HomeMy WebLinkAboutSigned round 15 ApplicationRenewable Energy Fund Round 15
Grant Application – Standard Form
AEA 23046 Page 1 of 51 10/04/2022
Application Forms and Instructions
This instruction page and the following grant application constitutes the Grant Application Form for
Round 15 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:
https://www.akenergyauthority.org/What-We-Do/Grants-Loans/Renewable-Energy-Fund/2022-
REF-Application.
What follows are some basic information and instructions for this application:
• 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 15 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 Coordinator by email
at grants@akenergyauthority.org or by phone at (907) 771-3081.
Renewable Energy Fund Round 15
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.
Renewable Energy Fund Round 15
Grant Application – Standard Form
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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)
Nushagak Electric & Telephone Cooperative
Tax ID # 92-0177246
Date of last financial statement audit: March 30, 2022
Mailing Address: Physical Address:
Box 350 557 Kenny Wren Rd
Dillingham, AK 99576 Dillingham, AK 99576
Telephone: Fax: Email:
907-842-5251 907-842-2799 wchaney@nushagak.coop
1.1 Applicant Point of Contact / Grants Coordinator
Name: Will Chaney Title: CEO/GM
Mailing Address:
Nushagak Electric & Telephone Cooperative
Box 350
Dillingham, AK 99576
Telephone: Fax: Email:
907-843-1489 907-842-2799 wchaney@nushagak.coop
1.1.1 Applicant Signatory Authority Contact Information
Name: Will Chaney Title: CEO/GM
Mailing Address:
Nushagak Electric & Telephone Cooperative
Box 350
Dillingham, AK 99576
Telephone: Fax: Email:
907-842-5251 907-842-2799 wchaney@nushagak.coop
1.1.2 Applicant Alternate Points of Contact
Name Telephone: Fax: Email:
Angelita Venua 907-842-5251 907-842-2799 avenua@nushagak.coop
Renewable Energy Fund Round 15
Grant Application – Standard Form
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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 #____45_, 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
https://www.akenergyauthority.org/What-We-Do/Grants-Loans/Renewable-Energy-
Fund/2022-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)
Renewable Energy Fund Round 15
Grant Application – Standard Form
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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.
Nuyakuk River Hydroelectric Project (Run of River Project)
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 Coordinator by email at grants@akenergyauthority.org or by phone at (907) 771-
3081.
Latitude 59.910807 N Longitude 158.118627 W
The proposed Project would be located on the Nuyakuk River approximately 60 miles north of
Dillingham, AK (pop. 2,364). The Project is located within the watershed that drains the eastern
side of the Wood River Mountains. The Project’s generating infrastructure and initial transmission
site would be inside the current Wood-Tikchik State Park boundary by approximately 4 miles. The
Project River intake would divert water from the Nuyakuk River, above Nuyakuk Falls, located
about 4.6 river miles downstream from the Tikchik Lake outlet to the powerhouse located at the
base of Nuyakuk Falls, at approximately river mile 5.3. From the Project site, the Nuyakuk River
runs approximately 40 miles before converging with the Nushagak River, which continues to Bristol
Bay.
2.2.2 Community benefiting – Name(s) of the community or communities that will be the
beneficiaries of the project.
Koliganek, New Stuyahok, Ekwok, Aleknagik, Dillingham, Levelock
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 (Broadband) ☐ 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
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Grant Application – Standard Form
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☒ Feasibility and Conceptual Design ☐ Construction
2.4 Project Description
Provide a brief, one-paragraph description of the proposed project.
The proposed Project is a new 10-12 MW run of river hydropower project consisting of an intake
structure, power conduit, powerhouse forebay, powerhouse, and tailrace channel approximately 4
miles downstream of the Tikchik Lake outlet above a natural fall on the Nuyakuk River. Power from
the Project would be available to the customers of the Cooperative and potentially other areas in
the region. The renewable power provided by the Project would represent a significant upgrade to
the current distribution system and minimize the reliance of local communities on fossil fuels as
their primary source of electricity. Currently, the population that would be served by this Project
relies wholly on diesel generation, which is barged upstream through the Nushagak River drainage
to requisite locations. The reduction (or elimination) of water transport of fuels will reduce the
potential for negative environmental impacts due to spills. The primary industry in the Project
service area is related to commercial harvest and processing of salmon. The long-term demand for
more reliable, efficient, and cost-effective renewable electric power, dispatchable renewable
thermal heat, high-speed broadband, along with the likely limited resource impacts makes this
Project a highly viable opportunity.
Initially this Project will replace up to 1.5 million gallons of diesel fuel annually displacing current
generation. Annualize power production modeling shows significant energy (approximately 30,000
MWh). Eventually, up to 2.5 million gallons per year of diesel fuel will be replaced with renewable
hydro energy which will provide electric power, heating, or thermal conversion to other useful
energy needs. We believe the combination of renewable energy and increased broadband access
will provide the basis for economic and social improvement and growth in the region for
generations to come.
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.
REF funding will be applied to Phase II of this Project.
Phase II will include the continued implementation of the FERC Integrated Licensing Process (ILP)
with specific emphasis on conducting the 2023 and 2024 natural resource and engineering study
seasons, with an eye toward the completion milestone of filing of the 2023/24 Study Season
Report for FERC Project No. 14873 in the Fall of 2023 and 2024 and NETC Board action to
continue Project work. Specific REF Grant Allocation spending will include Aquatics and Fisheries
Resource Studies, Water Quality/Quantity Resource Studies, Terrestrial Resources Studies,
Cultural Resources Studies, Recreational and Aesthetics Resources Studies, Engineering/Project
Design, and advancement of Regulatory Process.
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
($)
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Grant Application – Standard Form
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13 Nuyakuk River Hydroelectric Project AMD 63452 Y $1,000,000
14 Nuyakuk River Hydroelectric Project App #14001 Y $1,000,000
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
Phase II Task 1
Regulatory/FERC/
Permitting/Project
Management
Study
Preparation
2023 Study
Season
Report/NETC
Board action to
continue Project
Permitting,
logistics, planning,
coordination
with Cooperative
on travel,
schedules, GIS
support, etc.
1/1/23 12/31/24 Study Report
Phase II Task 2
Regulatory/FERC/
Permitting/Project
Management
Implement Field
Studies
2023 Study
Season
Report/NETC
Board action to
continue Project
Overall
management of
study program,
hydrology, water
quality, engineering
(Hydraulic
modeling and work
with other
models), sub
management
1/1/23 12/31/24 Study Report
Phase II Task 3
Regulatory/FERC/
Permitting/Project
Management
Document
Development/Ma
nagement
2023 Study
Season
Report/NETC
Board action to
continue Project
Initial Study Report,
GIS support for all
reporting, Internal
meetings, requisite
ARWG meetings
associated with
process,
Environmental
Justice Study and
PR
1/1/23 12/31/24 Study Report
Phase II Task 4
Regulatory/FERC/
Permitting/Project
Management
Strategy/FERC
2023 Study
Season
Report/NETC
Board action to
continue Project
Presentation
support to local
entities and
villages, Meeting
prep,
1/1/23 12/31/24 Study Report
Renewable Energy Fund Round 15
Grant Application – Standard Form
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and Agency
Interaction
Consultation
record/website and
FERC
filings,
Advancement of
design and work
w/preliminary
Geotech, meeting
prep.
Phase II Task 5
Fish and Aquatics
Studies
Fish Community
& Behavior
2023 Study
Season
Report/NETC
Board action to
continue Project
Study:
Literature review,
Netting, Snorkeling,
Tracking, Sonar,
Reporting
1/1/23 12/31/24 Study Report
Phase II Task 6
Fish and Aquatics
Studies
Falls Fish
Passage
2023 Study
Season
Report/NETC
Board action to
continue Project
Study: Tagging,
Tracking,
Bathymetry,
Modeling,
Reporting
1/1/23 12/31/24 Study Report
Phase II Task 7
Fish and Aquatics
Studies
Fish Entrainment
2023 Study
Season
Report/NETC
Board action to
continue Project
Study: Utilization of
existing data,
Conceptual
intake design,
Reporting
1/1/23 12/31/24 Study Report
Phase II Task 8
Fish and Aquatics
Studies
Fish Attraction
2023 Study
Season
Report/NETC
Board action to
continue Project
Study: Utilization of
existing data,
Conceptual
tailrace design,
Reporting
1/1/23 12/31/24 Study Report
Phase II Task 9
Fish and Aquatics
Studies
Life Cycle Model
Support
2023 Study
Season
Report/NETC
Board action to
continue Project
Study: Model
development,
Calibration, Data
incorporation,
Project impacts
analysis,
Reporting
1/1/23 12/31/24 Study Report
Phase II Task 10
Fish and Aquatics
Studies
Risk Assessment
2023 Study
Season
Report/NETC
Board action to
continue Project
Study: Risk
identification, data
utilization, itemize
potential site-
specific risks,
reporting
1/1/23 12/31/24 Study Report
Phase II Task 11
Terrestrial Studies
General
Vegetation/Wetland
Mapping
2023 Study
Season
Report/NETC
Board action to
continue Project
Study: Meetings,
Desktop analysis,
GIS work, Final
map production
1/1/23 12/31/24 Study Report
Renewable Energy Fund Round 15
Grant Application – Standard Form
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Phase II Task 12
Terrestrial Studies
Field Vegetation
Surveys/Wetland
Delineation
2023 Study
Season
Report/NETC
Board action to
continue Project
Study: Prep, Field
surveys, Final
W&W map
1/1/23 12/31/24 Study Report
Phase II Task 13
Terrestrial Studies
Caribou
Population
Evaluation
2023 Study
Season
Report/NETC
Board action to
continue Project
Study: Meeting
w/ADFG, Desktop
work,
Preparation of
Evaluation Report
1/1/23 12/31/24 Study Report
Phase II Task 14
Terrestrial Studies
Consultation,
Agency
Interaction
2023 Study
Season
Report/NETC
Board action to
continue Project
Study: Any
necessary internal
strategy, Agency
meetings, etc.
1/1/23 12/31/24 Study Report
Phase II Task 15
Cultural Studies
Study Planning
2023 Study
Season
Report/NETC
Board action to
continue Project
Study: Site visit,
Desktop work,
Recon of T-line,
Predictive model,
APE
1/1/23 12/31/24 Study Report
Phase II Task 16
Cultural Studies
Study
Implementation
and Reporting
2023 Study
Season
Report/NETC
Board action to
continue Project
Study: Field
surveys, TCP
interviews,
Reporting,
HPMP
1/1/23 12/31/24 Study Report
Phase II Task 17
Cultural Studies
Study Program
Management
2023 Study
Season
Report/NETC
Board action to
continue Project
Study: Agency
interaction,
Strategy, Tribal
consultation
1/1/23 12/31/24 Study Report
Phase II Task 18
Recreation and
Visual Studies
Meetings and
Project
Management
2023 Study
Season
Report/NETC
Board action to
continue Project
Study:
Coordination,
Agency and
Cooperative
meetings, Desktop
preparation
1/1/23 12/31/24 Study Report
Phase II Task 19
Recreation and
Visual Studies
Recreation Study
2023 Study
Season
Report/NETC
Board action to
continue Project
Study: Survey
development,
Survey distribution,
Communications
coordination,
Seasonal
intercept surveys,
reporting
1/1/23 12/31/24 Study Report
Phase II Task 20
Recreation and
Visual Studies
Noise Study
2023 Study
Season
Report/NETC
Board action to
continue Project
Study: Ambient
surveying, Sound
modeling,
Reporting,
Presentations
1/1/23 12/31/24 Study Report
Renewable Energy Fund Round 15
Grant Application – Standard Form
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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 $1,000,000
Cash match to be provideda $200,000
In-kind match to be provideda $
Energy efficiency match providedb $
Total costs for project phase(s) covered in application (sum of
above)
$1,200,000
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.
Nushagak has spent $578,624 to complete Phase I and an additional $1,172,010 on Phase II
tasks to date. The remaining $4,298,990 needed to complete Phase II will come from a
combination of $3,000,000 awarded in Renewable Energy Fund Rounds 13, 14, and 15, $500,000
from the Denali Commission, and the remainder from direct allocations from the State of Alaska,
USDA/RUS, BIA Indian Energy, DOE Indian Energy, and further Nushagak Electric & Telephone
Cooperative capital investment and debt service obligations.
Phase II is the larger funding issue, because grant programs at USDA/RUS, BIA and DOE do not
allow funding for feasibility studies. Meetings with all the agencies listed indicate strong interest in
funding once a FERC Operational License is issued, a milestone for Phase III completion.
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.
Cost overruns/shortfalls will be met with additional capital spending by NETC. NETC has an
adequate line of credit with NRU/CFC to cover these contingencies. Current unencumbered line of
credit is $6,600,000
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 $578,624
Feasibility and Conceptual Design Estimated $5,471,000
Final Design and Permitting Estimated $8,960,000
Construction (Broken Down)
Construction – Hydro facilities & Transmission to
Aleknagik & Dillingham
Estimated $98,000,000
Construction – Transmission to Koliganek, New
Stuyahok, Ekwok, & Levelock
Estimated $42,000,000
Total Project Costs (sum of above) Estimated $155,009,624
Metering/Tracking Equipment [not included in project
cost]
Estimated Included in
construction
costs
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Grant Application – Standard Form
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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.
• 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)
As part of developing the Project feasibility NETC held a series of meetings in advance of initiating
the FERC ILP licensing process. From October 2017 through the FERC Scoping Meeting in
December of 2019 we held 92 stakeholder meetings. While most of these meetings were intended
to introduce the Project and gauge support, we also took the opportunity to explore funding options
for Project construction. Opportunities identified include:
• 12/17/2017 Met with NRUCFC, Sheldon Peterson/CEO, verbal support for debt service
with an operating license
• 12/17/2017 Met with USDA/RUS, Chris McLean acting administrator, also verbal support
for debt service with an operating license, specific program identified, use of underutilized SUTA
funds
• 1/26/2018 Met with AEA/AIDEA, discussed the Renewable Energy Fund, Power Project
Fund as opportunities for study or construction funding
• 11/13/2019 Met with BIA Indian Energy & Economic Development, Jack Stevens,
discussed programs including EMDP and TEDC grants that could be applied for by Tribal
organizations for inter-tie transmission line build.
• 11/13/2019 Met with DOE Indian Energy Director Frost, discussed several grant and
technical assistance options including grant opportunities that could be applied for by Tribal
organizations for inter-tie transmission line build.
• Met with Denali Commission staff on multiple occasions in early 2020, Tom Wolf, Energy
Program Manager, and Janet Davis, Grants Management Officer. Received $500,000 in Project
funding in 2022
• Met on several occasions with State Legislative delegation and Administration. Have
submitted a CAPSIS request each of the last three years.
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 Coordinator by email at
grants@akenergyauthority.org or by phone at (907) 771-3081.
Phase 1 — Reconnaissance
Milestone or Task
Anticipated
Completion
Date
RE- Fund
Grant Funds
Grantee
Matching
Funds
Source of
Matching
Funds:
Cash/In-
kind/Federal
TOTALS
Renewable Energy Fund Round 15
Grant Application – Standard Form
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Grants/Other
State
Grants/Other
Acquisition of Park Access
Legislation and Public
Outreach Expense
$ $32,615 Cash $32,615
Site logistics & transportation $ $46,159 Cash $46,159
Survey/Field work $ $156,523 Cash $156,523
Preliminary Permit Application 6/11/2018 $ $20,000 Cash $20,000
Prepare Preliminary
Application Document (PAD) &
Notice of Intent (NOI)
10/8/2019 $ $40,000 Cash $40,000
FERC Scoping Process 3/18/2020 $ $20,000 Cash $20,000
Proposed Study Plan (PSP)
Development 4/16/2020 $ $60,000 Cash $60,000
FERC Regulatory Process
Management 4/16/2020 $ $80,000 Cash $80,000
Conceptual Project Design 2/1/2020 $ $50,000 Cash $50,000
Initial Economic Feasibility
Assessment 10/8/2019 $ $30,000 Cash $30,000
Project Kickoff Meeting with
Agencies 11/18/2019 $ $20,000 Cash $20,000
Project Management
(Nushagak Coop). $ $23,327 Cash $23,327
TOTALS $ $578,624 $578,624
Budget Categories:
Direct Labor & Benefits $ $23,327 $23,327
Travel & Per Diem $ $76,159 $76,159
Equipment $ $ $
Materials & Supplies $ $ $
Contractual Services $ $446,523 $446,523
Construction Services $ $ $
Other $ $32,615 $32,615
TOTALS $ $578,624 $578,624
Phase 2 — Feasibility and Conceptual Design
Milestone or Task
Anticipated
Completion
Date
RE- Fund Grantee
Matching
Source of
Matching
Funds:
TOTALS
Grant Funds Funds
Cash/In-
kind/Federal
Grants/Other
State
Grants/Other
Final Milestone for this Phase are
Study Reports for the tasks, the
2023/ 2024 Study Season Reports,
$ $
Renewable Energy Fund Round 15
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and the FERC Operating License
Application
Phase II Task 1
Regulatory/FERC/Permitting/Proje
ct Management
Study Preparation
12/31/2024
$75,000/R 15
$105,000 Cash $180,000
Phase II Task 2
Regulatory/FERC/Permitting/Proje
ct Management Implement Field
Studies
12/31/2024 $75,000/R 15 $305,000 Cash $380,000
Phase II Task 3
Regulatory/FERC/Permitting/Proje
ct Management Document
Development/Management
12/31/2024 $75,000/R 15 $125,000 Cash $200,000
Phase II Task 4
Regulatory/FERC/Permitting/Proje
ct Management Strategy/FERC
and Agency Interaction
12/31/2024 $235,000/R 13
$75,000/R 15
$290,000 Cash $600,000
Phase II Task 5 Fish and Aquatics
Studies
Fish Community & Behavior
12/31/2024 $480,000/R 14
$400,000/R 15
$69,000
$351,000
Denali
Cash $1,300,000
Phase II Task 6 Fish and Aquatics
Studies
Falls Fish Passage
12/31/2024 $300,00/R 14
$200,000/R 15
$50,000
$300,00
Denali
Cash $850,000
Phase II Task 7 Fish and Aquatics
Studies
Fish Entrainment
12/31/2024 $50,000 Denali
Commission $50,000
Phase II Task 8 Fish and Aquatics
Studies
Fish Attraction
12/31/2024 $50,000 Denali
Commission $50,000
Phase II Task 9 Fish and Aquatics
Studies
Life Cycle Model Support
12/31/2024 $100,000/R 13
$80,000/R 14 $180,000
Phase II Task 10 Fish and Aquatics
Studies
Risk Assessment
12/31/2024 $75,000/R 14 $5,000 Cash $80,000
Phase II Task 11 Terrestrial Studies
General Vegetation/Wetland
Mapping
12/31/2024 $25,000/R 14 $25,000
Phase II Task 12 Terrestrial Studies
Field Vegetation Surveys/Wetland
Delineation
12/31/2024 $100,000
Denali
Commission
$100,000
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Phase II Task 13 Terrestrial Studies
Caribou Population Evaluation
Section 106 Evaluation
12/31/2024 $40,000/R 14 $12,000
$13,000
Denali
Cash $65,000
Phase II Task 14 Terrestrial Studies
Consultation, Agency Interaction 12/31/2024 $41,000 Denali
Commission $41,000
Phase II Task 15 Cultural Studies
Study Planning 12/31/2024 $28,000 Denali
Commission $28,000
Phase II Task 16 Cultural Studies
Study Implementation and
Reporting
12/31/2024 $65,000 R 13 $10,000 Denali
Commission $75,000
Phase II Task 17 Cultural Studies
Study Program Management 12/31/2024 $25,000 Denali
Commission $25,000
Phase II Task 18 Recreation and
Visual Studies
Meetings and Project Management
12/31/2024 $22,000 Cash $22,000
Phase II Task 19 Recreation and
Visual Studies Recreation Study 12/31/2024 $100,000/R 15
$20,000
Denali
Commission
$120,000
Phase II Task 20 Recreation and
Visual Studies
Noise Study
12/31/2024 $45,000 Denali
Commission $45,000
Phase II Task 21
Initial Geotech
10/1/2022 $600,000/R 13 $105,000 Cash $705,000
Maintaining site (Camp) 10/1/2024 $350,000 Cash $350,000
TOTALS $1,000,000/R13
$1,000,000/R14
$1,000,000/R15
$500,000
$1,971,000
Denali
Cash $5,471,000
Budget Categories:
Direct Labor & Benefits $ $120,000 $120,000
Travel & Per Diem $ $150,000 $150,000
Equipment $ $120,000 $120,000
Materials & Supplies $ $170,000 $170,000
Contractual Services
$1,000,000/R13
$1,000,000/R14
$1,000,000/R15
$1,911,000 $4,911,000
Construction Services $ $ $0
Other $ $ 0
TOTALS $3,000,000 $2,471,000 $5,471,000
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Phase 3 — Final Design and Permitting
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
Phase III Task 1: Engineering
& Legal, resulting in an
Engineer Procure Construct
(EPC) contract and financial
agreements
12/31/2025 $ $1,000,000 Cash $1,000,000
Phase III Task 2: Land
Access and Use Agreements 12/31/2026 $ $200,000 Cash $200,000
Phase III Task 3: Site/Study
Permitting 12/31/2025 $ $250,000 Cash $250,000
Phase III Task 4: Economic
and Financial Analysis 12/31/2025 $ $100,000 Cash $100,000
Phase III Task 5:
FERC/Regulatory Process
Management and License
Application Preparation
12/31/2026 $ $2,000,000 Cash $2,000,000
Phase III Task 6: Project
Management and Outreach
(Nushagak Coop.)
12/31/2026 $ $60,000 Cash $60,000
Phase III Task 7: Secondary
Geotechnical Study 12/31/2025 $ $1,300,000 Cash $1,300,000
Phase III Task 8: Engineering
Design 12/31/2026 $ $2,300,000 Cash $2,300,000
Phase III Task 9: Permits &
Consultation 12/31/2026 $ $200,000 Cash $200,000
Phase III Task 10: Preparation
of Environmental/Natural
Resource Management Plans
12/31/2026 $ $1,000,000 Cash $1,000,000
Phase III Task 11: Land Use
Authorization 12/31/2026 $ $500,000 Cash $500,000
Phase III Task 12:
Adjudication of Water Right 12/31/2026 $ $50,000 Cash $50,000
Totals $8,960,000 $8,960,000
Budget Categories:
Direct Labor & Benefits $ $60,000 $60,000
Travel & Per Diem $ $20,000 $20,000
Equipment $ $25,000 $25,000
Materials & Supplies $ $25,000 $25,000
Contractual Services $ $8,830,000 $8,830,000
Construction Services $ $ $
Other $ $ $
TOTALS $ $8,960,000 $8,960,000
Phase 4 — Construction
Milestone or Task
Anticipated
Completion
Date
RE- Fund
Grant
Funds
Grantee
Matching
Funds
Source of
Matching
Funds:
TOTALS
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Cash/In-
kind/Federal
Grants/Other
State
Grants/Other
EPC Construction Services 12/31/2029 $ $129,000,000 Cash $129,000,000
Environmental Monitoring &
Reporting 12/31/2029 $ $8,000,000 Cash $8,000,000
Permit Reporting 12/31/2029 $ $3,000,000 Cash $3,000,000
Project Management
(Nushagak Coop) 12/31/2029 $ $125,000 Cash $125,000
$ $ $
$ $ $
$ $ $
$ $ $
$ $ $
$ $ $
$ $ $
$ $ $
TOTALS $ $140,125,000 $$140,125,000
Budget Categories:
Direct Labor & Benefits $ $125,000 $125,000
Travel & Per Diem $ $5,000,000 $5,000,000
Equipment $ $25,000,000 $25,000,000
Materials & Supplies $ $5,000,000 $5,000,000
Contractual Services $ $5,000,000 $5,000,000
Construction Services $ $100,000,000 $100,000,000
Other $ $ $
TOTALS $ $140,125,000 $140,125,000
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.
The costs associated with Phase II through IV of this Project were developed with NETC’s project
consultant, McMillen Jacobs Associates, and reflects their experience in like kind hydroelectric
development in the State of Alaska. In the past 10 years, McMillen Jacobs Associates has worked
on over 15 hydroelectric projects in Alaska, with services including feasibility assessments,
engineering, design-build construction, natural resource study program management, and FERC
licensing, relicensing, license amendments, and license implementation and compliance. McMillen
Jacobs recently assisted Homer Electric Association (Kenai Hydro, LLC) with the acquisition of an
original license for the Grant Lake Hydroelectric Project (FERC No. P-13212), including all phases
of license application preparation, natural resource study program management and
implementation, and engineering design. The Grant Lake project received a FERC operating
license in August 2019 and project generation is expected to begin in 2026 following a 2-year
construction period.
3.3 Project Communications
3.3.1 Project Progress Reporting
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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?
NETC will provide quarterly and annual progress reports to AEA, this will track with FERC reporting
requirements. These reports with contain both specific grant expenditures and overall Project
progress including intra-milestone Project advances. In addition, NETC will provide AEA copies of
the FERC required annual/seasonal reports and the go/no go Board actions associated with these
reports.
Documents that mark the individual completion of Tasks and Phases that lead to the FERC
Operating Permit Application will also be posted to the Project website,
https://www.nuyakukhydro.com/ and to the FERC document portal using the identifier for this
Project P-14873, https://elibrary.ferc.gov/eLibrary/search
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.
NETC utilizes holistic accounting National Information Solutions Cooperative (NISC) software that
includes project work order line item and categorical expenditures. NETC will provide these reports
to AEA quarterly and annually.
In the past 10 years NETC has successfully completed reporting for two USDA/RUS HECG Grants
along with a previous AEA REF Grant. In addition, NETC has completed a PPP loan/forgiveness
cycle and has received a USDA/RD ReConnect grant for a Broadband project. Both have been
successful in meeting financial reporting requirements.
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.
Project management duties for Phases II and III will be contracted to McMillen Jacobs Associates
to build on Project development accomplished in Phase I. In addition, Project management support
will be provided by Mr. Will Chaney, NETC’s General Manager.
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.
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Project accounting for Phases II and III will be provided by NETC’s in-house accounting
department led by Senior Accountant Angelita Venua. In addition, NETC will undergo yearly third-
party audits.
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.
Applicant:
Nushagak Electric and Telephone Cooperative (NETC) is a member-owned Cooperative providing
electric and telecommunications services in rural Alaska. NETC’s offices and power production
facility are located in Dillingham, Alaska. NETC’s electric division generates and distributes electric
service to the communities of Dillingham and Aleknagik and has been providing distributed electric
energy to these communities since 1965. NETC has 11.2 MW of diesel generation capacity with
1,475 metered customers. For all Phases/Milestones: NETC will be responsible for Project
outreach, Project finance, Project accounting and supporting Project management. Direct
milestone responsibility in Phase II and Phase III includes Economic and Financial Analysis,
Project Management and Outreach, Land Access and Use Agreements, and Site/Study Permitting.
NETC personnel are all residents of Bristol Bay and have extensive western Alaska logistical
knowledge. Scheduling and other resources will be process-driven and goal-oriented.
Contractors:
McMillen Jacobs Associates will provide consulting services to the applicant, overall project
management, including regulatory services, meeting facilitation, study plan development and
management, RFP development and contractor selection. McMillen Jacobs will also act as general
Project manager through Phases II and III with overall responsibility to maintain both the FERC ILP
timeline and reporting and meet REF Grant funding timelines and Project update reporting. Phase
II direct milestone responsibilities include Fisheries Assessments, Water Quality Assessment -
Dissolved Oxygen and Water Temperatures, Flow Duration Curve Assessment, Ice Processes
Assessment, Botanical and Wetlands Survey, Terrestrial Evaluations, Cultural Studies, Meeting
Facilitation, Preliminary Design & Engineering, FERC/Regulatory Process Management, and
requisite FERC document development.
Kleinschmidt/R2: Kleinschmidt/R2 has extensive fisheries experience associated with hydroelectric
licensing experience including six projects in Alaska. They will provide fish passage and aquatics
consulting. They will be responsible for the implementation of Phase II and Phase III fisheries
studies including Fish Species Abundance and Distribution Near the Project Area, Nuyakuk Falls
Fish Passage Study, Fish Entrainment and Impingement Study, and Assessment of False
Attraction at the Tailrace Fish Barrier.
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QEDA Consulting: QEDA Consulting has been retained to develop a comprehensive Life Cycle
Model (LCM) that will provide detailed information about potential impacts to salmonid and resident
fish species as a result of Project development. QEDA has successfully developed similar LCMs
for salmonid species populations in other watersheds.
Cultural Resources Consultants: CRC has extensive background in cultural resource evaluations in
Alaska associated with existing and proposed hydro facilities. They will provide the Project with
their experience in developing and completing our cultural resource-based Phase II and Phase III
studies: Cultural Resources Subsistence Study and Cultural Resources Section 106 Evaluation.
Initial Geotechnical Study: This was completed in 2022 by contractor Discovery Drilling.
NOAA/NMFS: NMFS recommended the Future Flows Assessment during the study plan
development process. We have engaged with them in a collaborative effort to complete this Phase
II study.
Alaska Department of Fish & Game: We are engaging in a collaborative effort with ADF&G to
extend existing ADF&G programs to complete the Caribou Population Evaluation and the
Subsistence Phase II and Phase III Study.
MLP & Associates (MLP&A): MLP&A will be performing the Botanical and Wetlands Survey and
Caribou Population Evaluation Phase II studies. MLP&A is based in Alaska and has extensive
experience conducting botanical and wildlife studies in the region. The Alaska Department of Fish
& Game (ADF&G) has an extensive caribou tracking and monitoring program in the region and has
indicated a willingness to collaborate with NETC and MLP&A to provide existing data for use in the
Caribou Population Evaluation.
R&M Consultants: R&M Consultants, also located in Anchorage, will conduct the Recreation and
Aesthetic Resources Phase II studies. Additionally, R&M will engage a subconsultant with the
expertise to conduct the Noise Study. R&M brings exceptional project planning expertise to the
Project team and has successfully implemented similar studies on other FERC and hydroelectric
projects in Alaska.
4.2 Local Workforce
Describe how the project will use local labor or train a local labor workforce.
NETC and McMillen Jacobs will continue to use local resources for logistical support and
encourage the use of local resources to complete the contracted studies where the expertise exists
locally. NETC is currently seeking to hire local personnel to serve as Camp Manager at the Project
site, which will be a full-time seasonal position during both Project study seasons (2023 and 2024).
The power plant operations personnel will be trained from NETC existing power plant operational
personnel, all local. Additional necessary personnel will be hired locally through our local hire
initiative.
Transmission line operations will be handled by NETC’s current distribution line crew. Additional
workforce will be developed through our apprentice program
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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 primary mode of operation for this Project will be level control, whereby outflow is balanced to
inflow. The Project is conceived as a run-of-river project, with no storage component. As such,
power production will mimic some fraction of total river inflow to the Project site.
Mean daily discharge in the Nuyakuk River is presented, based on USGS gaging data available at
station 15302000 located near the outlet of Nuyakuk Lake. From the figure, it is clear that the
period of high flow in the river occurs between early summer and early fall. For the remainder of
the year, the river is running at near baseflow conditions. Because the Project will operate in run-
of-river mode, sizing the generating units should be done to either 1) optimize power production
during a specific time of year (e.g., during the winter months) or 2) produce power more or less
evenly throughout the year. Under the current Project conceptualization, units have been sized to
provide a stable amount of power from month to month while attempting to minimize overall capital
costs associated with the hydroelectric units, tunnel(s), and other Project components.
When powerhouse flows do not match the system loads, grid system electricity will have to be
supplemented with existing diesel generation. This will most likely be in the winter months when
the amount of water available to the powerhouse is less than the power demand would require.
The transmission grid will therefore have five diesel generation power plants tied together to
complete the electric grid system. The existing power plant in Dillingham has the ability to provide
energy for all six villages serviced by the transmission system throughout the year, except for the
month of July. This gives NETC the ability to feed the system from different sources as needed for
load or maintenance. NETC intends to optimize hydro generation unit design for high efficiencies
during winter low flow periods.
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The Project will have an installed total capacity of 10 to 12 MW and is based on the configuration
discussed above. Energy production also assumes the conceptual Project configuration described
above, with a single 30-ft diameter tunnel servicing the two units over a distance of 750 feet. For
those months in which the total available inflow to the powerhouse is less than the total
powerhouse flow capacity, a minimum instream flow of 1,000 cfs is assumed to pass downstream,
while the remainder is passed through the powerhouse to generate electricity. The predicted
average annual energy from the Project is 58,900 MWh representing a plant factor of 63%.
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Estimates will be revised once instream flow studies are completed, and any flow accretions below
Nuyakuk Lake are determined.
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.
The current distributed electrical energy demand in the communities is met through diesel
generation; the no action alternative would be continued diesel generation. This is the basis for our
financial modeling.
There have been other alternatives explored including wind and an alternate hydroelectric site;
NETC (Grant/Elva Hydro 2009, Wind Integration Study 2009) BBNC (Wind Feasibility Study 2005).
These were determined disadvantageous to the current diesel generation when evaluated and
were not pursued past the feasibility study.
The proposed Project has potential short and long-term financial, energy resiliency and
environmental advantages over the no action alternative. It has financial, maintenance, reliability,
production and longevity advantages over the other alternatives studied. At a community level a
seasonal lower cost source of dispatchable renewable heat along with year-round high-speed
broadband will enhance community sustainability and positively impact local economies.
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
NETC worked directly and intensively with the Alaska State Legislature to develop SB91 which
allows for the requisite natural resource and engineering assessment activities and FERC
regulatory processes that need to be conducted for an ultimate project feasibility determination.
SB91 was unanimously passed by the Alaska State Legislature in 2019 allowing for the
comprehensive evaluation of the site.
NETC acquired a Special Use Permit from ADNR, Division of Parks & Outdoor Recreation on April
1, 2020 (Permit #LAS 33198). The permit authorizes temporary use of the project site to conduct
scientific research, including geotechnical investigations, land surveying, and bathymetric
surveying. The permit includes provisions for the installation of a man camp that will be used to
house Project personnel on site. The permit is effective May 1, 2020 through May 1, 2023.
NETC will continue to engage with all requisite agencies to obtain additional permits for conducting
natural resource studies and engineering evaluations, as needed. NETC is currently in the process
of developing natural resource study methodologies, and once study plans are finalized NETC will
coordinate with requisite agencies to obtain all required permits prior to initiating studies and on-
site engineering assessments. NETC has had additional dialogue with ADFG regarding additional
study permit needs and is currently in the process of developing the requisite applications.
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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 on a bluff on the south bank of the Nuyakuk River adjacent to Nuyakuk Falls,
within Wood-Tikchik State Park. The Project site is currently undeveloped with the exception of a
portage trail used by boaters to bypass the falls. As discussed above, SB91 provides NETC with
permission to comprehensively study the site for hydroelectric project development.
NETC is currently establishing a man camp at the site for use in housing personnel during the
assessment through construction phases of the Project as described in Section 5.1.3.
The proposed Project boundary consists of 2,860.60 acres which includes a 75-ft buffer around all
Project facilities and on either side of the proposed transmission line. The Alaska Department of
Natural Resources (ADNR) manages a total of 1,666.57 acres (58.3 percent) of proposed Project
lands. Of this, 265.85 acres (9.3 percent) is land within Wood-Tikchik State Park. Native lands total
707.39 acres (24.7 percent) of proposed Project lands. The remainder of proposed Project lands
are owned or managed by the Bureau of Land Management (BLM) (357.08 acres or 12.5 percent)
and private or municipal entities own an additional 129.56 acres (4.5 percent). NETC plans to work
collaboratively with all landowners to obtain right-of-way as needed to install transmission lines
from the Project site to distribution locations.
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?
• 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.
NETC has gone to significant effort to avoid technical risks associated with this project by engaging
in early and consistent consultation with stakeholders and agencies and by taking a collaborative
approach with all interested parties. Stakeholders have been engaged from the initial feasibility
stages of the Project, and as discussed in Section 3.2.4, 92 stakeholder meetings were held
between October 2017 and December 2019. NETC voluntarily held a Project Kickoff Meeting in
November 2019 in advance of the FERC Scoping Meeting for the specific purpose of engaging
both public and agency stakeholders early in the licensing process.
Initial geotechnical information about the Project site was collected in August 2022 and is required
to avoid technical risks during Project design. The Initial Geotechnical Study is a preliminary site
investigation to assess/confirm rock quality at the proposed facilities and confirm project feasibility.
Final results of the initial study are currently pending. To date, geologic reconnaissance has been
limited to review of geologic maps for the Project vicinity and aerial photographs of the proposed
intake, powerhouse, tunnel, and tailrace sites. During the Secondary Geotechnical Study, NETC
will collect additional data necessary to confirm the conceptual design layout and support the
engineering design development of the Project. The Secondary Geotechnical Study will provide
geotechnical data for the final design of the proposed facilities.
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Obtaining necessary water appropriation for hydroelectric generation and Project design that is
protective of fisheries are expected to be the primary challenges associated with this Project. A
robust natural resource study program has been developed in order to thoroughly investigate all
potential Project effects to natural resources.
NETC invited key agencies and stakeholders to participate in an Aquatics Resource Working
Group (ARWG). The initial goal of the ARWG was to review and update the study plan as it
pertains to the aquatic environment in general and fish passage in particular. The ARWG began
meeting in 2020, and currently meets on a monthly basis. In June 2022, NETC hosted an in-person
meeting and site visit to enable the ARWG members to see the proposed Project site and have
extensive discussion regarding the Proposed Study Plan. As a result of the ARWG’s collaboration,
NETC filed a Revised Study Plan (RSP) that the ARWG agreed on, and FERC ultimately issued a
Study Plan Determination based on the RSP on August 27, 2022. Members of the ARWG include:
Bristol Bay Science and Research Institute (BBSRI), University of Washington Fisheries Research
Institute (FRI), State of Alaska Department of Fish and Game (ADF&G), National Marine Fisheries
Service (NMFS), United Tribes of Bristol Bay (UTBB), and NETC’s team.
The results of the natural resource study program and associated engineering assessments will
inform final Project engineering and design. NETC has retained FERC regulatory support and
engineering services from McMillen Jacobs Associates, a firm with experience designing and
licensing new hydroelectric projects within the State of Alaska. McMillen Jacobs Associates staff
will assist NETC with the licensing, natural resource and engineering aspects of the Project in
order to minimize risks to Project development, including securing water appropriation from ADNR.
Kleinschmidt/R2 will lead the fishery assessments throughout the natural resource study program.
Kleinschmidt/R2 has extensive experience conducting fishery studies in support of FERC
hydroelectric project licensing, thus protecting the Project against technical risk associated with
potential fishery resources impacts.
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’s comprehensive natural resource study program has been designed to evaluate
potential environmental and land use issues, including:
Aquatics/Fishery Resources, including Fish Passage, and Fishery-related Project Design
Considerations (Entrainment, Impingement, and False Attraction to Tailrace Flows)
Water Resources, including Water Quality, Ice Processes, and Future Flows
Botanical/Wetlands Resources
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Wildlife Resources and Wildlife Habitat (Caribou Population Evaluation)
Cultural Resources, including Subsistence Use, Archaeological Resources, and Historical
Resources
Recreation and Aesthetic Resources (including a Noise Study)
As discussed in Section 4.1.3, Project team members have extensive Alaska expertise that has
been retained to study environmental and land use issues. Each of the natural resource study
areas listed above consists of one or more studies, each of which is robust and designed to
investigate all aspects of Project development effects on the resource studied. The Project team
consists of expertise in each resource area to ensure that study results provide detailed
information regarding the nature of any environmental and land use issues that may exist. The
results of the natural resource study program will allow FERC to prepare an Environmental
Assessment (EA) as part of the Project licensing process. The natural resource study program and
the FERC-prepared EA will identify any environmental and land issues that may exist as a result of
Project development. Environmental Protection, Mitigation, and Enhancement Measures (PM&Es)
will be identified during the FERC licensing process to address Project-related effects.
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.
NETC’s current generation capacity includes eight Caterpillar diesel generation units, totaling
11.335MW of rated capacity, with Woodward EasyGen 3000XT controllers and SCADA monitoring
and control. Our power production facility is continually manned 24/7/365. NETC’s system loads
vary between 1.4 MW and 3 MW during 9 months of the year, September till May with very little
instantaneous load variance. NETC targets generator load at 80% rated capacity, allowing for both
efficiency and spinning reserve. In 2019 a total of 19.268 GWh were generated, over the last
decade yearly generation has remained between 19 GWh and 20 GWh.
Between June and August salmon processing pushes NETC electric load past 6MW at times. The
processors also create demand variance of up 1 MW. NETC’s operators and the processors
operating staff coordinate these known variances allowing for efficiency and adequate spinning
reserve.
Generated voltage is 4.16 kV, substation transformers convert to 7.2 kV for distribution. This is the
only substation in the distribution system and is comprised of two 10 MVA transformers running
parallel with the associated switchgear needed for 1:1 redundancy.
NETC acts as both a Generation/Transmission Cooperative and a Distribution Cooperative
providing electric service to our members in a harsh western Alaska coastal environment, from fuel
delivery to member outlet. NETC computes annual outage time per member for USDA Form 7
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reporting. This computation takes in the number of outages, members affected by the outage, the
amount of time service was down and cause of outage to determine the average time per year a
member was out of service. NETC’s total outage time per member in 2020 was 107 minutes or
99.999795% reliability. Our five-year average is 68.54 minutes per member or 99.999868%
reliability.
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: Diesel/Caterpillar 3516/1130kW/565kW/1800RPM/Electronic/Woodward EasyGen
3000XT/138436
Unit 2: Diesel/Caterpillar 3512B/1050kW/525kW/1800RPM/Electronic/ EasyGen 3000XT /90405
Unit 3: Diesel/Caterpillar 3512B/1050kW/525kW/1800RPM/Electronic/ EasyGen 3000XT /75168
Unit 4: Diesel/Caterpillar 3512B/1050kW/525kW/1800RPM/Electronic/ EasyGen 3000XT /81094
Unit 5: Diesel/Caterpillar 3512C/1050kW/525kW/1800RPM/Electronic/ EasyGen 3000XT /62849
Unit 6: Diesel/Caterpillar 3512C/1050kW/525kW/1800RPM/Electronic/ EasyGen 3000XT /64330
Unit 7: Diesel/Caterpillar 3456/455kW/223kW/1800RPM/Electronic/ EasyGen 3000XT /18400
Unit 8: Diesel/Caterpillar 3608A/2250kW/1125kW/900RPM/Electronic/ EasyGen 3000XT /2562
Unit 9: Diesel/Caterpillar 3608A/2250kW/1125kW/900RPM/Electronic/ EasyGen 3000XT /2136
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.
NETC’s existing electrical system is a standalone, isolated, grid consisting of a diesel power plant a
single substation located adjacent to the power plant and a distribution system. This is consistent
throughout the systems in the proposed Project.
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
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, approximately 50,000 gallons of
heating fuel oil is displaced for
community public schools &
community buildings along with an
additional 24,000 gallons of heating
fuel oil displaced for NETC facility and
tank farm heat.
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Month Generation Diesel
(kWh)
Fuel Consumption
(Diesel-Gallons)
Peak Load
(KW)
Minimum Load
(KW)
January 2022 1,518,968 101,685 2,630 1,250
February 2022 1,538,946 103,633 2,505 1,625
March 2022 1,266,059 86,088 2,215 1,540
April 2022 1,428,232 95,815 2,340 1,530
May 2022 1,796,463 121,170 3,974 1,632
June 2022 1,639,589 109,587 3,955 1,500
July 2022 3,284,252 217,983 6,480 1,700
August 2022 1,924,994 128,545 5,920 1,485
September 2022 1,266,910 86,793 2,103 1,296
October 2022 1,266,299 83,960 2,055 1,340
November 2022 1,370,867 91,997 2,455 1,410
December 2021 1,522,749 102,476 2,630 920
Total 19,824,328 1,329,732
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
February
March
April
May
June
July
August
September
October
November
December
Total
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
5.4.2.4 O&M and replacement costs for
existing units
Power Generation Thermal Generation
i. Annual O&M cost for labor $1,229,945
ii. Annual O&M cost for non-labor $3,149,551
iii. Replacement schedule and cost for
existing units
$25,000,000 over the
next 30 years
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year forecasts. As appropriate, include expected changes to energy demand, peak load, seasonal
variations, etc. that will affect the project.
Presently hot water is recovered from diesel genset cooling systems via heat exchangers to provide
heating to NETC buildings and fuel tanks along with and external thermal loop that sells distributed
thermal heat to the Dillingham elementary, middle, high school, regional school office, tribal, and
State facilities. Approximately 50,000 gallons of heating fuel is displaced annually for non-NETC
heating use and approximately 24,000 gallons of heating fuel is displaced annually for NETC facilities
and fuel tank farm heating.
NETC has recently completed an upgrade/rebuild of existing thermal loop with insulated non-
corrosive underground pipe, heat exchangers, VFD circulating pumps and controls to handle the
existing thermal load, along with future expansion capacity to service thermal loop expansion to other
community (Post Office, Bristol Bay College Campus, and City of Dillingham) facilities. Funding for
the current thermal heat loop is from NETC sources, funding for future thermal loop expansion and
additional heat exhaust recovery is being pursued through USDA/RUS High Energy Cost grant
programs. If approved this expansion project when fully implemented will recover and/or displace an
additional 250,000 gallons of fuel per year.
The vision is that this upgraded thermal loop system can still be fully utilized once the new hydro
generation facility comes on-line, either alone utilizing non-firm renewable energy, in parallel with
diesel gensets, or alone with diesel gensets during winter low flow hydro generation months. It is
anticipated that NETC’s Dillingham thermal loop system will be able to utilize approximately 5 to 7
GWh/year of non-firm renewable energy for heating once the hydro generation facility becomes
operational.
NETC’s future financial projections are a forty-year term based on the expected FERC Operational
License term and resultant debt service terms.
A twenty-year review of kWh sales by rate class shows level annual sales with a diminishing
residential sales component and an increasing large commercial sales component. At the same time
peak annual demand has risen with the large commercial sale, driven by salmon processing
seasonal loads.
As this Project matures, we will build into excess capacity through a non-firm (dispatchable) rate that
will encourage space heating and energy storage investments (domestic hot water, ice making, EVs)
As the rates are lowered through increased utilization more demand will be developed for firm power
consumption. This new demand will be primarily driven by conversion of previously dispatchable
loads as the firm/non-firm rates converge.
As we model the cost of power production a 5% growth rate is anticipated. If a 5% growth rate is
achieved we will reach the average annualized power production, less transmission loss (52.4GWh),
in eighteen years at which time the estimate cost of power production and transmission will be
.14/kWh. If the annual growth rate is 3% capacity will be reached in thirty years and the cost of power
production will be .15/kWh.
Forty years of modeled growth and power production costs, using a 5% growth rate. The beginning
annual sales reflect expected overall electric KWh sales for all communities in 2028 and do not
include current heat recovery sales. Growth includes firm and dispatchable KWh sales, and heat:
Year Annual Sales (GWh) Power Production Cost/kWh
2028 22.60 $0.28
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2029 23.73 $0.27
2030 24.92 $0.26
2031 26.16 $0.25
2032 27.47 $0.24
2033 28.84 $0.23
2034 30.29 $0.22
2035 31.80 $0.21
2036 33.39 $0.20
2037 35.06 $0.19
2038 36.81 $0.19
2039 38.65 $0.18
2040 40.59 $0.17
2041 42.62 $0.16
2042 44.75 $0.16
2043 46.98 $0.15
2044 49.33 $0.15
2045 51.80 $0.14
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.
The Project will consist of a single primary development centered around a river intake/diversion
located above Nuyakuk Falls and a single powerhouse facility located downstream below Nuyakuk
Falls. Additional Project facilities will include a single-bore tunnel arrangement to convey water from
the intake to the powerhouse, a tailrace conveyance channel to return water to the Nuyakuk River,
an airstrip with local access roads, a small building to house a maintenance shop on the lower level
and an operators’ residence on the upper level, and an electrical transformer and switchyard area to
step power up for high-voltage (34.5 kV) conveyance via overhead transmission to watershed
communities. Overhead transmission is currently estimated to cover 140 miles according to the
conceptualized route. The Project will likely also include a lower dock facility located near the
powerhouse/tailrace outlet to allow for docking of small water craft that can navigate the Nuyakuk
River back to the Nushagak River.
The powerhouse is conceptualized to contain two Kaplan-style reaction turbine generating units to
accommodate a combined maximum design flow of approximately 6,000 cfs divided evenly among
the units. The rated capacity on each unit would be approximately 5,380 kW. The gross head on
the Project is approximately 26 feet, based on site surveying work that occurred in June of 2019.
The proposed Project features have been developed based upon existing physical and
environmental information and are conceptual in nature. As part of the FERC ILP and the overall
feasibility process, additional information will be obtained through technical and environmental
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studies, and continuing research and consultation will be conducted with equipment manufacturers
and resource agencies. In May 2020, site-specific topographic and bathymetric LiDAR surveys were
conducted, and these data will be used in site analysis and Project design. As additional information
becomes available, the design features presented below can be expected to be refined and/or
modified to accommodate any changed conditions, including maintenance of instream flow
requirements.
SUMMARY OF PROJECT FEATURES
Number of Generating Units 2
Turbine Type Kaplan (Z-style or Vertical)
Runner Diameter (estimated) 12-ft
Operating Speed 124.1 rpm
Generator Type Synchronous
Rated Generator Output
Unit 1 5.38 MW
Unit 2 5.38 MW
Maximum Rated Turbine Discharge
Unit 1 3,000 cfs
Unit 2 3,000 cfs
Diversion Forebay Water Surface Elevation
Minimum (Preliminary) 250.0 (ft NAVD88)
Maximum (Preliminary) 275.0 (ft NAVD88)
Turbine Centerline Elevation (Preliminary) 231.67 (ft NAVD88)
Normal Tailwater Elevation
Minimum (Preliminary) 214.0 (ft NAVD88)
Maximum (Preliminary) 231.5 (ft NAVD88)
Average Annual Energy (assuming 23.2 feet of net head and an average monthly intake diversion
flow of 4,047 cfs or 6,700 kW) 58,900 MWh
Gross Head 26 feet ± fluctuation
Net Head at Maximum Rated Discharge 23.2 feet
Watershed Characteristics
Drainage Area 1,571 sq. mi.
Maximum Basin Elevation 5,250 (ft NAVD88)
Minimum Basin Elevation 248 (ft NAVD88)
Mean Annual Precipitation 59.0 inches
Area of Ponds or Lakes 12.4 %
Nuyakuk River Diversion (All aspects to-be-determined (TBD) once bathymetry and sub-bottom
profiling work is completed in 2020 and geotechnical reconnaissance results are available)
Structure Type Concrete Diversion / Low Head Weir (TBD)
Structure Length 100 feet
Average Monthly Water Height above Weir (Max) 5.40 feet
Crest Elevation 250.5
Water Conveyance (Pressurized Tunnel from Intake to Powerhouse)
Intake Style Possibly a diversion structure feeding a concrete open channel short canal. Single
canal could feed two vertical intake shafts (one per turbine unit)
Typical Open Channel Allowable Velocity < 3.0 ft/sec
Open Channel typical depths 10 to 15 ft
Open Channel width 175 to 250-ft
Tunnel Lip Elevation at Open Channel 250.5 (ft NAVD88)
Tunnel Construction Type TBD once field geotechnical drilling and data are compiled
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Length of inclined tunnels to powerhouse 750 feet
Tunnel Velocity at Maximum Turbine Discharge ~ 15 ft/sec
Single Tunnel Configuration
(one feeding two turbines)
Tunnel Flow Capacity 6,000 cfs
Unlined Tunnel Diameter 25-ft
Final Lined Diameter 23-ft
Base Elevation (Preliminary) 250.5 (ft NAVD88)
Top Elevation (Preliminary) 270.5 (ft NAVD88)
Powerhouse
Approximate Dimensions (for two-unit powerhouse) 45 feet x 100 feet x 30 feet high
Finished Floor Elevation 250.0 (ft NAVD88)
Tailrace
Type Open Channel
Length 450 feet
Typical Water Depth 8-ft +/-
Typical Width 80 to 300 ft
Transmission Line
Type Overhead
Length (to Dillingham) Approximately 60 miles
Voltage 34.5 kV
Access Roads (from Airstrip Runway to Powerhouse)
Type Single lane gravel surfacing with turnouts
Length 0.5 miles
When powerhouse flows do not match the system loads, grid system electricity will have to be
supplemented with existing diesel generation. This will most likely be in the winter months when the
amount of water available to the powerhouse is less than the power demand would require. The
transmission grid will therefore have five diesel generation power plants tied together to complete
the electric grid system. The existing power plant in Dillingham has the ability to provide energy for
all six villages serviced by the transmission system throughout the year, except for the month of July.
This gives NETC the ability to feed the system from different sources as needed for load or
maintenance.
A gravity groin structure would be constructed above the falls on the Nuyakuk River, if determined
necessary during Project design and engineering. The groin, if constructed, would only extend a
portion of the way across the river with the intent of moving water from the southern portion of the
river above the falls into an open-channel, concrete canal to convey the diverted water inland
(towards the powerhouse) a short distance. The canal is conceptualized to have a length equal to
or greater than its width (L/W > 1) in order to follow appropriate hydraulic standards for splitting the
water into multiple intakes. As such, the canal length would be on the order of 100 ft long. At the
end of the canal would be two vertical shafts, drop-inlets, with each drop inlet feeding an independent
tunnel connected to one turbine unit. The diversion and intake geometry will be advanced once field
site investigations (bathymetry, sub-bottom profiling, and geotechnical drilling) are completed. In
addition, two-dimensional river hydraulic modeling will be required for approximately 1,000 lineal feet
above the falls to aid in proper development of the intake diversion hydraulic and structural design.
It is anticipated that river hydraulic modeling and geotechnical studies will be conducted as part of
the overall Project licensing study program.
Each conveyance tunnel would be equipped with an isolation gate at the intake to be able to
independently shut down each tunnel and corresponding turbine unit for maintenance or other
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emergency (e.g. turbine runaway) considerations. A canal gatehouse would be constructed with
large vertical telescoping control gates that can be designed to effectively isolate one tunnel and
shut off flow to that tunnel for maintenance or other reasons. The diversion structure and intake
canal would be equipped with redundant level transmitters to continuously monitor water levels in
these critical conveyance features.
The inlet zone to the open channel canal would be protected by steel inclined bar-screens (with
openings between bars on the order of 1 to 3 inches) to divert both ice and debris away from the
open channel and downstream over the natural falls. The trash rack would be oriented parallel to
river flow to maximize sweeping velocity on the rack face, thereby increasing passive flushing of
debris from the rack. The trash rack would be necessary to protect both the downstream telescoping
vertical gates as well as the downstream turbine units. Final concept design would need to
investigate whether or not an additional isolation bulkhead or sluice gates would be needed behind
the trash rack for further safety or maintenance purposes.
Assuming that a two-turbine powerhouse is the most practical and reliable configuration for power
generation, the Project would be developed with either one larger water conveyance tunnel feeding
both turbine units, or two smaller diameter tunnels, with each tunnel dedicated to one turbine unit.
Better system reliability and Project redundancy would be provided by an arrangement that dedicates
a tunnel to each unit, but the cost of providing two tunnels could be higher than that of a single tunnel
unit. Advantages of a two-tunnel project would include the following:
• Ability to run one turbine unit while maintenance is performed on the other isolation gate or
turbine unit.
• Design of the steel tunnel liners to fit inside the excavated rock tunnels may be significantly
easier with the smaller 15-ft final steel liners than the larger and thicker requirements for the single
25-ft steel lined tunnel.
If on-site geotechnical drilling and investigations show that native rock quality is poor or inconsistent,
then it should be assumed that all tunnels would have to be lined with either a welded in-place steel
liner (a continuous steel shell liner likely of at least 1/2-inch thickness) or perhaps with a rock-bolt
and shotcrete system to protect against the inherent structural weaknesses or deficiencies in the
native rock. If steel liners are used, they would be brought in longitudinal arc-sections and seem-
welded both longitudinally and horizontally inside the tunnel. Once the steel liners are placed inside
the tunnel, the annular void space between the liner and the native rock would be pressure grouted
with structural non-shrink grout mixes designed to be pumped and flow through annular spaces.
If on-site geotechnical investigations show that native rock is of high enough quality and consistent
enough through the tunnel alignment zone, then it may be possible to omit the need for an interior
steel liner or rock-bolt and shotcrete liner system. This configuration would provide a large economic
benefit to the Project. Detailed on-site geotechnical investigations, including field drilling and logging,
will be used to clarify the design needs of the conveyance tunnels.
If a single conveyance tunnel system is pursued for the Project design, it will be necessary to provide
a bifurcation design near the outlet to the tunnel and prior to the powerhouse. The trifurcation would
be designed of steel pipe and would divide the flow to the two Kaplan units with their horizontal spiral
cage inlet configurations. Geometric symmetry would be required to ensure an equal division of flow
to the three units when all units are in operation. The low system net heads (estimated at 26 feet or
11 psig (pounds per square inch, gage)) and lack of much external groundwater or other external
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loading conditions suggest that the structural design and resulting plate thickness of a steel pipe
trifurcation system should not be very thick. However, both handling and site-specific seismic
considerations will be taken into account in the final bifurcation design.
If two separate conveyance tunnels are pursued for the Project, then the bifurcation structure can be
eliminated from the Project.
The powerhouse would be located on the south bank of the Nuyakuk River near the base of the falls.
The powerhouse is estimated to be approximately 45 feet wide by 100 feet long by 30 feet high to
accommodate two of the Kaplan vertical shaft turbine units. The powerhouse would have a large
underground foundation that houses the entrance cage to the runner along with the impeller section
of each turbine unit. The main superstructure above ground would be a pre-engineered metal
building anchored to a concrete foundation.
The powerhouse concept is to contain two vertical shaft Kaplan-type turbine/generator units with a
rated capacity of 5,380 kW for each unit at a design flow of approximately 3,000 cfs per unit, and
associated switchgear and controls. The centerline of the turbine and generator units would be
approximately 232 feet above mean sea level (msl). The tailwater elevation at the powerhouse would
range from approximate elevations 214 feet above msl to 231.5 feet above msl depending upon
output level. Final values for these elevations will be determined once the site topographic and
bathymetric surveys are further analyzed during Project design and engineering efforts. The turbines
would be designed to operate at high efficiencies over a range of flows from the maximum of 3,000
cfs to a minimum of around 755 cfs depending on conditions.
The tailrace would be an open rectangular concrete channel approximately 450 feet long and80 to
300 feet wide to convey water back to the Nuyakuk River. The tailrace outlet to the river would be
designed to reduce velocities relative to the natural river velocities in the discharge zone. This will
help prevent native anadromous fish from being attracted to the Project discharge flow instead of the
natural river channel flow pathways. In addition, the need for vertical picket barriers or other such
fish barrier protection measures on the outlet of the Tailrace will need to be evaluated during Project
development.
The switchyard at the powerhouse will consist of a pad-mounted disconnect switch (i.e., breaker)
and a pad-mounted step-up transformer. An overhead 34.5 kV transmission line would run from the
powerhouse switchyard approximately 60 miles to a point of interconnection with the NETC electrical
system. A right-of-way would be established along the proposed transmission line. This route would
be used to construct the transmission line, then serve as a land-based right of way for the Project
site. The route would incorporate setbacks from main waterways and alignment changes to minimize
visual impacts.
The transmission line poles would be designed as tangent line structures located approximately
every 300 feet on center. Transmission line design will also incorporate the latest raptor protection
guidelines. Collision avoidance devices will be installed on the line at appropriate locations to protect
migratory birds.
The Project would be constructed over a 24-month timeframe after the issuance of the Project
license. Construction would begin in the spring with the clearing of a right-of-way along the
transmission corridor and the construction of the localized access road at the Project works on the
river. A majority of the large equipment necessary to construct Project infrastructure would be
barged up the river and stored at the site during construction activities. An airstrip would be
constructed adjacent to the Project site to allow air transport of equipment, materials, and manpower
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to support construction activities. A fully equipped man camp would be erected for the Project
construction staff. Portable generation facilities would provide power for the construction work and
man camp facilities. Initially, temporary cofferdams would be constructed at the intake and
powerhouse tailrace channel exit zone into the river. This would allow the intake structure, power
conduit, and powerhouse construction to advance simultaneously to maximize the work completed
during a summer construction season. The intake and power conduit would be completed first, with
the powerhouse structure completed immediately following. The generation equipment would be
installed, and the balance of plant construction advanced during the winter months. The diversion
structure and tailrace channel would be the last components constructed followed by removal of the
river cofferdams. These work activities would be completed in the last season followed by startup,
commissioning, and initiation of commercial power generation.
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
1 Water 5380 Kaplan Style
Kaplan Style
Kaplan Style
65% 40+ 99%
2 Water 5380 65% 40+ 99%
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
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 primary mode of operation for this Project will be level control, whereby outflow is balanced to
inflow. The Project is conceived as a run-of-river project, with no large storage component. As such,
power production will mimic some fraction of total river inflow to the Project site.
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Mean daily discharge in the Nuyakuk River is based on USGS gaging data available at station
15302000 located near the outlet of Nuyakuk Lake. From the figure, it is clear that the period of high
flow in the river occurs between early summer and early fall. For the remainder of the year, the river
is running at near baseflow conditions. Because the Project will operate in run-of-river mode, sizing
the generating units should be done to either 1) optimize power production during a specific time of
year (e.g., during the winter months) or 2) produce power more or less evenly throughout the year.
Under the current Project conceptualization, units have been sized to provide a stable amount of
power from month to month while attempting to minimize overall capital costs associated with the
hydroelectric units, tunnel(s), and other Project components. Average monthly power generation
under this operational configuration is shown.
During periods when system firm power loads exceed hydro capacity, electric generation and
spinning reserve needs will be met with an economic dispatch model that will utilize the least cost
generation option first. This will likely be NETC’s diesel generation plant initially.
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5.4.3.1 Expected Capacity
Factor
63%
5.4.5.2 Annual Electricity Production and Fuel Consumption (Proposed System)
Month Generation
(Proposed
System)
(kWh)
Generation
(Type 2)
(kWh)
Generation
(Type 3)
(kWh)
Fuel
Consumption
(Diesel-
Gallons)
Fuel
Consumption
[Other]
Secondary
load
(kWh)
Storage
(kWh)
January 2,600,000
February 1,800,000
March 1,100,000
April 1,500,000
May 8,600,000
June 9,200,000
July 9,200,000
August 9,200,000
September 9,200,000
October 9,200,000
November 8,200,000
December 3,900,000
Total 73,700,000
5.4.5.3 Annual Heating Fuel Consumption (Proposed System)
Month Diesel
(Gallons)
Electricity Propane
(Gallons)
Coal
(Tons)
Wood
(Cords,
green tons,
dry tons)
Other
January
February
March
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April
May
June
July
August
September
October
November
December
Total
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.
$
Option 2: Diesel generation OFF
For projects that will result in shutting down
diesel generation please estimate:
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. $3,135,771 (40 year average)
2. Hours diesel OFF/year: 6600
3. $2,726,036 (40 year average)
5.4.7 Fuel Costs
Estimate annual cost for all applicable fuel(s) needed to run the proposed system (Year 1 of
operation)
Diesel
(Gallons)
Electricity Propane
(Gallons)
Coal
(Tons)
Wood
Other
Unit cost
($)
Annual
Units
Total
Annual
cost ($)
5.5 Performance and O&M Reporting
For construction projects only
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5.5.1 Metering Equipment
Please provide a short narrative, and cost estimate, identifying the metering equipment that will be
used to comply with the operations reporting requirement identified in Section 3.15 of the Request
for Applications.
Metering and automatic data logging of all key operational and performance metrics will be
incorporated into final system design to comply with all AEA, FERC, and USDA/RUS reporting
requirements.
Because Broadband fiber will be incorporated into transmission line cables a real-time fiberoptic
based industrial dispatch and control system will be capable of controlling, monitoring and metering
firm and non-firm electric system loads. This incorporated industrial fiber control system will provide
a long-term robust, reliable, and cost-effective control, dispatch, monitoring, and metering system
5.5.2 O&M reporting
Please provide a short narrative about the methods that will be used to gather and store reliable
operations and maintenance data, including costs, to comply with the operations reporting
requirement identified in Section 3.15 of the Request for Applications
SCADA, metering and automatic data logging of all key operational and performance metrics will be
incorporated into final system design along with an asset management system to track and document
maintenance costs, history, and performance to comply with all AEA, FERC, and USDA/RUS
reporting requirements.
SECTION 6 – ECONOMIC FEASIBILITY AND BENEFITS
6.1 Economic Feasibility
6.1.1 Economic Benefit
Annual Lifetime
Anticipated Diesel Fuel Displaced for Power
Generation (gallons)
1,500,000 60,000,000
Anticipated Fuel Displaced for Heat
(gallons)
58,033 25,743,923
Total Fuel displaced (gallons) 1,558,033 85,743,923
Anticipated Diesel Fuel Displaced for Power
Generation ($)
$5,159,100
(@ $3.4394/gallon)
$206,364,000
Anticipated Fuel Displaced for Heat ($) $319,181
(@ $5.50/gallon)
$141,591,576
Anticipated Power Generation O&M Cost
Savings
$2,812,835 $112,513,399
Anticipated Thermal Generation O&M Cost
Savings
Total Other costs savings (taxes, insurance,
etc.)
Total Fuel, O&M, and Other Cost Savings $7,004,667 $373,877091
6.1.2 Economic Benefit
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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 https://www.akenergyauthority.org/What-We-
Do/Grants-Loans/Renewable-Energy-Fund/2022-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.
The Nuyakuk River Hydroelectric Project will provide an alternative to diesel power production for
six Bristol Bay communities, initially lowering the cost of power production and eventually significantly
lowering the cost of power production as the investment matures. Two main drivers in the increasing
value of this Project when compared with the diesel alternative; load growth up to the power
production limits and the effects of inflation on fuel costs. As the cost of power lowers for these
communities they will be less reliant on PCE, possibly eliminating the need, benefitting the State and
all Alaskans.
Completion of this Project will also bring a level of energy security and self-sufficiency to the
communities served. There are risks in fuel delivery including low water grounding in the river system
and leaks during transfer that will be mitigated by the lessoning dependence on generator fuel and
space heating diesel.
Financial forecasting was developed by evaluation of NETC RUS form 7 reporting, NETC
replacement schedule/cost estimation from recent power plant investment and community PCE
reporting. The spreadsheet used to forecast has several user defined inputs including initial Project
capitalization costs and reinvestment cycle, existing power plant reinvestment costs and cycle,
interest rates for capital debt service, inflation rates and expected growth. Actual power production
O&M cost were used as legacy system baseline and Project O&M costs where estimated based on
operational expectations. The spreadsheet will be included with this application, the forty year cost
estimate and selected inputs:
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User Input Year Diesel Hydro
cost/KWH cost/KWH
Hydro debt service Initial 2028 0.31$ 0.28$
Interest rate 2 2029 0.32$ 0.27$
Term in years 40 2030 0.33$ 0.26$
Capital cost 151,000,000.00$ 2031 0.33$ 0.25$
Grants 20,000,000.00$ 2032 0.34$ 0.24$
Total cost 131,000,000.00$ 2033 0.35$ 0.23$
2034 0.36$ 0.22$
Diesel debt service Initial 2035 0.36$ 0.21$
Interest rate 1.97 2036 0.37$ 0.20$
Term in years 30 2037 0.38$ 0.19$
Capital cost 13,500,000.00$ 2038 0.39$ 0.19$
Grants -$ 2039 0.40$ 0.18$
Total cost 13,500,000.00$ 2040 0.41$ 0.17$
2041 0.42$ 0.16$
Hydro debt service 1st Reinvest 2042 0.43$ 0.16$
Interest rate 2 2043 0.44$ 0.15$
Term in years 40 2044 0.45$ 0.15$
Capital cost 12,000,000.00$ 2045 0.46$ 0.14$
Grants -$ 2046 0.47$ 0.14$
Total cost 12,000,000.00$ 2047 0.48$ 0.14$
2048 0.49$ 0.14$
Diesel debt service 1st Reinvest 2049 0.50$ 0.14$
Interest rate 2 2050 0.51$ 0.14$
Term in years 30 2051 0.52$ 0.14$
Capital cost 20,000,000.00$ 2052 0.53$ 0.14$
Grants 5,000,000.00$ 2053 0.55$ 0.14$
Total cost 15000000 2054 0.56$ 0.14$
2055 0.57$ 0.15$
Diesel debt service 2nd Reinvest 2056 0.58$ 0.15$
Interest rate 2 2057 0.60$ 0.15$
Term in years 30 2058 0.62$ 0.15$
Capital cost 45,000,000.00$ 2059 0.63$ 0.15$
Grants 10,000,000.00$ 2060 0.65$ 0.15$
Total cost 35000000 2061 0.66$ 0.15$
2062 0.68$ 0.16$
Rate of inflation 2.50%2063 0.69$ 0.16$
2064 0.71$ 0.16$
MWH Consumption Diesel 20328 2065 0.73$ 0.16$
Growth Diesel 0.05%2066 0.74$ 0.16$
2067 0.76$ 0.17$
MWH Consumption Hydro 22600
Growth Hydro 5.00%
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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 largest economic risk to this Project is the cost of construction, estimated at approximately $155
million. The two largest drivers in the cost of construction are the penstock construction cost at the
power plant and the transmission line build.
The cost of constructing the penstock will be determined by the quality of the substrate at the site.
NETC conducted a preliminary geotechnical investigation at the Project site in 2022, and results of
the study are currently being reviewed, initial results are favorable. The results of this study will have
significant bearing on the cost of penstock construction and the overall cost of construction. By
completing this study early in the process NETC will gain critical information for financial feasibility
assessment.
The transmission line costs, and in particular the cost to access the smaller communities, is being
mitigated by evaluating build alternatives such as emerging pole placement technology and carbon
fiber core conductors that would allow for fewer pole placements and higher reliability. NETC has
also met with Tribal grant funding representatives from the Department of Energy and Bureau of
Indian Affairs Indian Energy Programs. The Project was well received and NETC will work with the
Tribal organizations in these communities to apply for these funds when appropriate.
NETC will continue it’s 55-year history of successful power plant operations by providing 24/7
operators onsite, operator training, operational maintenance and appropriate system reinvestment.
While other investments in renewable may impact the current load, NETC knows of none currently
in development and no local resource that would replace base load capacity as this Project does.
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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.
N/A
Renewable energy resource availability (kWh per month)
Estimated direct sales to private sector businesses (kWh)
Revenue for displacing diesel generation for use at private sector businesses ($)
Estimated sales for use by the Alaskan public (kWh)
Revenue for displacing diesel generation for use by the Alaskan public ($)
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 include a fiber optic communications build that will have the ability to extend the
existing fiber network to these communities. NETC has contracted for 100GB/s of Direct Internet
Access on completion of the fiber build, equivalent to over 200 times the existing bandwidth to
these communities.
Achieving Urban standards of Broadband access will improve quality of life by providing access to
E-commerce, employment opportunity, governmental functions including access to elected
representation, education, news, entertainment and social media.
Improved Broadband access will allow modernization of workforce tasks by allowing better access
to cloud-based services, secure data storage and training opportunities.
Increased Broadband access will allow businesses and job seekers better access to opportunities
and markets
Economic benefit of lower electric rates
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Mature hydroelectric generation has several examples of rural communities providing service at, or
better than, urban rate equivalency. Examples include Cordova, Kodiak, Sitka, Valdez, Ketchikan
There are hydroelectric facilities in Alaska that have been providing power for over 100 years
Current PCE urban averaging is .19/kWh. That rate applied to the communities served by this
Project has significant yearly savings averaged over the last five years:
• Savings to the State in avoided PCE payments $1,289,290/year (2019 AEA PCE reports)
• Savings to the communities combined averages $3,632,155/year (non PCE customers)
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
Nushagak Electric Association was incorporated in March of 1964, and became Nushagak Electric
Cooperative with an amendment to the articles of incorporation in September of 1972. It became
Nushagak Electric and Telephone Cooperative with articles of consolidation in May of 2002.
NETC has successfully operated power production and distribution over the last 55 years under
Certificate of Public Convenience and Necessity providing distributed electric service to the
communities of Dillingham and Aleknagik. NETC will maintain this new infrastructure under the
same systems of management and control methodology, using contemporary technology, which
has been proven successful since operations began in 1964.
Will Chaney, CEO/GM, overall project responsibility. Will has been with the Cooperative for 22
years. During this time he has held the positions of Power Plant Operator, Lineman, Construction
Supervisor, Staking Engineer, Operations Manager and now General Manager.
Jim Denslinger, Operations Manager, project quality control and integration. Jim has 17 years of
operational experience in this power plant, including all aspects of plant maintenance and repair.
Bernie Venua, Power Plant technician, project quality control and integration. Bernie has 22 years
of operational experience in this power plant, including all aspects of plant maintenance and repair.
In addition to these key individuals, NETC’s power plant staff includes six operator-mechanics with
a combined 98 years of service. The plant is staffed around the clock, every day of the year.
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Operational supplies will be tracked through our existing software platform, provided and supported
by National Information Solutions Cooperative (NISC).
Daily and Monthly PM checks will be developed through the engineering process in consultation
with vendors for best practices. We will train NETC’s existing power plant operators and mechanics
on these new Preventative Maintenance and expected Corrective Maintenance procedures. We
will integrate the data collection and review from the PM and CM procedures into the existing
processes.
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.
• If you will not be selling energy, explain how you will ensure that the completed project will be
financially sustainable for its useful life.
Nushagak Electric and Telephone Cooperative have provided electric service to the communities
of Dillingham and Aleknagik, Alaska since 1964. The cooperative has grown to meet the increasing
distributed electric needs of the communities served, from total production of 5.5MWh’s and a peak
load of 1.5 MW in 1978 to 17.66 GWh’s and a peak of 6.3 MW in 2019. In meeting this growing
expectation, NETC has consistently managed operations to provide reliable service while trying to
minimize the economic impact to our members.
NETC operations include electric, telephone and cable TV, divisions I, II and III respectively.
Revenues are generated for each of these services under a cooperative structure, striving to
maintain a 1.50 TIER. Two in-house accountants and a bookkeeper manage grant funds and
financial reporting for NETC. Grant accounting is audited annually by a third party.
Angela Venua, Senior Accountant, and Robert Himschoot, CEO/GM, will have responsibility for
fiduciary concerns, project accounting, and financial reporting. NETC retains a third-party audit on
an annual basis; currently Aldrich CPA’s and Advisors, LLP, are under contract.
Angela Venua, Senior Accountant, project accounting, financial reporting and compliance. Angela
has been with NETC for 17 years, where she became Senior Accountant in 2015. Angela holds a
Bachelor’s in Accounting and is a RUS Borrower Accountant through the USDA Graduate School.
NETC will complete a cost-of-service study (“COSS”) that allocates the electric utility costs of
Nushagak Electric & Telephone Cooperative (“NETC”) to the various rate classes. Costs will be
based on the current budget but normalized for a full year interest and depreciation expenses as
well as other costs anticipated in the near future. Although NETC’s electric rates are not regulated
by the Regulatory Commission of Alaska (“RCA”), the analysis will use the standards developed
within the industry.
Revenue collection will be completed through our existing software platform provided by NISC. We
have successfully used this platform for revenue collection across all our services since 2015. The
platform includes an online payment option.
7.1.2.1 Revenue Sources
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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)
The Project will have a small but immediate reduction on rates across all rate classes, and a larger
reduction as the Project matures, consistent with the reduction in power production costs modeled
earlier in the application (6.1.2).
NETC has contracted supplemental heat sales since 1986. The revenue is generated based on
BTU consumption with the revenue model. NETC would continue selling thermal heat at a
competitive discount compared to conventional/heating fuel pricing.
Additional revenue, not modeled in the financial forecasting, would come from monetizing the
Broadband bandwidth derived from this Project. NETC also provides Broadband services and has
all the necessary technical, operational and financial mechanisms to market this capacity.
NETC’s study area includes the communities of Dillingham, Aleknagik, Manokotak, Clark’s Point,
Ekuk and Portage Creek. NETC’s Broadband product is available in Dillingham, Aleknagik and
Clark’s Point with a total of 811 subscriptions. This capacity expansion would allow for expansion
of service to Manokotak, Ekuk and Portage Creek including the seasonal commercial and sports
fishing industry.
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.
Currently there are no Power Purchase agreements modeled for this Project. Power sales to
communities can be handled as Large Commercial rate class sales. NETC currently sells power to
the Bristol Bay Area Health Corporation (BBAHC) under this arrangement. BBAHC owns and
maintains its own distribution system, energy and demand are metered at a system demarcation
point.
This mechanism lends to COSS rate making by taking into account capital investment through
grant funds allocated to individual communities.
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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.
NETC has completed Phase I with the submission of the FERC ILP Scoping Documents. It has
initiated Phase II through the FERC ILP Study Plan development process.
NETC invited key agencies and stakeholders to participate in an Aquatics Resource Working
Group (ARWG). The initial goal of the ARWG was to review and update the study plan as it
pertains to the aquatic environment in general and fish passage in particular. The ARWG began
meeting in 2020, and currently meets on a monthly basis. In June 2022, NETC hosted an in-person
meeting and site visit to enable the ARWG members to see the proposed Project site and have
extensive discussion regarding the Proposed Study Plan. As a result of the ARWG’s collaboration,
NETC filed a Revised Study Plan (RSP) that the ARWG agreed on, and FERC ultimately issued a
Study Plan Determination based on the RSP on August 27, 2022. Members of the ARWG include:
Bristol Bay Science and Research Institute (BBSRI), University of Washington Fisheries Research
Institute (FRI), State of Alaska Department of Fish and Game (ADF&G), National Marine Fisheries
Service (NMFS), United Tribes of Bristol Bay (UTBB), and NETC’s team.
In preparation for Phase II field study work NETC and McMillen Jacobs have identified and
engaged partners and contractors for the 2023 and 2024 field work including Kleinschmidt/R2,
Cultural Resources Consultants (CRC), Quantum Spatial, R&M Consultants, QEDA Consulting,
MLP & Associates, ADF&G, and NOAA NMFS.
NETC worked directly and intensively with the Alaska State Legislature to develop SB91 which
allows for the requisite natural resource and engineering assessment activities and FERC
regulatory processes that need to be conducted for an ultimate project feasibility determination.
SB91 was unanimously passed by the Alaska State Legislature in 2019 allowing for the
comprehensive evaluation of the site.
NETC acquired a Special Use Permit from ADNR, Division of Parks & Outdoor Recreation on April
1, 2020 (Permit #LAS 33198). The permit authorizes temporary use of the Project site to conduct
scientific research, including geotechnical investigations, land surveying, and bathymetric
surveying. The permit includes provisions for the installation of a man camp that will be used to
house Project personnel on site. The permit is effective May 1, 2020 through May 1, 2024.
NETC will continue to engage with all requisite agencies to obtain additional permits for conducting
natural resource studies and engineering evaluations, as needed. NETC is currently in the process
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of developing natural resource study methodologies, and once study plans are finalized NETC will
coordinate with requisite agencies to obtain all required permits prior to initiating studies and on-
site engineering assessments. Two years of intensive natural resource study will then commence
in 2023 and 2024.
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.
As the Project becomes better defined efforts will be made to encourage Village/Tribal
organizations to pursue Energy Conservation Measures (ECM’s) at all locations that might
incorporate any new dispatchable thermal heating devices that utilize excess renewable
hydroelectricity.
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 year of the RFA date of October 4, 2022. Please note that letters
of support from legislators will not count toward this criterion.
After two years of desktop Project feasibility studies and over ninety Project outreach meetings, in
October of 2019, NETC filed our Pre Application Document initiating the FERC Integrated
Licensing Process (ILP) timeline. Recently NETC received letters and resolutions stating concern
for the effects of COVID-19 and the Bristol Bay fishing season on the ability to effectively
participate in the licensing process study plan development, specifically the aquatics and fish
passage studies that all consider paramount. Initially, these entities requested a delay of 12
months to the ILP schedule. NETC received these correspondences during the last week of May
from five regional entities, Bristol Bay Economic Development Corporation, Bristol Bay Native
Association, Bristol Bay Area Health Corporation, Bristol Bay Housing Authority and United Tribes
of Bristol Bay. On June 8th NETC received a copy of a consistent resolution passed by the Wood
Tikchik Management Council at their meeting on May 27th.
While NETC does not agree with all the conclusions in these correspondences, we do respect the
entities and want to address their concerns. NETC consulted with FERC on June 2nd regarding
these topics which lead to a request for an Abeyance (a suspension of the schedule) to the ILP
timeline. The request was submitted June 7th and approved by FERC on June 9th.
We were by no means idle during the abeyance. NETC invited key agencies and stakeholders to
participate in an Aquatics Resource Working Group (ARWG). The initial goal of the ARWG was to
review and update the study plan as it pertains to the aquatic environment in general and fish
passage in particular. The ARWG has met fourteen times since its inception in October 2020, and
multiple more times in small groups based on the topic of discussion. Because of the ARWG’s
collaboration, a consensus study plan for aquatics was developed and included in the RSP.
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Members of the ARWG include, Bristol Bay Science and Research Institute (BBSRI), University of
Washington Fisheries Research Institute (FRI), State of Alaska Department of Fish and Game
(ADF&G), National Marine Fisheries Service (NMFS), United Tribes of Bristol Bay (UTBB), and
NETC’s team.
NETC held an in-person ARWG meeting and site visit in June 2022. NETC also held a public
meeting during this timeframe that allowed members of the community to engage in discussion and
ask questions of the technical experts. Following this series of meetings, NETC filed the RSP with
FERC on August 1, 2022 and received a Study Plan Determination from FERC on August 27,
2022. NETC plans to hold additional in-person meetings in the region as conditions permit to share
Project information as the study program and Project design advance.
NETC also received several Resolutions of support during our Public outreach process. The letters
of concern requesting NETC to apply for an Abeyance, NETC’s response letter and the letters of
support will be included with the application.
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.
In November of 2009 NETC received grant # 2195419 from the AEA REF. The award amount was
$4,031,500 of which $1,898,233.19 was expended for the study of Grant and Elva lake hydro
potential. When project feasibility was evaluated after the 2013 study season and the project was
terminated the remaining $2,133,266.82 was returned to the Fund. The Grant was closed out in
August of 2014.
On September 28th 2021, NETC received a REF Round 13 award in the amount of $1,000,000. It
is NETC’s intent to utilize that award almost entirely in 2022. Round 13 funds will be used to
complete initial Geotech studies, Section 106 evaluation advancement, Salmon Life Cycle
modeling, Water Quality baseline assessments and FERC ILP Study Plan advancement
On June 20th 2022, NETC received an REF Round 14 award in the amount of $1,000,000. It is
NETC’s intent to utilize that award almost entirely in 2023. Round 14 funds will be used to
complete initial Fish and Aquatics studies, Terrestrial studies, and Recreational studies.
In August of 2022 NETC was awarded $500,000 in project support from the Denali Commission.
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.
• Pre Application Document for FERC Project P-14873 (Nuyakuk Hydro)
• Scoping Document 1 and 2 for FERC P-14873
• Proposed Study Plan for FERC P-14873
• Revised Study Plan for FERC P-14873
• Study Plan Determination from FERC P-14873
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Federal Tax ID #: 92-0177246
Please submit an updated form whenever there is a change to the above information.
SECTION 14 – ADDITIONAL DOCUMENTATION AND CERTIFICATION
SUBMIT THE FOLLOWING DOCUMENTS WITH YOUR APPLICATION:
A. Contact information and resumes of Applicant’s Project Manager, Project Accountant(s),
key staff, partners, consultants, and suppliers per application form Section 3.1, 3.4 and
3.6.
Applicants are asked to provide resumes submitted with applications in separate electronic
documents if the individuals do not want their resumes posted to the project web site.
B. Letters or resolutions demonstrating local support per application form Section 9.
C. For projects involving heat: Most recent invoice demonstrating the cost of heating fuel
for the building(s) impacted by the project.
D. Governing Body Resolution or other formal action taken by the applicant’s governing
body or management per RFA Section 1.4 that:
• Commits the organization to provide the matching resources for project at the match
amounts indicated in the application.
• Authorizes the individual who signs the application has the authority to commit the
organization to the obligations under the grant.
• Provides as point of contact to represent the applicant for purposes of this
application.
• Certifies the applicant is in compliance with applicable federal, state, and local, laws
including existing credit and federal tax obligations.
E. An electronic version of the entire application on CD or other electronic media, per RFA
Section 1.7.
F. CERTIFICATION
The undersigned certifies that this application for a renewable energy 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 Will Chaney