Multiple phases (e.g. final design, construction) for the same project may be submitted as one
application.
If you are applying for grant funding for more than one phase of a project, provide milestones and grant
budget for each phase of the project (see Sections 3.1 and 3.2.2).
In order to ensure that grants provide sufficient benefit to the public, AEA may limit recommendations
for grants to preliminary development phases in accordance with 3 Alaska Administrative Code (ACC)
107.605(1).
If some work has already been completed on your project and you are requesting funding for an
advanced phase, submit information sufficient to demonstrate that the preceding phases are
completed and funding for an advanced phase is warranted. Supporting documentation may include,
but is not limited to, reports, conceptual or final designs, models, photos, maps, proof of site control,
utility agreements, business and operation plans, power sale agreements, relevant data sets, and other
materials. Please provide a list of supporting documents in Section 11 of this application and attach the
documents to your application.
If you have additional information or reports you would like the Authority to consider in reviewing your
application, either provide an electronic version of the document with your submission or reference a
web link where it can be downloaded or reviewed. Please provide a list of additional information;
including any web links, in Section 12 of this application and attach the documents to your application.
For guidance on application best practices please refer to the resource-specific Best Practices
Checklists; links to the checklists can be found in the appendices list at the end of the accompanying
REF Round 13 RFA.
In the Sections below, please enter responses in the spaces provided. You may add additional rows or
space to the form to provide sufficient space for the information, or attach additional sheets if needed.
If you need assistance with your application, please contact AEA’s Grants Manager Karin St. Clair by
email at grants@akenergyauthority.org or by phone at (907) 771-3081.
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Grant Application – Standard Form
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REMINDER:
AEA is subject to the Public Records Act AS 40.25, and materials submitted to AEA may be subject to
disclosure requirements under the act if no statutory exemptions apply.
All applications received will be posted on the Authority web site after final recommendations are
made to the legislature. Please submit resumes as separate PDFs if the applicant would like those
excluded from the web posting of this application.
In accordance with 3 AAC 107.630 (b) Applicants may request trade secrets or proprietary company
data be kept confidential subject to review and approval by AEA. If you want information to be kept
confidential the applicant must:
o Request the information be kept confidential.
o Clearly identify the information that is the trade secret or proprietary in their application.
o Receive concurrence from the Authority that the information will be kept confidential. If the
Authority determines it is not confidential, it will be treated as a public record in accordance
with AS 40.25 or returned to the applicant upon request.
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SECTION 1 – APPLICANT INFORMATION
Please specify the legal grantee that will own, operate, and maintain the project upon completion.
Name (Name of utility, IPP, local government, or other government entity)
Pedro Bay Village Council
Tax ID # 92-0074409
Date of last financial statement audit: N/A
Mailing Address: Physical Address:
PO Box 47070 COUNCIL BUILDING
PEDRO BAY, AK 99647 PEDRO BAY, AK 99647
Telephone: Fax: Email:
907-850-2225 907-850-2221 J.BAALKE@PEDROBAY.COM
1.1 Applicant Point of Contact / Grants Manager
Name: JOHN BAALKE Title: VILLAGE ADMINISTRATOR
Mailing Address:
PO Box 47020
PEDRO BAY, AK 99647
Telephone: Fax: Email:
907-242-3076 907-850-2221 J.BAALKE@PEDROBAY.COM
1.1.1 Applicant Signatory Authority Contact Information
Name: KEITH JENSEN Title: PRESIDENT
Mailing Address:
PO Box 47020
PEDRO BAY, AK 99647
Telephone: Fax: Email:
907-850-4041 907-850-2221 KEITH.JENSEN@PEDROBAY.COM
1.1.2 Applicant Alternate Points of Contact
Name Telephone: Fax: Email:
JOEL GROVES 907-258-2420X204 907-258-2419 JOEL@POLARCONSULT.NET
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1.2 Applicant Minimum Requirements
Please check as appropriate. If applicants do not meet the minimum requirements, the application will be
rejected.
1.2.1 Applicant Type
☒ An electric utility holding a certificate of public convenience and necessity under AS 42.05
CPCN #662___, or
☐ An independent power producer in accordance with 3 AAC 107.695 (a) (1)
CPCN #______, or
☐ A local government, or
☒ A governmental entity (which includes tribal councils and housing authorities)
Additional minimum requirements
☒ 1.2.2 Attached to this application is formal approval and endorsement for the project by the
applicant’s board of directors, executive management, or other governing authority. If the applicant
is a collaborative grouping, a formal approval from each participant’s governing authority is
necessary. (Indicate yes by checking the box)
☒ 1.2.3 As an applicant, we have administrative and financial management systems and follow
procurement standards that comply with the standards set forth in the grant agreement (Section 3 of
the RFA). (Indicate yes by checking the box)
☒ 1.2.4 If awarded the grant, we can comply with all terms and conditions of the award as identified in
the Standard Grant Agreement template at www.akenergyauthority.org/what-we-do/grants-
loans/renewable-energy-fund-ref-grants/2020-ref-application (Any exceptions should be clearly
noted and submitted with the application.) (Indicate yes by checking the box)
☒ 1.2.5 We intend to own and operate any project that may be constructed with grant funds for the
benefit of the general public. If no please describe the nature of the project and who will be the
primary beneficiaries. (Indicate yes by checking the box)
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SECTION 2 – PROJECT SUMMARY
2.1 Project Title
Provide a 4 to 7 word title for your project. Type in the space below.
KNUTSON CREEK HYDRO PROJECT CONSTRUCTION
2.2 Project Location
2.2.1 Location of Project – Latitude and longitude (preferred), street address, or community name.
Latitude and longitude coordinates may be obtained from Google Maps by finding you project’s location on
the map and then right clicking with the mouse and selecting “What is here? The coordinates will be
displayed in the Google search window above the map in a format as follows: 61.195676.-149.898663. If
you would like assistance obtaining this information, please contact AEA’s Grants Manager Karin St. Clair by
email at grants@akenergyauthority.org or by phone at (907) 771-3081.
Latitude 59.80d N Longitude 154.14d W.
The project site on Knutson Creek is located approximately one mile northwest of the village.
2.2.2 Community benefiting – Name(s) of the community or communities that will be the beneficiaries
of the project.
Village of Pedro Bay
2.3 Project Type
Please check as appropriate.
2.3.1 Renewable Resource Type
☐ Wind ☐ Biomass or Biofuels (excluding heat-only)
☒ Hydro, Including Run of River ☐ Hydrokinetic
☐ Geothermal, Excluding Heat Pumps ☐ Transmission of Renewable Energy
☐ Solar Photovoltaic ☐ Storage of Renewable
☐ Other (Describe) ☐ Small Natural Gas
2.3.2 Proposed Grant Funded Phase(s) for this Request (Check all that apply)
Pre-Construction Construction
☐ Reconnaissance ☐ Final Design and Permitting
☐ Feasibility and Conceptual Design ☒ Construction
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2.4 Project Description
Provide a brief, one-paragraph description of the proposed project.
The proposed project is an approximately 150 kW run-of-river hydroelectric project on Knutson
Creek near Pedro Bay. The hydro project will provide nearly all (~98%) of the electricity needs of
the village, as well as providing a significant amount of interruptible energy to heat the tribal
council building and other community buildings in the village.
2.5 Scope of Work
Provide a short narrative for the scope of work detailing the tasks to be performed under this funding
request. This should include work paid for by grant funds and matching funds or performed as in-kind
match.
The requested grant is for phase 1 construction of the hydro project. Phase 1 includes constructing new
access roads up to the project powerhouse and pioneering access trails up to the intake site.
2.6 Previous REF Applications for the Project
See Section 1.15 of the RFA for the maximum per project cumulative grant award amount
Round
Submitted
Title of application Application #,
if known
Did you
receive a
grant? Y/N
Amount of REF
grant awarded
($)
6 Knutson Creek Hydroelectric Project
Design and Permitting
976 Y $290,000
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SECTION 3 – Project Management, Development, and Operation
3.1 Schedule and Milestones
Please fill out the schedule below (or attach a similar sheet) for the work covered by this funding request.
Be sure to identify key tasks and decision points, including go/no go decisions, in your project along with
estimated start and end dates for each of the milestones and tasks. Please clearly identify the beginning
and ending of all phases (I. Reconnaissance, II. Feasibility and Conceptual Design, III. Final Design and
Permitting, and IV. Construction) of your proposed project. See the RFA, Sections 2.3-2.6 for the
recommended milestones for each phase. Add additional rows as needed.
Task #
Milestones Tasks
Start
Date
End
Date Deliverables
1 Award Construction
Contract
Contractor
Procurement
Aug.
2021
Nov.
2021
Construction Contract
2 Complete Phase 1
Construction
Phase 1 Construction Jan
2022
Nov
2022
Phase 1 Construction As-builts
3 Complete Phase 1
Construction
Phase 1 Construction
Engineering
July
2021
Dec
2022
Inspection Reports, as-builts
4 Complete Phase 1
Construction
Phase 1 Construction
Management
July
2021
Dec
2022
Progress reports
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3.2 Budget
3.2.1 Funding Sources
Indicate the funding sources for the phase(s) of the project applied for in this funding request.
Grant funds requested in this application $1,710,000
Cash match to be provided a $1,000
In-kind match to be provideda $4,000
Energy efficiency match providedb $0
Total costs for project phase(s) covered in application (sum of above) $1,715,000
Describe your financial commitment to the project and the source(s) of match. Indicate whether these
matching funds are secured or pending future approvals. Describe the impact, if any, that the timing of
additional funds would have on the ability to proceed with the grant.
PBVC has demonstrated a consistent financial commitment to this project, as evidenced by the matching
funds and the in-kind services provided by PBVC and/or village residents over the years.
PBVC recognizes the state’s current budget situation and that availability of grant funds will likely be
limited for project construction. We have a proven track record of financing our capital projects through a
variety of state and federal grant programs and will pursue these, as well as debt service to the extent the
utility operation can support it.
a Attach documentation for proof (see Section 1.18 of the Request for Applications)
b See Section 8.2 of this application and Section 1.18 of the RFA for requirements for Energy Efficiency Match.
3.2.2 Cost Overruns
Describe the plan to cover potential cost increases or shortfalls in funding.
The proposed budget includes a contingency on all activities to address unforeseen project costs. Beyond
that, PBVC would control cost overruns through proactive project management to identify and adjust work
scopes to prevent cost overruns where practical.
In instances where cost overruns cannot be avoided, PBVC would pay additional costs from its own
resources to the extent possible and as authorized by PBVC leadership on a case-by-case basis with
consideration of the specific circumstances of the cost-overrun.
3.2.3 Total Project Costs
Indicate the anticipated total cost by phase of the project (including all funding sources). Use actual costs
for completed phases. Indicate if the costs were actual or estimated.
Reconnaissance [Actual] $ 29,100
Feasibility and Conceptual Design [Actual] $103,770
Final Design and Permitting [Actual] $295,000
Construction [Estimated] $6,500,000
Total Project Costs (sum of above) Estimated $6,927,870
Metering/Tracking Equipment [not included in project cost] Estimated $0
3.2.4 Funding Subsequent Phases
If subsequent phases are required beyond the phases being applied for in this application, describe the
anticipated sources of funding and the likelihood of receipt of those funds.
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State and/or federal grants
Loans, bonds, or other financing options
Additional incentives (i.e. tax credits)
Additional revenue streams (i.e. green tag sales or other renewable energy subsidies or programs that
might be available)
PBVC will consider all viable sources of funding for subsequent phases of construction. State or federal
grants and/or loans and private sector loans are all options. Supplemental revenues from electricity sales,
green tags, energy subsidies, tax credits, and other sources that may be available at the time the project
financing is secured will all be considered.
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3.2.3 Budget Forms
Applications MUST include a separate worksheet for each project phase that was identified in Section 2.3.2
of this application — I. Reconnaissance, II. Feasibility and Conceptual Design, III. Final Design and
Permitting, and IV. Construction. Please use the tables provided below to detail your proposed project’s
total budget. Be sure to use one table for each phase of your project, and delete any unnecessary tables.
The milestones and tasks should match those listed in 3.1 above.
If you have any question regarding how to prepare these tables or if you need assistance preparing the
application please feel free to contact AEA’s Grants Manager Karin St. Clair by email at
grants@akenergyauthority.org or by phone at (907) 771-3081.
Phase 4 — Construction
Milestone or Task
Anticipated
Completion
Date
RE- Fund
Grant Funds
Grantee
Matching
Funds
Source of
Matching
Funds:
Cash/In-
kind/Federal
Grants/Other
State
Grants/Other
TOTALS
1. Contractor Procurement Nov. 2021 $8,000 $0 - $8,000
2. Phase 1 Construction Nov. 2022 $1,566,000 $0 - $1,566,000
3. Phase 1 Construction
Engineering Jan. 2023 $85,000 $0 - $85,000
4. Phase 1 Construction
Management Jan. 2023 $51,000 $5,000 Cash / in-kind $56,000
TOTALS $1,710,000 $5,000 $1,715,000
Budget Categories:
Direct Labor & Benefits $51,000 $5,000 Cash / in-kind $56,000
Travel & Per Diem $0 $0 - $0
Equipment $0 $0 - $0
Materials & Supplies $0 $0 - $0
Contractual Services $93,000 $0 - $93,000
Construction Services $1,566,000 $0 - $1,566,000
Other $0 $0 - $0
TOTALS $1,710,000 $5,000 $1,715,000
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3.2.4 Cost Justification
Indicate the source(s) of the cost estimates used for the project budget, including costs for future phases
not included in this application.
September 2020 Engineer’s Cost Estimate for the project.
3.3 Project Communications
3.3.1 Project Progress Reporting
Describe how you plan to monitor the progress of the project and keep AEA informed of the status. Who
will be responsible for tracking the progress? What tools and methods will be used to track progress?
PBVC will rely on our Village Administrator – John Baalke – and engineering consultant Joel Groves, P.E. at
Polarconsult Alaska, Inc. – for progress reporting. Regular reports will be made to AEA on - at a minimum -
a monthly basis. Mr. Groves will prepare draft progress reports for review and submittal by Mr. Baalke.
More frequent reporting may be appropriate during some phases of the project to make timely report of
notable events. Reports will include status and tracking information for work product, schedule, and
budget, allowing recipients to easily stay abreast of current project progress.
3.3.2 Financial Reporting
Describe the controls that will be utilized to ensure that only costs that are reasonable, ordinary and
necessary will be allocated to this project. Also discuss the controls in place that will ensure that no
expenses for overhead, or any other unallowable costs will be requested for reimbursement from the REF
Grant Program.
During construction, contractor pay requests will be routed through the engineer for review and
affirmation that the pay request is supported by construction progress. Mr. Groves is familiar with AEA REF
program requirements and will also flag any expenses that are not eligible for the grant so these can be
addressed with the contractor and/or removed from PBVC reimbursement submittals as appropriate.
PBVC bookkeeper Rebecca Jensen would also review contractor and other project pay requests prior to
submittal to AEA to verify they conform to grant requirements.
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SECTION 4 – QUALIFICATIONS AND EXPERIENCE
4.1 Project Team
Include resumes for known key personnel and contractors, including all functions below, as an attachment
to your application. In the electronic submittal, please submit resumes as separate PDFs if the applicant
would like those excluded from the web posting of this application.
4.1.1 Project Manager
Indicate who will be managing the project for the Grantee and include contact information. If the applicant
does not have a project manager indicate how you intend to solicit project management support. If the
applicant expects project management assistance from AEA or another government entity, state that in this
section.
PBVC administrator John Baalke will be our project manager.
Mr. Baalke’s contact information is provided at Section 1.1 of this application. No management assistance
is needed from AEA.
4.1.2 Project Accountant
Indicate who will be performing the accounting of this project for the grantee. If the applicant does not
have a project accountant indicate how you intend to solicit financial accounting support.
Rebecca Jensen is PBVC’s finance officer and bookkeeper and will be responsible for tracking budgets and
supporting documentation. Trudy Bonnette will also be available to assist with project accounting and
reporting needs.
4.1.3 Expertise and Resources
Describe the project team including the applicant, partners, and contractors.
For each member of the project team, indicate:
the milestones/tasks in 3.1 they will be responsible for;
the knowledge, skills, and experience that will be used to successfully deliver the tasks;
how time and other resource conflicts will be managed to successfully complete the task.
If contractors have not been selected to complete the work, provide reviewers with sufficient detail to
understand the applicant’s capacity to successfully select contractors and manage complex contracts.
Mr. Baalke will be the overall project manager responsible for tracking and managing the overall budget,
scope and schedule of work performed under this grant. Mr. Baalke has successfully managed several grant
projects for PBVC, including prior grants for the reconnaissance, feasibility, and design/permit phases of
this project, which were sourced from four different state and/or federal agencies. The recently completed
design/permit grant is an AEA REF grant from Round 6.
Mr. Groves will be the project engineer, and will lead the procurement process for selection of construction
contractors for this project. He will also provide construction engineering services for PBVC and as
applicable may support PBVC with construction management.
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PBVC expects to select a construction contractor through a competitive pubic procurement process. Bid
documents will be advertised and circulated to qualified contractors, and a contractor will be selected by
PBVC based on impartial review of bids received to provide best overall value to PBVC on this project.
4.2 Local Workforce
Describe how the project will use local labor or train a local labor workforce.
During the study, permitting, and design phases, PBVC has employed local residents when appropriate to
support subject matter experts. This has typically included activities such as field guides, survey assistants,
bear guards, or troubleshooting/fixing malfunctioning stream gauge hardware to avoid the expense of
mobilizing consultants to the village.
Use of local labor during construction will depend on how the project is managed and the availability and
willingness of qualified individuals to work on the project.
PBVC may send one or more people to AVTEC or similar hydro operator training courses before project
commissioning so they are familiar with the particulars of operating and maintaining small hydro systems.
The community intends to identify plant operators prior to construction and involve them with construction
where appropriate so they will be familiar with how the project was built, as we believe this will benefit the
utility in the long-term with project familiarity and ability to successfully and efficiently perform operations,
maintenance, repair and replacement (OMR&R) activities with local labor, equipment, and materials.
This is not as-critical for proposed phase one construction (access roads and trails), but will be especially
critical during phase two, when the project improvements are installed and the plant is commissioned.
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SECTION 5 – TECHNICAL FEASIBILITY
5.1 Resource Availability
5.1.1 Assessment of Proposed Energy Resource
Describe the potential extent/amount of the energy resource that is available, including average resource
availability on an annual basis. For pre-construction applications, describe the resource to the extent
known. For design and permitting or construction projects, please provide feasibility documents, design
documents, and permitting documents (if applicable) as attachments to this application (See Section 11).
Likelihood of the resource being available over the life of the project. See the “Resource Assessment”
section of the appropriate Best Practice Checklist for additional guidance.
The resource capacity factor for the proposed run-of-river hydro project is approximately 91%. This is
based on resource availability, final design estimates of power output based on penstock losses and turbine
/ generator efficiency, and assumed (pending permit finalization) in-stream flow reservation of 6.5 cfs (see
below).
PBVC is in final stages of permitting with ADFG, which will determine whether an in-stream flow reservation
(ISFR) will be required for the project. If required, an ISFR of 6.5 cfs would reduce the resource capacity
factor from 96% to approximately 91%. This is because most of the year, Knutson Creek flow is much
higher than the flow needed for the project. Project performance would only be affected by an ISFR in late
winter / early spring (January – April), when natural creek flow is at its lowest. This application assumes the
ISFR is included in the final permit.
Resource availability is characterized by hydrology study conducted by PBVC from 2010 to 2017. The 6.5-
year record at Knutson Creek has a good correlation (R2 = 0.85) with the concurrent USGS hydrology record
at nearby Iliamna River, providing a 24-year extended record (1996 to 2020) for Knutson Creek.
The water resource is expected to be available over the 50-year life of the project. There are no other
water rights or reservations on Knutson Creek aside from those applied for by PBVC. The Knutson Creek
basin is unglaciated so climate change is not expected to adversely impact annual energy production.
Indeed, the anomalously warm years of 2015 and 2016 (due to “The Blob”) resulted in higher-than-normal
flows through most of the winter, which would reduce or eliminate the impact of an ISFR on the project
and increase water availability for hydro generation.
5.1.2 Alternatives to Proposed Energy Resource
Describe the pros and cons of your proposed energy resource vs. other alternatives that may be available
for the market to be served by your project.
PBVC’s 2009 hydro reconnaissance study (see supporting data, Section 11) evaluated the hydropower
potential of other creeks near the village. All of these would have more typical run-of-river seasonal
generation curves (estimated plant capacity factors of 66% to 79%), and would not be able to fully meet the
village’s winter demand. Some of the resources considered may also have more substantial fisheries
conflicts that could prevent construction or constrain project operation.
Wind power has not been studied in Pedro Bay. Wind power would not meet as much of Pedro Bay’s utility
load as the proposed project. The mountainous terrain around the village suggests that local wind fields
may have a high degree of turbulence and not be suitable for wind turbines, but this matter has not been
studied.
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Solar power in conjunction with large battery storage could meet some of Pedro Bay’s electric demand, but
this concept has not been studied. The extent to which a system could carry 100% of village load during
episodes of summer-time cloudy weather, or in the shoulder seasons (spring and fall) would depend on the
size of the battery system relative to the solar array size and utility load. Diesel generation would still be
required for most of the winter season, and for some of the shoulder and summer seasons, depending on
the specific system proposed and insolance data for Pedro Bay.
5.1.3 Permits
Provide the following information as it may relate to permitting and how you intend to address outstanding
permit issues. See the “Environmental and Permitting Risks” section of the appropriate Best Practice
Checklist for additional guidance.
List of applicable permits
Anticipated permitting timeline
Identify and describe potential barriers including potential permit timing issues, public opposition that
may result in difficulty obtaining permits, and other permitting barriers
The project is finalizing the permitting process. Major permits and current (9/24/2020) status follow.
Supporting documentation is listed in Application Section 11.
- FERC finding of non-jurisdiction issued September 2015 (DI 14-06)
- U.S. Army Corps of Engineers Wetland Permit applied August 2020. Currently being adjudicated.
Expected authorization under NWP #39.
- ADNR Water Rights filed December 2019, application complete and in ADNR adjudication backlog. LAS
33115.
- ADNR Dam Safety. Non-jurisdictional status affirmed June 29, 2020.
- ADFG Fish Habitat permit. PBVC filed a permit application in 2016 and conducted numerous fisheries
surveys and field investigations from 2016 to 2018 to quantify potential impacts to fish habitat. A final
permit decision is expected in October 2020.
All necessary project permits should be issued by December 2020 or earlier. No public opposition to the
project or unusual permitting barriers are known.
5.2 Project Site
Describe the availability of the site and its suitability for the proposed energy system. Identify potential land
ownership issues, including whether site owners have agreed to the project or how you intend to approach
land ownership and access issues. See the “Site control” section of the appropriate Best Practice Checklist
for additional guidance.
The project site is entirely located on lands patented or interim-conveyed to the Pedro Bay Corporation
(PBC). PBVC intends to finalize site control for this project via an ANCSA 14(c)3 exchange and limited access
ROW agreements. An agreement with PBC is pending and will be provided to AEA upon completion.
5.3 Project Technical & Environmental Risk
5.3.1 Technical Risk
Describe potential technical risks and how you would address them.
Which tasks are expected to be most challenging?
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How will the project team reduce the risk of these tasks?
What internal controls will be put in place to limit and deal with technical risks?
See the “Common Planning Risks” section of the appropriate Best Practice Checklist for additional guidance.
The major technical risks facing the project are:
1. Geotechnical risk. Subsurface geotechnical exploration has not been conducted, so there is increased
risk of identifying significant geotechnical issues in the course of construction. This risk is controlled by
phasing project construction. Phase 1 focuses on construction project access roads and trails, which will
identify geotechnical conditions relevant to subsequent construction. Information learned from Phase 1
construction can be used to adapt and finalize Phase 2 designs to actual site conditions, minimizing overall
construction risk.
2. Flood risk. Knutson Creek is subject to large flood flows. High water events during construction - in
particular during construction of the Knutson Creek bridge, tributary ford crossings, or diversion structure -
could result in loss of partially built structures, lost time, or damage to equipment or material. Clear
communication of these risks to the contractor and development of contingency plans and accelerated
schedules for high-risk phases of construction will help to mitigate this risk.
3. Logistic risk. Shipping to Pedro Bay is complicated and expensive. Any equipment or material omitted
from the main job mobilization will incur additional costs for shipping and/or schedule delays. Careful
attention to material lists, verification of items such as pipe bolt-up kits, and mobilization of appropriate
reserve / contingency materials and equipment will all help avoid surprise costs / delays.
Budgets include appropriate contingency to deal with risks that are not successfully mitigated. Depending
on bid results, PBVC may adjust the final work scope during the negotiation phase to maintain adequate
contingency and avoid unaffordable cost overruns.
5.3.2 Environmental Risk
Explain whether the following environmental and land use issues apply, and if so, which project team
members will be involved and how the issues will be addressed. See the “Environmental and Permitting
Risks” section of the appropriate Best Practice Checklist for additional guidance.
Threatened or endangered species
Habitat issues
Wetlands and other protected areas
Archaeological and historical resources
Land development constraints
Telecommunications interference
Aviation considerations
Visual, aesthetics impacts
Identify and describe other potential barriers
The project permitting process identified fish habitat and cultural resource issues associated with the
proposed development.
Fish habitat impacts will be addressed by the final terms of a fish habitat permit from ADFG, which are
expected to include appropriate timing constraints and best practices guidance for in-water work, and
possibly an in-stream flow reservation. These expected requirements are reflected in the project budgets
and energy estimates and will be finalized upon receipt of the habitat permit.
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The project layout has been adjusted to avoid impacts to identified cultural resources in the vicinity.
Accordingly, no impact to cultural resources is expected.
5.4 Technical Feasibility of Proposed Energy System
In this section you will describe and give details of the existing and proposed systems. The information for
existing system will be used as the baseline the proposal is compared to and also used to make sure that
proposed system can be integrated.
Only complete sections applicable to your proposal. If your proposal only generates electricity, you can
remove the sections for thermal (heat) generation.
5.4.1 Basic Operation of Existing Energy System
Describe the basic operation of the existing energy system including: description of control system;
spinning reserve needs and variability in generation (any high loads brought on quickly); and current
voltage, frequency, and outage issues across system. See the “Understanding the Existing System” section
of the appropriate Best Practice Checklist for additional guidance.
The existing electric system uses up to three diesel gen-sets to generate electricity for the community.
Electricity is distributed via a single phase 7.2 kV underground distribution system. The diesel plant is
automated with controllers that dispatch the generators to meet load.
5.4.2.1 Existing Power Generation Units
Include for each unit include: resource/fuel, make/model, design capacity (kW), minimum operational
load (kW), RPM, electronic/mechanical fuel injection, make/model of genset controllers, hours on
genset
Unit 1: 95 kW single phase 480V diesel. John Deere 6059 TFG01. EasyGen controller (Comm. 2000).
Unit 2: 58 kW single phase 480V diesel. John Deere 4045 T150. EasyGen controller (Comm. 2012).
Unit 3: 58 kW single phase 480V diesel. John Deere 4045 T150. EasyGen controller (Comm 2013).
5.4.2.2 Existing Distribution System
Describe the basic elements of the distribution system. Include the capacity of the step-up transformer at
the powerhouse, the distribution voltage(s) across the community, any transmission voltages, and other
elements that will be affected by the proposed project.
The existing distribution system consists of single phase direct-burial cable operating at 7.2kV. System
topology is radial, with no loop feeds. The step-up transformer at the diesel powerhouse is a pad mount 100
kVA 480V/7.2 kV single phase. The new distribution cable to the hydro powerhouse would tie-in to the
existing village distribution system at existing TB1 just west of the village council building.
5.4.2 Existing Energy Generation Infrastructure and Production
In the following tables, only fill in areas below applicable to your project. You can remove extra tables. If
you have the data below in other formats, you can attach them to the application (see Section 11).
Is there operational heat recovery? (Y/N) If yes estimated
annual displaced heating fuel (gallons)
Yes. Estimated 7,700 gallons for the
school and council building.
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5.4.2.3 Existing Thermal Generation Units (if applicable to your project)
Generation
unit
Resource/
Fuel type
Design
capacity
(MMBtu/hr)
Make Model Average
annual
efficiency
Year
Installed
Hours
N/A
Month Generation (Diesel)
(kWh)
Fuel Consumption
(Diesel-Gallons)
Peak Load Minimum Load
January 14,748 1,387 ~40 kW ~12 kW
February 13,188 1,271 ~40 kW ~12 kW
March 14,146 1,380 ~40 kW ~12 kW
April 13,552 1,345 ~40 kW ~12 kW
May 14,625 1,413 ~50 kW ~12 kW
June 18,305 1,641 ~70 kW ~15 kW
July 20,682 1,908 ~70 kW ~15 kW
August 19,582 1,808 ~70 kW ~15 kW
September 17,225 1,709 ~60 kW ~15 kW
October 13,934 1,480 ~50 kW ~12 kW
November 14,445 1,336 ~50 kW ~12 kW
December 15,567 1,572 ~40 kW ~12 kW
Total 190,000 18,250 ~40 kW ~12 kW
Data based on last five years (2015 – 2019) PBVC utility operating data. Peaks and minimums are estimates.
5.4.2.5 Annual Heating Fuel Consumption (Existing System)
Use most recent year. Include only if your project affects the recovered heat off the diesel genset or will
include electric heat loads. Only include heat loads affected by the project.
Month Diesel
(Gallons)
Electricity Propane
(Gallons)
Coal
(Tons)
Wood
(Cords, green
tons, dry
tons)
Other
January 1,580 - - - - -
February 1,310 - - - - -
March 1,310 - - - - -
April 1,000 - - - - -
May 760 - - - - -
June 490 - - - - -
July 380 - - - - -
August 390 - - - - -
5.4.2.4 O&M and replacement costs for existing
units
Power Generation Thermal Generation
i. Annual O&M cost for labor $25,000 Not applicable.2
ii. Annual O&M cost for non-labor $10,000 Not applicable.2
iii. Replacement schedule and cost for existing
units
N/A Not applicable.2
Note 2: Dispatchable energy sales are envisioned with assumed annual sales of 200,000 to 250,000 kWh.
Specific buildings targeted for refit include the VPSO building, PBVC library, and new church.
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September 590 - - - - -
October 920 - - - - -
November 1,220 - - - - -
December 1,450 - - - - -
Total 11,400 - - - - -
Reflects heating load for new church, library building, and VPSO building. Could also add Butler building
in lieu or in addition to VPSO building.
5.4.3 Future Trends
Describe the anticipated energy demand in the community, or whatever will be affected by the project,
over the life of the project. Explain how the forecast was developed and provide year by year forecasts. As
appropriate, include expected changes to energy demand, peak load, seasonal variations, etc. that will
affect the project.
Future trends are expected to be flat for the full 50-year project life at current annual demand of 190,000
kWh at generation. This is based on review of past utility data - the 190,000 kWh value is based on the
average for the last five years (2015 to 2019). Annual load was significantly higher (~260,000 kWh at
generation) before the school closed in fall 2011 due to low enrollment. The range of annual demand in the
available operating record (2003 – 2019) is a high of 296,000 kWh in 2005, and a low of 184,000 kWh in 2013.
Annual load has been stable in the 180,000 to 200,000 band since 2013.
Future trends are expected to be strongly influenced by local economic opportunity in the community. If the
school were to reopen, loads similar to those prior to 2011 (~260,000 kWh) are possible, although permanent
load reduction through adoption of higher efficiency consumer goods is likely to suppress future demand
below past highs.
There has been an increasing trend of higher summer load in the past few years, attributed to higher usage
by seasonal lodges and/or seasonal residents. Current load profile is ~20 kW average load from October
through May, and 25 to 30 kW average load from June through September.
Variations in utility loads as described above will have little to no effect on hydro plant performance, as the
plant will be able to meet nearly all of utility demand in all of the above conditions. Variations in kWh
generation and sales will affect project economics, as the per kWh cost of the project increases as total kWh
sales volume decreases.
5.4.4 Proposed System Design
Provide the following information for the proposed renewable energy system:
A description of renewable energy technology specific to project location
The total proposed capacity and a description of how the capacity was determined
Integration plan, including upgrades needed to existing system(s) to integrate renewable energy
system: Include a description of the controls, storage, secondary loads, distribution upgrades that
will be included in the project
Civil infrastructure that will be completed as part of the project—buildings, roads, etc.
Include what backup and/or supplemental system will be in place
See the “Proposed System Design” section of the appropriate Best Practice Checklist for additional
guidance.
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The proposed system is a conventional run-of-river hydroelectric project. It will consist of the following major
features:
- 12,500 feet of new access roads and trails to access the project from the village’s existing road system,
including a single-lane bridge across Knutson Creek at RM 1.82.
- Diversion structure at RM 2.59 of Knutson Creek to impound water and direct it into the project penstock.
- Approximately 6,600 foot-long 20” penstock to convey up to 20 cfs of water from the diversion to the
powerhouse.
- Powerhouse above the left bank of Knutson Creek at RM 1.29. Project develops 205 feet of gross head to
drive a single 150 kW crossflow turbine / generator set. Powerhouse will include turbine, generator,
switchgear and controls, hydraulic power unit, and associated equipment.
- Approximately 250 foot long tailrace to return project water to Knutson Creek at RM 1.29.
- Approximately 9,700 feet of new underground power line and 10,100 feet of communication line between
the hydro and diesel powerhouses. The dedicated fiber comm line would support automated parallel
operation / dispatch of the two power plants based on resource and gen set availability.
The hydro project will normally provide sufficient power to run the utility in “diesels-off” mode for nearly all
of the year. The hydro generator will be governed by an electronic load bank in the hydro powerhouse to
maintain system frequency. Some of the governor load (and/or excess generating capacity) can be
transferred in blocks to an electric boiler in the diesel power plant to keep the diesel gensets warm and
maintain heat in the existing waste heat loop serving the school and community building. Additional
dispatchable loads can be installed in other community buildings to utilize more of the available hydro
capacity.
The existing diesel power plant will remain in service to provide backup generation to the hydro plant. A
master controller will be installed to coordinate dispatch of hydro and diesel gen sets to meet utility load.
5.4.4.1 Proposed Power Generation Units
Unit # Resource/
Fuel type
Design
capacity
(kW)
Make Model Expected
capacity
factor
Expected
life
(years)
Expected
Availability
H1 hydro 150 kW TBD Crossflow 93.6% 50 >98%
5.4.4.2 Proposed Thermal Generation Units (if applicable)
Generation
unit
Resource/
Fuel type
Design
capacity
(MMBtu/hr)
Make Model Expected
Average annual
efficiency
Expected life
N/A
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5.4.5 Basic Operation of Proposed Energy System
To the best extent possible, describe how the proposed energy system will operate: When will the
system operate, how will the system integrate with the existing system, how will the control
systems be used, etc.
When and how will the backup system(s) be expected to be used
See the “Proposed System Design” section of the appropriate Best Practice Checklist for additional
guidance.
The hydro project will operate year-round except for maintenance and unscheduled outages. The utility will
normally operate in “diesels-off” mode, with the hydro supplying all electricity to meet utility demand. The
hydro will include an electronic load governor to match load and supply with reserve for demand fluctuations
and maintain a stable grid frequency.
Excess hydro generating capacity will be used to power an electric boiler in the diesel power plant to keep
the diesel plant and engines warm and also to keep the existing waste heat loops service the community
building and school in service. Additional excess hydro generating capacity can be dispatched to other
community buildings on an as-available basis.
A new master controller installed at the diesel powerhouse will dispatch the four (1 hydro, 3 diesel)
generation assets to meet PBVC load in accordance with programmed economic dispatch protocol and
generator operating set points. Hydro will be dispatched first when sufficient water is available for operation
(as determined by head level sensor in the intake gallery), and diesels will be turned off. Water flow and
turbine output will be regulated by turbine inlet vanes to meet load, which will include dispatchable loads
when appropriate as described above.
When PBVC load exceeds available hydro capacity or water availability, a diesel gen set(s) will be activated in
“isoc” mode and base loaded to achieve good fuel economy and operating point. If available, the hydro will
be operated in “droop” mode and the load bank frequency controller disabled or relegated to secondary
control to address hydraulic transients.
System modeling indicates the hydro plant can supply 93.6% of annual utility demand.
5.4.3.1 Expected Capacity
Factor
93.6%
(please also see section 5.1.1 on ADFG permit terms.)
5.4.5.2 Annual Electricity Production and Fuel Consumption (Proposed System)
Month Generation
(Hydro)
(kWh)
Generation
(Diesel)
(kWh)
Generation
(Type 3)
(kWh)
Fuel
Consumption
(Diesel-
Gallons)
Fuel
Consumption
[Other]
Secondary
load
(kWh)
Storage
(kWh)
January 16,935 2,182 - 208 - - -
February 15,587 1,995 - 190 - - -
March 12,865 5,324 - 507 - - -
April 13,899 2,686 - 256 - - -
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May 13,793 0 - 0 - - -
June 12,689 0 - 0 - - -
July 12,359 0 - 0 - - -
August 13,702 0 - 0 - - -
September 14,266 0 - 0 - - -
October 16,133 0 - 0 - - -
November 15,666 0 - 0 - - -
December 19,490 428 - 41 - - -
Total 177,385 12,615 - 1,202 - - -
5.4.5.3 Annual Heating Fuel Consumption (Proposed System)
Month Diesel
(Gallons)
Electricity
(kWh at
generation)
Propane
(Gallons)
Coal
(Tons)
Wood
(Cords, green
tons, dry tons)
Other
January 928 26,000 - - - -
February 736 23,000 - - - -
March 787 21,000 - - - -
April 241 30,000 - - - -
May 30 29,000 - - - -
June 0 19,000 - - - -
July 0 15,000 - - - -
August 0 15,000 - - - -
September 2 23,000 - - - -
October 0 36,000 - - - -
November 55 46,000 - - - -
December 588 34,000 - - - -
Total 3,368 317,000 - - - -
For same three buildings in table 5.4.2.5. Note 3,368 gallons diesel vs. 11,400 for existing system,
reflecting savings of 8,032 gallons annually. Heat is provided on dispatchable basis by indicated kWh at
generation. Metered dispatched kWh to heat buildings is generation less system losses of 12%.
5.4.6 Proposed System Operating and Maintenance (O&M) Costs
O&M costs can be estimated in two ways for the standard application. Most proposed renewable energy
projects will fall under Option 1 because the new resource will not allow for diesel generation to be turned
off. Some projects may allow for diesel generation to be turned off for periods of time; these projects
should choose Option 2 for estimating O&M.
Option 1: Diesel generation ON
For projects that do not result in shutting down
diesel generation there is assumed to be no impact
on the base case O&M. Please indicate the
estimated annual O&M cost associated with the
proposed renewable project.
$N/A
Option 2: Diesel generation OFF
For projects that will result in shutting down diesel
generation please estimate:
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1. Annual non-fuel savings of shutting off
diesel generation
2. Estimated hours that diesel generation will
be off per year.
3. Annual O&M costs associated with the
proposed renewable project.
1. $8,000
2. Hours diesel OFF/year ~8,712 hours off (note 1)
3. $15,000
Note 1: Resource availability would support ~8,740 or more hours of annual ‘diesels-off’ operation. This is
reduced to 8,712 hours to allow diesels to operate 4 hours per month to keep them in good working order
and permit brief hydro outages for routine preventative maintenance / operations tasks.
5.4.7 Fuel Costs
Estimate annual cost for all applicable fuel(s) needed to run the proposed system (Year 1 of operation)
Diesel
(Gallons)
Electricity Propane
(Gallons)
Coal
(Tons)
Wood
Other
Unit cost ($) 4.93 - - - -
Annual Units 1,200 - - - -
Total Annual
cost ($)
5,916 - - - -
5.5 Performance and O&M Reporting
For construction projects only
5.5.1 Metering Equipment
Please provide a short narrative, and cost estimate, identifying the metering equipment that will be used to
comply with the operations reporting requirement identified in Section 3.15 of the Request for
Applications.
Plant switchgear and controls will include required sensors and logging capability to automatically collect
plant generation and performance information.
No incremental cost is expected for infrastructure needed to comply with AEA reporting requirements.
5.5.2 O&M reporting
Please provide a short narrative about the methods that will be used to gather and store reliable operations
and maintenance data, including costs, to comply with the operations reporting requirement identified in
Section 3.15 of the Request for Applications
The plant operator will maintain maintenance and repair logs. Relevant maintenance and repair activities
will be summarized and reported to AEA on an annual basis for the required 10-year period.
The labor effort to compile required data, prepare annual reports, and respond to AEA reporting inquiries is
estimated at $5,000 annually.
SECTION 6 – ECONOMIC FEASIBILITY AND BENEFITS
6.1 Economic Feasibility
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6.1.1 Economic Benefit
Annual Lifetime
Anticipated Diesel Fuel Displaced for Power
Generation (gallons)
16,900 845,000
Anticipated Fuel Displaced for Heat (gallons) 8,032 401,600
Total Fuel displaced (gallons) 24,932 1,246,600
Anticipated Diesel Fuel Displaced for Power
Generation ($)
$83,317 $4,165,850
Anticipated Fuel Displaced for Heat ($) $39,598 $1,979,900
Anticipated Power Generation O&M Cost
Savings
$8,000 $400,000
Anticipated Thermal Generation O&M Cost
Savings
$0 $0
Total Other costs savings (taxes, insurance,
etc.)
$0 $0
Total Fuel, O&M, and Other Cost Savings $130,915 $6,545,750
6.1.2 Economic Benefit
Explain the economic benefits of your project. Include direct cost savings and other economic benefits, and
how the people of Alaska will benefit from the project. Note that additional revenue sources (such as tax
credits or green tags) to pay for operations and/or financing, will not be included as economic benefits of
the project.
Where appropriate, describe the anticipated energy cost in the community, or whatever will be affected by
the project, over the life of the project. Explain how the forecast was developed and provide year-by-year
forecasts
The economic model used by AEA is available at www.akenergyauthority.org/What-We-Do/Grants-
Loans/Renewable-Energy-Fund-REF-Grants/2020-REF-Application. This economic model may be used by
applicants but is not required. The final benefit/cost ratio used will be derived from the AEA model to ensure
a level playing field for all applicants. If used, please submit the model with the application.
Direct economic benefits from this project include reduced electricity rates for the community and increased
stability in electric rates over time as our dependence on volatile fuel prices and fuel delivery prices will be
significantly reduced with the hydro operational. These benefits would be augmented if the project is able
to qualify for and receive additional revenue from green tags / renewable energy credits, tax credits, or other
financial incentives. Because of the volatility in the terms and eligibility thresholds of these various programs,
PBVC does not expect to realize revenue from them but will explore them when the project financing is
finalized to see which - if any - programs have merit.
The AEA economic model shows a benefit-cost ratio of 0.71 for the project at current load levels of 190,000
kWh/year at generation. A return to pre-2013 loads results in a benefit-cost ratio of 0.85.
Indirect benefits that are not readily reduced to dollar values include (see also narrative at 6.2):
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- By reducing local fuel demand and marine transport volumes, this project incrementally reduces the risk of
catastrophic damage to our economy due to a significant fuel spill in the village or in Lake Iliamna associated
with fuel handling operations.
- Extend the life of our existing diesel plant, reducing overall frequency of engine overhauls and deferring
plant upgrade / replacement requirements.
- Improve quality of life by reducing diesel power plant stack emissions (improved local air quality) and
reducing sound emissions from the diesel power plant.
- Improves local recreational and subsistence opportunities for residents and/or visitors by providing
improved trail access up Knutson valley. Access to these PBC lands would be subject to PBC access
authorizations in accordance with the terms of land use authorizations.
6.1.3 Economic Risks
Discuss potential issues that could make the project uneconomic to operate and how the project team will
address the issues. Factors may include:
Low prices for diesel and/or heating oil
Other projects developed in community
Reductions in expected energy demand: Is there a risk of an insufficient market for energy produced over
the life of the project.
Deferred and/or inadequate facility maintenance
Other factors
The main risk that nearly all Alaska hydro projects have encountered in recent years is construction cost risk,
where the final installed cost of projects have been significantly higher than estimates developed throughout
the planning and design phases. Two examples of this include Battle Creek (~50% over budget, 2020 1, 2) and
Blue Lake Dam Raise (~93% over budget, 20123). The current budget estimate is based on site conditions,
final design and permits, and recent cost experience for similar Alaska hydro projects.
Exposure to other economic risks, such as future episodes of low-cost alternate fuels or new energy
alternatives, will depend on the final financing plan for the project. The greatest risk is perhaps a declining
load. The utility could connect additional dispatchable energy circuits to increase kWh sales, although this
would not fully replace prime energy revenues due to the lower per-kWh rate for dispatchable sales, and
there is a diminishing return on dispatchable refits due to the limited number of large buildings in the
community.
1. Battle Creek Diversion TPS Report, 2011 Legislature ($31.5 million cost estimate).
2. Battle Creek Completion Press Release, AEA, 8/27/2020 ($47 million final cost).
3. Blue Lake Dam Raise Construction Award, KCAW article, 9/12/2012. ($96.7 million bid vs. $50 million
engineer’s estimate).
6.1.4 Public Benefit for Projects with Direct Private Sector Sales
For projects that include direct sales of power to private sector businesses (sawmills, cruise ships, mines,
etc.), please provide a brief description of the direct and indirect public benefits derived from the project as
well as the private sector benefits and complete the table below. See Section 1.6 in the Request for
Applications for more information.
Not applicable. All electricity sales will be through the electric utility.
Renewable energy resource availability (kWh per month) N/A
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Estimated direct sales to private sector businesses (kWh) N/A
Revenue for displacing diesel generation for use at private sector businesses ($) N/A
Estimated sales for use by the Alaskan public (kWh) See 5.4.5.2
Revenue for displacing diesel generation for use by the Alaskan public ($) See 5.4.5.2
6.2 Other Public Benefit
Describe the non-economic public benefits to Alaskans over the lifetime of the project. For the purpose of
evaluating this criterion, public benefits are those benefits that would be considered unique to a given project
and not generic to any renewable resource. For example, decreased greenhouse gas emission, stable pricing
of fuel source, won’t be considered under this category.
Some examples of other public benefits include:
The project will result in developing infrastructure (roads, trails, pipes, power lines, etc.) that can be used
for other purposes
The project will result in a direct long-term increase in jobs (operating, supplying fuel, etc.)
The project will solve other problems for the community (waste disposal, food security, etc.)
The project will generate useful information that could be used by the public in other parts of the state
The project will promote or sustain long-term commercial economic development for the community
The project will provide price security for local rate-payers, who have experienced extreme electric rates
and rate shock in recent years due to variable fuel cost compounded with variable premiums for local fuel
delivery. Lower prices and price stability will help both residents and businesses, both promoting and
sustaining long-term commercial economic development for the community.
By reducing the volume of fuel transported to Pedro Bay, the project will incrementally reduce the hazard
of fuel spills in marine water, inland waters, or on-shore in Pedro Bay. Pedro Bay’s culture and economy
are both highly dependent on the integrity and health of our environment for local subsistence harvest,
local sport fish tourism, and local commercial fishing. A significant local fuel spill could have devastating
short and long-term impacts to multiple facets of our community.
With this project the diesel generators would be off-line almost all the time, therefore noise and air
pollution from the diesel power plant would be dramatically reduced.
Electric utility revenues would transition from diesel fuel purchase to hydro plant operations, keeping
wealth in our local economy and supporting new jobs.
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SECTION 7 – SUSTAINABILITY
Describe your plan for operating the completed project so that it will be sustainable throughout its
economic life.
At a minimum for construction projects, a business and operations plan should be attached and the
applicant should describe how it will be implemented. See Section 11.
7.1.1 Operation and Maintenance
Demonstrate the capacity to provide for the long-term operation and maintenance of the proposed project
for its expected life
Provide examples of success with similar or related long-term operations
Describe the key personnel that will be available for operating and maintaining the infrastructure.
Describe the training plan for existing and future employees to become proficient at operating and
maintaining the proposed system.
Describe the systems that will be used to track necessary supplies
Describe the system will be used to ensure that scheduled maintenance is performed
PBVC has successfully operated village utilities (electric, bulk fuel, solid waste) for many years.
PBVC has not yet identified specific personnel that would be responsible for hydro plant operations. It is
our intent to identify such personnel prior to construction so they can be involved with construction to the
extent practical. This will give them greater familiarity with the project which will be invaluable for
operations and maintenance.
As appropriate, PBVC will train operators either with formal education at institutions such as AVTEC or by
visiting similar local hydro plants in the region or state to become familiar with plant operational
requirements, issues, and methods. For example, operations experience at Tazimna is considered
invaluable for cold-region intake performance.
Operations and Maintenance Plans will be developed concurrent with plant construction to capture final
design elements, as-built conditions, and relevant site and equipment information learned during
construction. In general, these plans are expected to be developed as follows.
Maintenance requirements will be identified in the operations and maintenance manuals furnished by
various vendors during the construction phase. These diverse requirements will be captured in a unified
concise O&M document specifying by major project element the pertinent O&M activities and intervals,
with reference back to the individual O&M manuals for more specific details. The unified O&M manual will
include maintenance logs that will be kept current by plant personnel.
Critical spare parts requirements will also be pulled from the vendor operations and maintenance manuals,
and an integrated list will be developed. Spare parts critical to plant operation and/or with long
procurement lead times will be maintained in on-site inventory. In some instances, high-cost items may
not be stocked if their cost is greater than the risk-weighted cost of a plant outage in the event of
unexpected component failure.
7.1.2 Financial Sustainability
Describe the process used (or propose to use) to account for operational and capital costs.
Describe how rates are determined (or will be determined). What process is required to set rates?
Describe how you ensure that revenue is collected.
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If you will not be selling energy, explain how you will ensure that the completed project will be
financially sustainable for its useful life.
PBVC’s existing accounting and bookkeeping system will be used to account for operational and capital
costs. Costs will be categorized in accordance with the USOA and tracked as needed for grant reporting
and/or tax purposes.
PBVC’s electricity rates are set by PBVC’s governing board. PBVC electricity rates have traditionally been
set to cover costs with appropriate margin for unforeseen events.
Revenue is collected in accordance with our tariff, including provisions for account disconnect or referral to
collections in the event of non-payment of utility bills.
7.1.2.1 Revenue Sources
Briefly explain what if any effect your project will have on electrical rates in the proposed benefit area over
the life of the project. If there is expected to be multiple rates for electricity, such as a separate rate for
intermittent heat, explain what the rates will be and how they will be determined
Collect sufficient revenue to cover operational and capital costs
What is the expected cost-based rate (as consistent with RFA requirements)
If you expect to have multiple rate classes, such as excess electricity for heat, explain what those rates
are expected to be and how those rates account for the costs of delivering the energy (see AEA’s
white paper on excess electricity for heat)..
Annual customer revenue sufficient to cover costs
Additional incentives (i.e. tax credits)
Additional revenue streams (i.e. green tag sales or other renewable energy subsidies or programs that
might be available)
Electric rates with the project will depend on the final financing plan for the project.
Rates for dispatchable energy will be set to be competitive against the variable price of fuel-fired
heating. The estimated rate for dispatchable energy is $0.10 per kWh.
PBVC assumes no revenue from tax credits or sale of renewable energy credits from the project. PBVC will
consider tax credits, obligatory, and voluntary REC market opportunities that are available at the time of
construction. The decision to pursue these revenue streams will depend on the cost to qualify for the
programs, potential revenue, and perceived risk. In the event incremental revenues from such sources are
realized, they may be used to lower electric rates as determined by PBVC management.
7.1.2.2 Power Purchase/Sale
The power purchase/sale information should include the following:
Identification of potential power buyer(s)/customer(s)
Potential power purchase/sales price - at a minimum indicate a price range (consistent with the Section
3.16 of the RFA)
Identify the potential power buyer(s)/customer(s) and anticipated power purchase/sales price range.
Indicate the proposed rate of return from the grant-funded project. Include letters of support or power
purchase agreement from identified customers.
PBVC will use all electricity from the project to meet existing and future loads within its certificated service
area. This may include dispatchable loads as described elsewhere in this proposal.
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SECTION 8 – PROJECT READINESS
8.1 Project Preparation
Describe what you have done to prepare for this award and how quickly you intend to proceed with work
once your grant is approved.
Specifically address your progress towards or readiness to begin, at a minimum, the following:
The phase(s) that must be completed prior to beginning the phase(s) proposed in this application
The phase(s) proposed in this application
Obtaining all necessary permits
Securing land access and use for the project
Procuring all necessary equipment and materials
Refer to the RFA and/or the pre-requisite checklists for the required activities and deliverables for each
project phase. Please describe below and attach any required documentation.
PBVC has been pursuing this project since 2008. We have advanced the project through reconnaissance
and feasibility study and most recently final design and permitting. Applications have been submitted for
all major permits required for construction, and permit issuance is expected by or before December 2020.
We expect to begin construction in 2022, as grant funds would become available in July 2021, too late to
complete a procurement process and mobilize a contractor to Pedro Bay for the 2021 construction season.
8.2 Demand- or Supply-Side Efficiency Upgrades
If you have invested in energy efficiency projects that will have a positive impact on the proposed project,
and have chosen to not include them in the economic analysis, applicants should provide as much
documentation as possible including:
1. Explain how it will improve the success of the RE project
2. Energy efficiency pre and post audit reports, or other appropriate analysis,
3. Invoices for work completed,
4. Photos of the work performed, and/or
5. Any other available verification such as scopes of work, technical drawings, and payroll for work
completed internally.
PBVC completed energy upgrades of several community buildings in 2008. The final upgrade report is
included in the Section 12 document list. These upgrades reduce the demand for standard electric service
and also dispatchable electric service, allowing hydro output to be distributed to more buildings in the
village.
SECTION 9 – LOCAL SUPPORT AND OPPOSITION
Describe local support and opposition, known or anticipated, for the project. Include letters, resolutions,
or other documentation of local support from the community that would benefit from this project. Provide
letters of support, memorandum of understandings, cooperative agreements between the applicant, the
utility, local government and project partners. The documentation of support must be dated within one
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year of the RFA date of July 20, 2020. Please note that letters of support from legislators will not count
toward this criterion.
Local letters of support are submitted with the application. No local or other opposition to the project is
known.
This project is included in the 2013 Phase 1 and 2015 Phase 2 Bristol Bay Energy Plans as a community
energy priority (Phase 2, vol 2 page 126) and in the existing / planned hydro inventory (Phase 1, Table 10,
Phase 2, Vol 2, Table 11).
This project is also included in AEA’s April 2020 report listing shovel-ready Energy Infrastructure projects in
Alaska (page 7).
SECTION 10 – COMPLIANCE WITH OTHER AWARDS
Identify other grants that may have been previously awarded to the Applicant by AEA for this or any other
project. Describe the degree you have been able to meet the requirements of previous grants including
project deadlines, reporting, and information requests.
PBVC has successfully and fully complied with all other grant awards from AEA for this (see application
section 2.6) and other projects, including:
- Building energy efficiency upgrades (AEA Grant AEA grant #2195225.
- Diesel Powerhouse upgrade (2012, AEA PO RQ-4071).
SECTION 11 – LIST OF SUPPORTING DOCUMENTATION FOR PRIOR PHASES
In the space below, please provide a list of additional documents attached to support completion of prior
phases.
- Hydroelectric Reconnaissance Study Knutson Creek Drainage, Town Creek, and Dumbbell Lake, Pedro Bay,
Alaska, October 2009.
- Knutson Creek Hydroelectric Feasibility Study, Final Report. November 2013.
- FERC DI-14-06. Non-jurisdictional Finding for Knutson Creek, Alaska.
- U.S. Army Corps of Engineers Wetland Permit Application and correspondence.
- ADNR Water Rights application and status correspondence. LAS 33115.
- ADNR Dam Safety. Non-jurisdictional status affirmed June 29, 2020.
- ADFG Fish Habitat permit correspondence and resource studies.
SECTION 12 – LIST OF ADDITIONAL DOCUMENTATION SUBMITTED FOR CONSIDERATION
In the space below, please provide a list of additional information submitted for consideration.
- AEA April 2020 List of Shovel-Ready Energy Infrastructure Projects in Alaska.
- Bristol Bay Energy Plan (Phase 1 and 2 reports).
- Village End Use Energy Efficiency Measures Program, Final Report, AEA grant #2195225