HomeMy WebLinkAboutAPP_13016-REFr13_StdApp_ELV_FINALRenewable Energy Fund Round 13
Grant Application – Standard Form
AEA 21010 Page 1 of 35 7/20/2020
Application Forms and Instructions
This instruction page and the following grant application constitutes the Grant Application Form for Round
13 of the Renewable Energy Fund (REF). A separate application form is available for projects with a primary
purpose of producing heat (see Request for Applications (RFA) Section 1.5). This is the standard form for all
other projects, including projects that will produce heat and electricity. An electronic version of the RFA and
both application forms is available online at: www.akenergyauthority.org/what-we-do/grants-
loans/renewable-energy-fund-ref-grants/2020-ref-application.
What follows are some basic information and instructions for this application:
● The Alaska Energy Authority (AEA) expects this application to be used as part of a two-year solicitation
cycle with an opt-out provision in the second year of the cycle.
● If you are applying for grants for more than one project, provide separate application forms for each
project.
● Multiple phases (e.g. final design, construction) for the same project may be submitted as one
application.
● If you are applying for grant funding for more than one phase of a project, provide milestones and grant
budget for each phase of the project (see Sections 3.1 and 3.2.2).
● In order to ensure that grants provide sufficient benefit to the public, AEA may limit recommendations
for grants to preliminary development phases in accordance with 3 Alaska Administrative Code (ACC)
107.605(1).
● If some work has already been completed on your project and you are requesting funding for an
advanced phase, submit information sufficient to demonstrate that the preceding phases are
completed and funding for an advanced phase is warranted. Supporting documentation may include,
but is not limited to, reports, conceptual or final designs, models, photos, maps, proof of site control,
utility agreements, business and operation plans, power sale agreements, relevant data sets, and other
materials. Please provide a list of supporting documents in Section 11 of this application and attach the
documents to your application.
● If you have additional information or reports you would like the Authority to consider in reviewing your
application, either provide an electronic version of the document with your submission or reference a
web link where it can be downloaded or reviewed. Please provide a list of additional information;
including any web links, in Section 12 of this application and attach the documents to your application.
For guidance on application best practices please refer to the resource-specific Best Practices
Checklists; links to the checklists can be found in the appendices list at the end of the accompanying
REF Round 13 RFA.
● In the Sections below, please enter responses in the spaces provided. You may add additional rows or
space to the form to provide sufficient space for the information, or attach additional sheets if needed.
● If you need assistance with your application, please contact AEA’s Grants Manager Karin St. Clair by
email at grants@akenergyauthority.org or by phone at (907) 771-3081.
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Grant Application – Standard Form
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REMINDER:
● AEA is subject to the Public Records Act AS 40.25, and materials submitted to AEA may be subject to
disclosure requirements under the act if no statutory exemptions apply.
● All applications received will be posted on the Authority web site after final recommendations are
made to the legislature. Please submit resumes as separate PDFs if the applicant would like those
excluded from the web posting of this application.
● In accordance with 3 AAC 107.630 (b) Applicants may request trade secrets or proprietary company
data be kept confidential subject to review and approval by AEA. If you want information to be kept
confidential the applicant must:
o Request the information be kept confidential.
o Clearly identify the information that is the trade secret or proprietary in their application.
o Receive concurrence from the Authority that the information will be kept confidential. If the
Authority determines it is not confidential, it will be treated as a public record in accordance
with AS 40.25 or returned to the applicant upon request.
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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)
Community of Elfin Cove Non-Profit Corporation, Elfin Cove Utility Commission
Tax ID # 92-0089934
Date of last financial statement audit:2018
Mailing Address: Physical Address:
P.O. Box 1 Community Building
Elfin Cove, AK 99825 Elfin Cove, AK 99825
Telephone: Fax: Email:
907-239-2226 907-236-2226 jim.wild.ak@gmail.com
1.1 Applicant Point of Contact / Grants Manager
Name: Title:
Jim Wild Project Manager
Mailing Address:
PO Box 109
Elfin Cove, AK 99825
Telephone: Fax: Email:
907-239-2222 907-236-2222 jim.wild.ak@gmail.com
1.1.1 Applicant Signatory Authority Contact Information
Name: Jim Wild
Title: Vice Chairman Community of Elfin Cove Non-Profit Corporation (CECNPC)
Mailing Address:
PO Box 109
Elfin Cove, AK 99825
Telephone: Fax: Email:
907-236-2222 jim.wild.ak@gmail.com
1.1.2 Applicant Alternate Points of Contac
Name Telephone: Fax: Email:
Mary Jo Lord-Wild 907 738 5538 mary.jo.lord-wild@elfincove.net
Shirley Perkins 907 723 8278 elfincoho@aol.com
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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 #__701____, or
☐ An independent power producer in accordance with 3 AAC 107.695 (a) (1)
CPCN #______, or
☐ A local government, or
☐ A governmental entity (which includes tribal councils and housing authorities)
Additional minimum requirements
☒ 1.2.2 Attached to this application is formal approval and endorsement for the project by the
applicant’s board of directors, executive management, or other governing authority. If the applicant
is a collaborative grouping, a formal approval from each participant’s governing authority is
necessary. (Indicate yes by checking the box)
☒ 1.2.3 As an applicant, we have administrative and financial management systems and follow
procurement standards that comply with the standards set forth in the grant agreement (Section 3 of
the RFA). (Indicate yes by checking the box)
☒ 1.2.4 If awarded the grant, we can comply with all terms and conditions of the award as identified in
the Standard Grant Agreement template at www.akenergyauthority.org/what-we-do/grants-
loans/renewable-energy-fund-ref-grants/2020-ref-application (Any exceptions should be clearly
noted and submitted with the application.) (Indicate yes by checking the box)
☒ 1.2.5 We intend to own and operate any project that may be constructed with grant funds for the
benefit of the general public. If no please describe the nature of the project and who will be the
primary beneficiaries. (Indicate yes by checking the box)
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SECTION 2 – PROJECT SUMMARY
2.1 Project Title
Provide a 4 to 7 word title for your project. Type in the space below.
Elfin Cove Hydro Final Permitting and Design
2.2 Project Location
2.2.1 Location of Project – Latitude and longitude (preferred), street address, or community name.
Latitude and longitude coordinates may be obtained from Google Maps by finding you project’s location on
the map and then right clicking with the mouse and selecting “What is here? The coordinates will be
displayed in the Google search window above the map in a format as follows: 61.195676.-149.898663. If
you would like assistance obtaining this information, please contact AEA’s Grants Manager Karin St. Clair by
email at grants@akenergyauthority.org or by phone at (907) 771-3081.
Latitude 58.19N Longitude 136.35W
The project will be located on Crooked Creek and Jim's Lake, approximately one mile south of Elfin Cove
2.2.2 Community benefiting – Name(s) of the community or communities that will be the beneficiaries
of the project.
Elfin Cove, Alaska.
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 (Hydro)
☐ Other (Describe) ☐ Small Natural Gas
2.3.2 Proposed Grant Funded Phase(s) for this Request (Check all that apply)
Pre-Construction Construction
☐ Reconnaissance ☒ Final Design and Permitting
☐ Feasibility and Conceptual Design ☐ Construction
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2.4 Project Description
Provide a brief, one-paragraph description of the proposed project.
The project will include a run-of-river hydroelectric plant between Crooked Creek and Jim's Lake (upper
system) and a storage hydroelectric project between Jim's Lake and tidewater (lower system). Our FERC
License Application considers two development options:
The Full Development Option would feature a 35-kW upper system and 105 kW lower system for 140 kW of
generating capacity, supplying 90% of the utility’s annual energy demand.
The Phased Development Option would defer installation of power recovery equipment on the upper
system to the future (only the water diversion would be initially built), providing 105 kW of generating
capacity and supplying 82% of the utility’s annual energy demand.
At this time we expect to proceed with the phased development option, as it is the more economic of the
two. Accordingly, this application describes the phased development option.
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.
ECUC would use funds to:
- (1) complete the FERC licensing process. Our final license application was submitted 8/24/2020. Complete
other state and federal permits in conjunction with FERC process (Corps NWP 17, USFS Special Use Permit,
ADNR water use permit, etc.).
- (2) make final design decisions addressing project constructability/sustainability/cost and conforming with
final permit terms and conditions, and advance existing 65% design to final construction documents.
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
($)
3 Elfin Cove Hydroelectric Project 446 N -
4 Elfin Cove Hydroelectric Project 692 Y $347,000
8 Elfin Cove Hydroelectric Permitting 1159 N -
9 Elfin Cove Hydroelectric Permitting 1250 N * -
* AEA recommended funding, and was the top unfunded REF project when AEA retired the R9 list in 2019.
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SECTION 3 – Project Management, Development, and Operation
3.1 Schedule and Milestones
Please fill out the schedule below (or attach a similar sheet) for the work covered by this funding request.
Be sure to identify key tasks and decision points, including go/no go decisions, in your project along with
estimated start and end dates for each of the milestones and tasks. Please clearly identify the beginning
and ending of all phases (I. Reconnaissance, II. Feasibility and Conceptual Design, III. Final Design and
Permitting, and IV. Construction) of your proposed project. See the RFA, Sections 2.3-2.6 for the
recommended milestones for each phase. Add additional rows as needed.
Task
# Milestones Tasks
Start
Date
End
Date Deliverables
1.1
-FERC License
-Approved
Operation/Monitoring Plans
Complete
FERC
Licensing
August
2020
Mar
2022 FERC License
1.2 -Final Permits
Obtain Other
Federal Permits
and
Authorizations
August
2021
Aug
2022
USFS Special Use Permit
COE NWP #17 Permit (or
equal)
1.3 -Final Permits
Obtain State
Permits and
Authorizations
August
2021
Aug
2022 ADNR Water Use Permit
2.1
-Final Design
-Updated Engineer’s Cost
Estimate
-Updated Engineer’s Energy
Estimate
Complete
Project Designs
and
Specifications
August
2021
Sept
2022
Final Construction Documents
(Design, Specifications, Bid
Package)
2.2 -Final Economic Analysis
-Financing Plan
Revise Existing
Business Plan
Oct
2021
Sept
2022
Updated business plan,
including final engineer’s cost
and energy estimates for final
project configuration.
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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 $130,000
Cash match to be provided a $ 32,500
In-kind match to be provided $ 0
Energy efficiency match providedb $ N/A
Total costs for project phase(s) covered in application (sum of above) $162,500
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.
Elfin Cove has demonstrated a consistent and substantial financial commitment to this project. In addition
to past matching funds and the in-kind services provided by many of our residents over the years, the
community has been allocating the majority of our state revenue sharing receipts to our hydro project
fund for many years so that we may one day realize the benefits of this important project.
Elfin Cove recognizes the state’s current budget situation and that availability of grant funds will likely be
limited for project construction. We have a proven track record of financing our capital projects through
loans. Elfin Cove is one of the few – perhaps the only – rural community in Alaska that financed our new
bulk fuel facility through loans. We are still paying off the capital cost of our bulk fuel facility through a fuel
surcharge. We understand the financial commitment required to advance capital projects, and we have
demonstrated the capability to responsibly manage long term debt associated with important community
capital projects. When the time comes, we are prepared to make similar decisions and commitments for
the hydro project.
For this Phase of the project, the total funds needed are $162,500, which would consist of $130,000 in
grant funding, and $32,500 in local match. We propose that the match will be cash, at a maximum of
$32,500, less the agreed market value of any in-kind services the community is able to provide to advance
the project.
The scope of this grant request is consistent with our prior (REF Round 9) grant application. It has been
adjusted for inflation since 2015 and refined outstanding work scope as the project has advanced through
design and permitting.
We have the proposed matching funds in our Hydro Project Fund.
a Attach documentation for proof (see Section 1.18 of the Request for Applications)
b See Section 8.2 of this application and Section 1.18 of the RFA for requirements for Energy Efficiency Match.
3.2.2 Cost Overruns
Describe the plan to cover potential cost increases or shortfalls in funding.
The proposed budget includes a contingency on all activities to address unforeseen project costs. Beyond
that, ECUC would control cost overruns through proactive project management to identify and adjust work
scopes to prevent cost overruns where practical.
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In instances where cost overruns cannot be avoided, ECUC would pay additional costs from its own
resources to the extent possible and as authorized by ECUC leadership on a case-by-case basis with
consideration of the specific circumstances of the cost-overrun.
3.2.3 Total Project Costs
Indicate the anticipated total cost by phase of the project (including all funding sources). Use actual costs
for completed phases. Indicate if the costs were actual or estimated.
Reconnaissance [Actual] $55,900
Feasibility and Conceptual Design [Actual] $74,100
Final Design and Permitting [Estimated] $509,500
Construction [Estimated] $5,270,000
Total Project Costs (sum of above) [Estimated] $5,909,500
Metering/Tracking Equipment [not included in project cost] [Estimated] $0
3.2.4 Funding Subsequent Phases
If subsequent phases are required beyond the phases being applied for in this application, describe the
anticipated sources of funding and the likelihood of receipt of those funds.
● 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)
ECUC will consider all viable sources of funding for subsequent phases of construction. One key objective
of the currently proposed scope of work is to refine and to the extent practical reduce project capital cost.
State or federal grants and/or loans and private sector loans are all options. Supplemental revenues from
electricity sales, green tags, energy subsidies, tax credits, and other sources that may be available at the
time the project financing is secured will all be considered. Please see our current business plan for one
possible scenario of grants, loans, and revenue streams (standard electric service and dispatchable energy
service revenues) that would make the project viable.
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,
3.2.3 Budget Forms
Applications MUST include a separate worksheet for each project phase that was identified in Section 2.3.2
of this application — I. Reconnaissance, II. Feasibility and Conceptual Design, III. Final Design and
Permitting, and IV. Construction. Please use the tables provided below to detail your proposed project’s
total budget. Be sure to use one table for each phase of your project, and delete any unnecessary tables.
The milestones and tasks should match those listed in 3.1 above.
If you have any question regarding how to prepare these tables or if you need assistance preparing the
application please feel free to contact AEA’s Grants Manager Karin St. Clair by email at
grants@akenergyauthority.org or by phone at (907) 771-3081.
Phase 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
1.1 FERC Licensing Mar 2022 $34,000 $8,200 cash $ 42,200
1.2 State Permits Aug 2022 $3,200 $800 cash $ 4,000
1.3 Other Federal Permits Aug 2022 $7,900 $2,000 cash $ 9,900
2.1 Design Sep 2022 $80,100 $20,300 cash $100,400
2.2 Update Business Plan Sep 2022 $4,800 $1,200 cash $ 6,000
TOTALS $130,000 $32,500 $162,500
Budget Categories:
Direct Labor & Benefits $0 $5,000 cash $5,000
Travel & Per Diem $0 $5,000 cash $5,000
Equipment $0 $0 $0
Materials & Supplies $0 $0 $0
Contractual Services $130,000 $22,500 cash $152,500
Construction Services $0 $0 $0
Other $0 $0 $0
TOTALS $130,000 $32,500 $162,500
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3.2.4 Cost Justification
Indicate the source(s) of the cost estimates used for the project budget, including costs for future phases
not included in this application.
May 2020 Engineer’s Cost Estimate for Phased Development Option.
3.3 Project Communications
3.3.1 Project Progress Reporting
Describe how you plan to monitor the progress of the project and keep AEA informed of the status. Who
will be responsible for tracking the progress? What tools and methods will be used to track progress?
ECUC will rely on our hydro project manager - Jim Wild - and engineering consultant - Joel Groves, P.E. at
Polarconsult Alaska, Inc. - for progress reporting. Regular reports will be made to AEA on - at a minimum - a
quarterly basis. Mr. Groves will prepare draft progress reports for review and submittal by our hydro
project manager.
More frequent reporting may be appropriate during some phases of the project to make timely report of
notable events. Reports will include status and tracking information for work product, schedule, and
budget, allowing recipients to easily stay abreast of current project progress.
3.3.2 Financial Reporting
Describe the controls that will be utilized to ensure that only costs that are reasonable, ordinary and
necessary will be allocated to this project. Also discuss the controls in place that will ensure that no
expenses for overhead, or any other unallowable costs will be requested for reimbursement from the REF
Grant Program.
Pre-construction, most expenses will be routed through the engineer, who will ensure their invoices
conform to our grant agreements. These invoices will be reviewed by our project manager, and upon
approval forwarded to AEA as part of our reimbursement submittals.
These personnel will be familiar with the grant agreement and will ensure that disallowed costs are not
included in reimbursement requests and associated backup that is submitted to AEA. Personnel have
successfully managed prior AEA REF grants and are familiar with reporting requirements and allowable
costs for reimbursement.
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SECTION 4 – QUALIFICATIONS AND EXPERIENCE
4.1 Project Team
Include resumes for known key personnel and contractors, including all functions below, as an attachment
to your application. In the electronic submittal, please submit resumes as separate PDFs if the applicant
would like those excluded from the web posting of this application.
4.1.1 Project Manager
Indicate who will be managing the project for the Grantee and include contact information. If the applicant
does not have a project manager indicate how you intend to solicit project management support. If the
applicant expects project management assistance from AEA or another government entity, state that in this
section.
Our project manager will be Jim Wild. Jim, a 42-year resident of Elfin Cove, has been involved with this
hydro development project since the early 1980s when he proposed the first reconnaissance study be
funded by the Legislature for the Community. It was funded and Jim performed the initial stream gaging.
Jim’s Lake was named in recognition of his contributions.
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.
Mary Kirtley, Bookkeeper for ECUC.
M
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.
Jim Wild will be responsible for overall project management.
ECUC expects to contract with Polarconsult Alaska and/or other qualified firms to complete design and
permitting activities. Polarconsult engineer Joel Groves, P.E. has been the lead consultant on this project
since the reconnaissance study in 2009 and is familiar with all aspects and issues surrounding design,
permitting, and resource studies that have been completed for the project. He is experienced with the
permitting and design issues that remain to be completed to make this project shovel-ready.
ECUC may also engage locally experienced construction firms or individuals to help understand the cost,
construction, and operational implications of various construction methodologies for the project.
Construction cost and long-term sustainability of the project are key issues that ECUC needs to understand
and finalize for this project before design documents are completed.
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4.2 Local Workforce
Describe how the project will use local labor or train a local labor workforce.
During the study, permitting, and design phases, the project has used local labor for much of the field work
that has been conducted. Local labor has participated in surveying, hydrology studies, transportation and
logistics, and related items.
Use of local labor during construction will depend on how the project is managed and the availability and
willingness of qualified individuals to work on the project.
ECUC may send one or more people to AVTEC or similar hydro operator training courses before project
commissioning so they are familiar with the particulars of operating and maintaining small hydro systems.
The community intends to identify plant operators prior to construction and involve them with construction
where appropriate so they will be familiar with how the project was built, as we believe this will benefit the
utility in the long-term with project familiarity and ability to successfully and efficiently perform operations,
maintenance, repair and replacement (OMR&R) activities with local labor, equipment, and materials.
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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.
ECUC conducted a hydrology study from 2008 to 2016 to characterize resource availability for this project.
The study included bathymetric survey of Jim’s Lake (to quantify available storage volume) and stream
gauges at the proposed Crooked Creek diversion site and Jim’s Lake outlet. The hydrology study indicates
the upper system has a capacity factor of 63 percent at the proposed 5 cubic feet per second design flow,
and the overall project can supply between 82 and 90 percent of total annual ECUC electric demand
depending on the ultimate project configuration constructed. The proposed phased project would supply
82 percent of annual electricity demand under recent utility operating conditions.
Relevant resource reports are included with the application as listed at Sections 11 and 12.
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.
Other energy alternatives to existing diesel-fired generation and the proposed hydro include (1) other
hydros, (2) solar, (3) wind, and (4) tidal / hydrokinetic.
1. Other small creeks (such as Roy’s Creek) that flow through the community could provide run-of-river
hydropower. Roy’s Creek would only supply a fraction of the community’s demand (~60%), and would face
a similar permitting process that the Crooked Creek and Jim’s Lake project has already nearly completed.
The access/penstock route from the community traverses extremely steep terrain and the technical
feasibility of access and penstock construction up this route is uncertain. This resource was addressed in
the 2010 Reconnaissance Study (see application Sections 11 and 12).
2. Solar is not thought to be a viable resource due to the prevailing cloudy/rainy local climate and adverse
local topography (hills / mountains to the east and south block some sky view).
3. Wind was investigated with a met tower south of the community some decades ago and the resource
was not viable.
4. There is a world class tidal / hydrokinetic resource in South Inian Pass near the community, but “near” is
still over a mile from the community. The cost, technical, environmental, and navigational issues make this
alternative presumptively cost-prohibitive and not feasible. Also, the necessary technology is not yet
commercially available.
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5.1.3 Permits
Provide the following information as it may relate to permitting and how you intend to address outstanding
permit issues. See the “Environmental and Permitting Risks” section of the appropriate Best Practice
Checklist for additional guidance.
● List of applicable permits
● Anticipated permitting timeline
● Identify and describe potential barriers including potential permit timing issues, public opposition that
may result in difficulty obtaining permits, and other permitting barriers
The project has already initiated and made significant progress through the permitting process. Applicable
major permits include:
- FERC original license for minor water power project (final license application filed August 2020 under P-
14514-003, issuance expected in early 2022.
- USFS Special Use Permit for access to / development of federal lands in Tongass National Forest. Applied
2014, issuance expected in mid-2022 following FERC license.
- Wetlands permit from U.S. Army Corps of Engineers. Studies complete, will be filed as part of FERC
process. Eligible for NWP #17, typically ~60 days for permit issuance.
- ADNR Water Rights. Applied in 2014 (LAS 29817 and 29818). Water use permit typically issued prior to
start of construction. Water rights issued after five years of operational data is available.
- ADNR Dam Safety. Not applicable, under FERC jurisdiction.
- ADNR Fish Habitat Permit. Not applicable, finding of no permit required issued in 2014.
No public opposition to the project or unusual permitting barriers are known.
5.2 Project Site
Describe the availability of the site and its suitability for the proposed energy system. Identify potential land
ownership issues, including whether site owners have agreed to the project or how you intend to approach
land ownership and access issues. See the “Site control” section of the appropriate Best Practice Checklist
for additional guidance.
The project site is located entirely within the Tongass National Forest, including community access which
will utilize federally owned lot 40A within the townsite for access to the existing trails and utility
easements. The project site is suitable for the proposed system due to its proximity to the community and
existence of the lake which will provide useful energy storage. The U.S. Forest Service supports the project
and has been involved with the FERC consultation process. Our existing Special Use Permit application will
be processed upon completion of the FERC licensing process.
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.
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The currently proposed phase of the project is design / permitting and has no technical risk.
The major technical risk facing the project is constructing site access suitable for the selected method of
construction. Construction roads suitable for heavy equipment access will require significant slope cuts
that may encounter local surficial instabilities and trigger slope failures. This is predominately a cost risk as
managing slope failures can divert time and resources away from productive construction work. Less
extensive or no road building can reduce exposure to these hazards but preclude use of heavy equipment
for construction, requiring use of more labor-intensive construction methods.
These tradeoffs will be addressed in the final design phase to arrive at the most economic risk-based
construction methodology for the project.
It is noted that essentially all existing on-shore development in Elfin Cove has utilized manual labor with
light equipment support, so the community is familiar with these construction methods and a project built
this way will be easier to locally maintain and will be more sustainable. There is no locally available heavy
equipment, so project over-reliance on heavy equipment would mandate costly marine mobilization from
Juneau or other southeast hubs whenever such equipment is needed. Minimizing the need for heavy
equipment during and after construction would help reduce / avoid these mobilization costs.
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 has already considered and addressed all of the above environmental risk elements as part of
the FERC stage 2 consultation process. Already-completed resource studies have reviewed these subjects,
identified potential issues, and developed appropriate project adjustments to avoid, minimize, or mitigate
for potential impacts as appropriate. Resource agencies will be reviewing and commenting on these
studies and recommendations in the coming months as part of FERC’s review of the Final License
Application for the project.
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.
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5.4.1 Basic Operation of Existing Energy System
Describe the basic operation of the existing energy system including: description of control system;
spinning reserve needs and variability in generation (any high loads brought on quickly); and current
voltage, frequency, and outage issues across system. See the “Understanding the Existing System” section
of the appropriate Best Practice Checklist for additional guidance.
The existing electric system uses up to three diesel gen-sets to generate electricity to the community.
Electricity is distributed via a three phase 7.2 kV distribution system. The diesel plant is automated with
EasyGen controllers that dispatch the generators to meet load.
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).
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: John Deere 6061 diesel (179 kW, commissioned 2007, EasyGen controller installed
~2018).
Unit 2: John Deere 4045 diesel (67 kW, commissioned 2007, EasyGen controller installed ~2018).
Unit 3: John Deere 6068 diesel (110 kW, commissioned 2007, EasyGen controller installed
~2018).
Is there operational heat recovery? (Y/N) If yes estimated
annual displaced heating fuel (gallons)
Yes, estimated at 2,150 gallons annually.
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.
Existing distribution system utilizes a single 225 kVA pad-mount transformer to step up from 480 V 3-phase
delta at generation to 7.2 kV 3-phase grounded wye distribution. The distribution system is multi-hub radial
with no loop feed. Most of the distribution system is UG cable in conduit or direct burial. A leg of the system
on the west side of the Cove is overhead construction. The radial distribution leg between the diesel plant
and hydro point of tie-in is 7.2kV three-phase via a 15kV JCN armored cable w/ #2AWG copper conductors.
Tie in would occur at existing TB10. TB10 has existing 4 point junctions so no upgrade to TB10 is anticipated.
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5.4.2.3 Existing Thermal Generation Units (if applicable to your project)
Generation
unit
Resource/
Fuel type
Design
capacity
(MMBtu/hr)
Make Model Average
annual
efficiency
Year
Installed
Hours
Generic fuel oil. 200,000
btu/hr
N/A N/A 84% AFUE N/A N/A
5.4.2.4 O&M and replacement costs for existing
units
Power Generation Thermal Generation
i. Annual O&M cost for labor $33,000 1 Not applicable.2
ii. Annual O&M cost for non-labor $16,000 1 Not applicable.2
iii. Replacement schedule and cost for existing
units
Not defined. Not applicable.2
Note 1: See Table 3-1 of business plan.
Note 2: Dispatchable energy sales are envisioned with assumed annual sales of 119,000 kWh with the
phased system (also Table 3-1 of business plan). Specific buildings have not yet been targeted for refit.
Month Generatio
n (Diesel)
(kWh)
Generatio
n (Type 2)
(kWh)
Generation
(Type 3)
(kWh)
Fuel
Consumption
(Diesel-Gallons)
Peak
Load
Minimum
Load
January 11,674 - - 1,230 53 -
February 10,732 - - 1,088 50 -
March 8,103 - - 909 76 -
April 14,249 - - 1,327 105 -
May 35,659 - - 2,831 121 -
June 61,306 - - 4,506 307 -
July 59,609 - - 4,798 239 -
August 62,543 - - 5,052 236 -
September 32,085 - - 2,631 167 -
October 32,085 - - 2,631 83 -
November 13,889 - - 1,360 53 -
December 8,066 - - 837 79 -
Total 350,000 - - 29,200 307 -
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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.
The project will include an electric boiler to keep the existing diesel plant coolant loop and waste heat
loop in service so this infrastructure is not impacted. Dispatchable energy sales are envisioned see Note
2 at 5.4.2.4.
Month Diesel
(Gallons)
Electricity Propane
(Gallons)
Coal
(Tons)
Wood
(Cords, green tons,
dry tons)
Other
January 463 - - - - -
February 286 - - - - -
March 286 - - - - -
April 494 - - - - -
May 239 - - - - -
June 56 - - - - -
July 91 - - - - -
August 89 - - - - -
September 188 - - - - -
October 475 - - - - -
November 426 - - - - -
December 305 - - - - -
Total 3,400 - - - - -
5.4.3 Future Trends
Describe the anticipated energy demand in the community, or whatever will be affected by the project,
over the life of the project. Explain how the forecast was developed and provide year by year forecasts. As
appropriate, include expected changes to energy demand, peak load, seasonal variations, etc. that will
affect the project.
Historic utility load data is presented in Figure A-1 of the business plan, and has varied from 250,000 to
400,000 annual kWh at generation over the past 16 years. Pro forma financials are based on 350,000 kWh
at generation, consistent with recent years.
Based on past experience, future load trends are sensitive to electricity price and the general economic
climate for the sport fish tourism and commercial fishery industries that dominate Elfin Cove’s economy. Due
to the community’s small size and limited sectors in the local economy these trends are hard to predict.
Therefore flat load growth is assumed for the project life.
In recent years the community has exhibited a decline in year-round residents and an increase in seasonal
(summer) residents and commercial sport fishing operations. A continuation of this trend would exacerbate
the existing load pattern of small winter loads and large summer loads.
The full development option project reflects the maximum practical development of the hydrologic and basin
storage resources at Crooked Creek and Jim’s Lake. No future expansion of this project would be practical,
although separate run-of-river projects could be developed to increase total hydro capacity. The phased
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development project that is currently favored by the community could be upgraded in the future (to the full
option) to increase energy output.
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.
A description of the phased development option follows. Please also see FERC License Application Exhibit A
for a detailed description of both options.
Upper System
- The Upper System will consist of a passive self-cleaning (coanda screen) diversion structure on Crooked
Creek to divert up to 5 cfs to Jim’s Lake. This water will be conveyed by a ~833 foot long 14” diameter HDPE
penstock to an energy dissipation structure near Jim’s Lake. Flow would then enter Jim’s Lake via natural
drainage courses.
Lower System
- The Lower System will consist of a low dam to raise the level of Jim’s Lake from +338 feet to a normal
operating pool of +342 feet. A gravity intake structure would admit up to 6.5 cfs of water to the lower hydro
penstock with a normal operating band of +338 to +342 feet, providing 21 acre-feet of storage.
- Water would be conveyed to the lower powerhouse above tidewater via an approximately 2,264 foot long
14 and 16” HDPE penstock.
- The lower powerhouse would contain a two-jet impulse (Pelton or Turgo) turbine and synchronous three
phase generator rated for output of 105 kW, switchgear, controls, and ancillary equipment. Spent water
would discharge via tailrace to the cobble beach at Little Sandy Beach / Port Althorp.
Common Features
- Electricity would be stepped up to 7.2/12.47kV and transmitted via approximately 5,800 feet of new direct-
burial three-phase armored power cable starting at the lower powerhouse and extending overland to
connect to the existing ECUC distribution system at the south end of Elfin Cove (existing TB10).
- A dedicated controls cable would extend approximately 8,600 feet parallel to the existing and new
distribution lines to connect the existing diesel powerhouse to the new lower hydro powerhouse. This would
allow automatic parallel operation of the two plants.
- Approximately 9,400 feet of construction and permanent access trails between Elfin Cove, Little Sandy
Beach, Jim’s Lake, and Crooked Creek.
- A new master controller module in the diesel powerhouse to automatically operate the two plants based
on water availability and system demand. Siting of this module in the powerhouse will be challenging due to
limited available space in the powerhouse / control room.
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5.4.4.1 Proposed Power Generation Units
Uni
t #
Resource
/
Fuel type
Design
capacit
y (kW)
Mak
e
Model Expected capacity factor Expecte
d life
(years)
Expected
Availabilit
y
H1 ~0.5 to
6.5 cfs of
water
105 TBD Two jet
Pelton
or Turgo
N/A, storage project.
Projected to supply 82% of
ECUC load
50 years ~98%
5.4.4.2 Proposed Thermal Generation Units (if applicable)
Generation
unit
Resource/
Fuel type
Design
capacity
(MMBtu/h
r)
Make Model Expected
Average
annual
efficiency
Expected
life
TBD Electricity TBD TBD TBD 100% ~15 years
Electric boiler(s) for dispatchable energy.
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.
A new master controller installed at the diesel powerhouse will dispatch the four (1 hydro, 3 diesel)
generation assets to meet ECUC load in accordance with programmed economic dispatch protocol and
generator operating set points. Hydro will be dispatched first when sufficient water is available for operation
(as determined by head level sensor in the reservoir), and diesels will be turned off. Water flow and turbine
output will be regulated by turbine needle valves to meet load and retain water in the reservoir for storage.
When the reservoir is full, the turbine can be fully loaded beyond ECUC demand levels to utilize excess water
and serve dispatchable loads.
When operating solely on hydro, system frequency control will be achieved with a load bank controlled by
the hydro plant and a load bank in the diesel plant that will be block loaded to keep the diesel water jacket
and waste heat coolant loops in service.
When ECUC load exceeds available hydro capacity or water availability (depleted reservoir), a diesel gen set(s)
will be activated in “isoc” mode and base loaded to achieve good fuel economy and operating point. If
available, the hydro will be operated in “droop” mode and the load bank frequency controller disabled or
relegated to secondary control to address hydraulic transients.
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System modeling indicates the hydro plant can supply 82% of ECUC’s annual energy load, and operate in a
diesel-off state approximately 90% of the time.
5.4.3.1 Expected Capacity Factor 65%
Please note that “capacity factor” is not directly
applicable to storage hydro projects as energy output
can vary with how the reservoir is used. 65% is the
“capacity factor” for the phased development option
for ECUC load pattern and operation protocols as
described in this proposal. It may vary with different
load patterns, load levels, or operation protocols.
5.4.5.2 Annual Electricity Production and Fuel Consumption (Proposed System)
Month Generatio
n
(Proposed
Hydro)
(kWh)
Generation
(Diesel)
(kWh)
Generation
(Type 3)
(kWh)
Fuel
Consumption
(Diesel-
Gallons)
Fuel
Consumption
[avg month
cfs water]
Secondary
load
(kWh)
Storage
(kWh)
January 28,347 7 - 1 - -
February 27,996 0 - 0 - -
March 30,178 19 - 2 - -
April 27,783 0 - 0 - -
May 55,580 7,850 - 749 - -
June 55,208 15,744 - 1,503 - -
July 56,831 16,129 - 1,540 - -
August 58,735 15,650 - 1,494 - -
September 40,654 6,316 - 603 - -
October 24,260 0 - 0 - -
November 26,060 0 - 0 - -
December 28,868 85 - 8 - -
Total 460,500 61,800 - 5,900 - -
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5.4.5.3 Annual Heating Fuel Consumption (Proposed System)
Month Diesel
(Gallons)
Electricity
(Dispatched
from hydro)
Propane
(Gallons)
Coal
(Tons)
Wood
(Cords, green
tons, dry tons)
Other
January - 16,209 - - - -
February - 9,997 - - - -
March - 10,002 - - - -
April - 17,303 - - - -
May - 8,367 - - - -
June - 1,974 - - - -
July - 3,201 - - - -
August - 3,103 - - - -
September - 6,593 - - - -
October - 16,641 - - - -
November - 14,923 - - - -
December - 10,687 - - - -
Total - 119,000 - - - -
5.4.6 Proposed System Operating and Maintenance (O&M) Costs
O&M costs can be estimated in two ways for the standard application. Most proposed renewable energy
projects will fall under Option 1 because the new resource will not allow for diesel generation to be turned
off. Some projects may allow for diesel generation to be turned off for periods of time; these projects
should choose Option 2 for estimating O&M.
Option 1: Diesel generation ON
For projects that do not result in shutting down
diesel generation there is assumed to be no impact
on the base case O&M. Please indicate the
estimated annual O&M cost associated with the
proposed renewable project.
$N/A
Option 2: Diesel generation OFF
For projects that will result in shutting down diesel
generation please estimate:
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. $3,100 annual savings.
2. Hours diesel OFF/year: ~7,880 hrs/yr
3. $20,000 annual expense.
(please see pro formas in Business Plan)
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5.4.7 Fuel Costs
Estimate annual cost for all applicable fuel(s) needed to run the proposed system (Year 1 of operation)
Diesel
(Gallons)
Electricity Propane
(Gallons)
Coal
(Tons)
Wood
Other
Unit cost ($) 4.03
(note 1)
- - - - -
Annual
Units
5,900 - - - - -
Total
Annual cost
($)
$23,777 - - - - -
Actual current cost for #2 diesel. AEA model price of $3.38/gal is low.
5.5 Performance and O&M Reporting
For construction projects only
5.5.1 Metering Equipment
Please provide a short narrative, and cost estimate, identifying the metering equipment that will be used to
comply with the operations reporting requirement identified in Section 3.15 of the Request for
Applications.
Plant switchgear and controls will include required sensors and logging capability to automatically collect
plant generation and performance information.
No incremental cost is expected for infrastructure needed to comply with AEA reporting requirements.
5.5.2 O&M reporting
Please provide a short narrative about the methods that will be used to gather and store reliable operations
and maintenance data, including costs, to comply with the operations reporting requirement identified in
Section 3.15 of the Request for Applications
The plant operator will maintain maintenance and repair logs. Relevant maintenance and repair activities
will be summarized and reported to AEA on an annual basis for the required 10-year period.
The labor effort to compile required data, prepare annual reports, and respond to AEA reporting inquiries is
estimated at $5,000 annually.
SECTION 6 – ECONOMIC FEASIBILITY AND BENEFITS
6.1 Economic Feasibility
6.1.1 Economic Benefit
Annual Lifetime
Anticipated Diesel Fuel Displaced for Power
Generation (gallons)
23,300 1,165,000
Anticipated Fuel Displaced for Heat (gallons) 3,400 170,000
Total Fuel displaced (gallons) 26,700 1,335,000
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Anticipated Diesel Fuel Displaced for Power
Generation ($)
$93,899 $4,694,950
Anticipated Fuel Displaced for Heat ($) $13,702 $685,100
Anticipated Power Generation O&M Cost
Savings
$3,100 savings $155,000
Anticipated Thermal Generation O&M Cost
Savings
$0 $0
Total Other costs savings (taxes, insurance,
etc.)
$0 $0
Total Fuel, O&M, and Other Cost Savings $110,701 $5,535,050
6.1.2 Economic Benefit
Explain the economic benefits of your project. Include direct cost savings and other economic benefits, and
how the people of Alaska will benefit from the project. Note that additional revenue sources (such as tax
credits or green tags) to pay for operations and/or financing, will not be included as economic benefits of
the project.
Where appropriate, describe the anticipated energy cost in the community, or whatever will be affected by
the project, over the life of the project. Explain how the forecast was developed and provide year-by-year
forecasts
The economic model used by AEA is available at www.akenergyauthority.org/What-We-Do/Grants-
Loans/Renewable-Energy-Fund-REF-Grants/2020-REF-Application. This economic model may be used by
applicants but is not required. The final benefit/cost ratio used will be derived from the AEA model to ensure
a level playing field for all applicants. If used, please submit the model with the application.
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Direct economic benefits from this project under the financial assumptions in our business plan (Please see
Figures 3-1 and 3-2 of the business plan) include reduced electricity rates for the community and increased
stability in electric rates over time as our dependence on volatile fuel prices and fuel delivery prices will be
significantly reduced with the hydro operational. These benefits would be augmented if the project is able
to qualify for and receive additional revenue from green tags / renewable energy credits, tax credits, or other
financial incentives. Because of the volatility in the terms and eligibility thresholds of these various programs,
ECUC is not expecting to realize revenue from them but will explore them when the project financing is
finalized to see what - if any - programs have merit.
The AEA economic model shows a benefit-cost ratio of 0.68 for the project. However, the AEA fuel price
model for Elfin Cove is incorrect, as it shows a 2020 fuel price of $3.10 per gallon whereas current price is
30% higher at $4.03 per gallon. Adjusting the fuel price in the AEA economic model to reflect current and
historical prices results in a benefit-cost ratio of 0.83 for the project.
There is currently only one vessel in the region that has the USCG certifications for bulk fuel transport and
that can maneuver into the Elfin Cove fuel dock to make fuel deliveries. This is a chronic issue Elfin Cove has
dealt with for years. This forces Elfin Cove to pay a premium for fuel delivery due to both poor economy of
scale and lack of competition. It also presents a fuel security issue for the community as there is only one
operator that can provide bulk fuel deliveries to the community.
Indirect benefits that are not readily reduced to dollar values include (see also narrative at 6.2):
- By reducing local fuel demand and marine transport volumes, this project incrementally reduces the risk of
catastrophic damage to our economy due to a significant fuel spill in Cross Sound or neighboring waters.
Such a spill would directly and adversely impact our local tourism industry, commercial fishery support
industry, destination sport fishing industry, and many local residents who are commercial fishermen.
- By reducing utility fuel usage, this project will change fuel storage needs at our bulk fuel facility, providing
increased flexibility in management of our tanks. ECUC recently had to reallocate a 2nd 20,000 gallon tank
from heating oil to gasoline to meet peak summer gasoline demand. This project would help avoid the need
to upgrade or expand the bulk fuel facility.
- By introducing a significant new local hiking corridor, bolster the local / small cruise operator industry by
providing a new on-shore day excursion opportunity.
- Extend the life of our existing diesel plant, reducing overall frequency of engine overhauls and deferring
plant upgrade / replacement requirements.
- Improve quality of life by reducing diesel power plant stack emissions (improved local air quality) and
reducing sound emissions from the diesel power plant.
- Improves local recreational and subsistence opportunities for residents by providing an improved trail
access to uplands south of the community. Prevents degradation of the forest floor along existing primitive
trails along the project trail corridors.
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
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● Other factors
The main risk that nearly all Alaska hydro projects have encountered in recent years is construction cost
risk, where the final installed cost of projects have been significantly higher than estimates developed
throughout the planning and design phases. Two examples of this include Battle Creek (~50% over budget,
2020 1, 2) and Blue Lake Dam Raise (~93% over budget, 2012 3). The current budget estimate is based on
site conditions, 65% design, and recent cost experience for similar Alaska hydro projects. Cost estimates
will be scrutinized during the proposed phase of the project in conjunction with consideration of
construction methodology and long-term sustainability to complete final designs with a goal of making the
project as economic and locally sustainable as possible.
Exposure to other economic risks, such as future episodes of low-cost alternate fuels or energy alternatives,
will depend on the final financing plan for the project. The greatest risk is perhaps a declining load. This
would have a somewhat muted effect on hydro revenue, as the hydro can meet a higher percentage of load
as total load decreases due to the lower system reservoir (see business plan Figure A-2). The utility could
also connect additional dispatchable energy circuits to increase kWh sales, although this would not fully
replace prime energy revenues due to the lower per-kWh rate for dispatchable sales.
1. Battle Creek Diversion TPS Report, 2011 Legislature ($31.5 million cost estimate).
2. Battle Creek Completion Press Release, AEA, 8/27/2020 ($47 million final cost).
3. Blue Lake Dam Raise Construction Award, KCAW article, 9/12/2012. ($96.7 million bid vs. $50 million
engineer’s estimate).
6.1.4 Public Benefit for Projects with Direct Private Sector Sales
For projects that include direct sales of power to private sector businesses (sawmills, cruise ships, mines,
etc.), please provide a brief description of the direct and indirect public benefits derived from the project as
well as the private sector benefits and complete the table below. See Section 1.6 in the Request for
Applications for more information.
Not applicable. All electricity sales will be through the electric utility.
Renewable energy resource availability (kWh per month) N/A
Estimated direct sales to private sector businesses (kWh) N/A
Revenue for displacing diesel generation for use at private sector businesses ($) N/A
Estimated sales for use by the Alaskan public (kWh) see 5.4.5.2
Revenue for displacing diesel generation for use by the Alaskan public ($) see 5.4.5.2
6.2 Other Public Benefit
Describe the non-economic public benefits to Alaskans over the lifetime of the project. For the purpose of
evaluating this criterion, public benefits are those benefits that would be considered unique to a given project
and not generic to any renewable resource. For example, decreased greenhouse gas emission, stable pricing
of fuel source, won’t be considered under this category.
Some examples of other public benefits include:
● The project will result in developing infrastructure (roads, trails, pipes, power lines, etc.) that can be used
for other purposes
● The project will result in a direct long-term increase in jobs (operating, supplying fuel, etc.)
● The project will solve other problems for the community (waste disposal, food security, etc.)
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● 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 FERC consultation process has identified the project trail system as a prospective “destination trail” for
small cruise ship operators in the vicinity of Elfin Cove. Existing on-shore trail options in the region are
”out-and-back”, and the one-way hike from Elfin Cove to Little Sandy Beach (or vice versa) would provide a
unique and attractive option for on-shore day excursions. The terrain along and vistas from the trail route
are considered attractive, and the existence of the hydro system and lake may also be significant
attractions for local tourists.
The project will provide price security for local rate-payers, who have experienced extreme rate shock in
recent years due to variable fuel cost compounded with variable premiums for local fuel delivery. Price
stability will help both residents and businesses, both promoting and sustaining long-term commercial
economic development for the community.
By reducing the volume of fuel transported via marine barge to Elfin Cove, the project will incrementally
reduce the hazard of marine (or on-shore) fuel spills. Elfin Cove’s economy is highly dependent on the
integrity and health of marine fisheries (for tourism, sport fishery and commercial fishery sectors), and a
significant local fuel spill could have devastating short and long-term impacts to all the economic pillars of
our economy.
Reduced utility fuel demand in Elfin Cove will also help us better manage our bulk fuel storage capacity.
Current local demand for gasoline in the summer months and chronic limited delivery options / capacity
caused us to dedicate two 20,000 gallon tanks to gasoline, leaving only one 5,000 gallon tank for home
heating fuel. Reduced utility fuel demand would improve operational flexibility at our bulk fuel facility.
In hydro mode the diesel generators would be off-line; therefore no noise and fume pollution in Elfin Cove
for ~90% of the time.
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SECTION 7 – SUSTAINABILITY
Describe your plan for operating the completed project so that it will be sustainable throughout its
economic life.
At a minimum for construction projects, a business and operations plan should be attached and the
applicant should describe how it will be implemented. See Section 11.
7.1.1 Operation and Maintenance
Demonstrate the capacity to provide for the long-term operation and maintenance of the proposed project
for its expected life
● Provide examples of success with similar or related long-term operations
● Describe the key personnel that will be available for operating and maintaining the infrastructure.
● Describe the training plan for existing and future employees to become proficient at operating and
maintaining the proposed system.
● Describe the systems that will be used to track necessary supplies
● Describe the system will be used to ensure that scheduled maintenance is performed
Elfin Cove has successfully operated its utilities (electric, water, and bulk fuel) for many years, including
servicing the debt financing of our bulk fuel facility for many years.
ECUC has not yet identified specific personnel that would be responsible for plant operations. It is our
intent to identify such personnel prior to construction so they can be involved with construction if practical.
This will give them greater familiarity with the project which will be invaluable for operations and
maintenance.
As appropriate, ECUC will train operators either with formal education at institutions such as AVTEC or by
visiting similar local hydro plants in southeast to become familiar with plant operational requirements,
issues, and methods.
Operations and Maintenance Plans will be developed concurrent with plant construction to capture final
design elements, as-built conditions, and relevant site and equipment information learned during
construction. In general, these plans are expected to be developed as follows.
Maintenance requirements will be identified in the operations and maintenance manuals furnished by
various vendors during the construction phase. These diverse requirements will be captured in a unified
concise O&M document specifying by major project element the pertinent O&M activities and intervals,
with reference back to the individual O&M manuals for more specific details. The unified O&M manual will
include maintenance logs that will be kept current by plant personnel.
Critical spare parts requirements will also be pulled from the vendor operations and maintenance manuals,
and an integrated list will be developed. Spare parts critical to plant operation and/or with long
procurement lead times will be maintained in on-site inventory. In some instances, high-cost items may
not be stocked if their cost is greater than the risk-weighted cost of a plant outage in the event of
component failure.
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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.
ECUC’s existing accounting and bookkeeping system will be used to account for operational and capital
costs. Costs will be categorized in accordance with FERC requirements (USOA).
ECUC’s electricity rates are set by ECUC’s governing board. ECUC electricity rates have traditionally been
set to cover costs with appropriate margin for unforeseen events.
Revenue is collected in accordance with our tariff, including provisions for account disconnect or referral to
collections in the event of non-payment of utility bills.
7.1.2.1 Revenue Sources
Briefly explain what if any effect your project will have on electrical rates in the proposed benefit area over
the life of the project. If there is expected to be multiple rates for electricity, such as a separate rate for
intermittent heat, explain what the rates will be and how they will be determined
Collect sufficient revenue to cover operational and capital costs
● What is the expected cost-based rate (as consistent with RFA requirements)
● If you expect to have multiple rate classes, such as excess electricity for heat, explain what those rates
are expected to be and how those rates account for the costs of delivering the energy (see AEA’s
white paper on excess electricity for heat)..
● Annual customer revenue sufficient to cover costs
● Additional incentives (i.e. tax credits)
● Additional revenue streams (i.e. green tag sales or other renewable energy subsidies or programs that
might be available)
Projected electric rates with the project are presented on Figure 3-1 of the business plan. Year 1 rates are
0.63 per kWh with the hydro and $0.67 per kWh without. Increasing savings are projected over the life of
the project. Actual rates will depend on the final capital cost and financing plan for the project.
Rates for dispatchable energy will be set to be competitive against the variable price of fuel-fired heating.
The pro forma rate in the business plan for dispatchable energy is $0.07 per kWh, compared to $0.63 per
kWh for standard electric service.
ECUC’s pro forma financials for the project assume no revenue from tax credits or sale of renewable energy
credits from the project. ECUC will consider tax credits, obligatory, and voluntary REC market opportunities
that are available at the time of construction. The decision to pursue these revenue streams will depend on
the cost to qualify for the programs, potential revenue, and perceived risk.
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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.
ECUC will use all electricity from the project to meet existing and future loads within its certificated service
area.
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.
CECNPC has been pursuing this project since the early 1980s. In the past decade we have completed
updated reconnaissance and feasibility studies. In recent years we successfully completed FERC
consultation processes and conducted exhaustive agency-required studies for the project, culminating in a
final FERC license application submitted on August 24, 2020. We will be advancing through the FERC
license application review and consultation steps during the next several months to bring this project closer
to fruition.
The project is in an advanced stage of permitting and design, with the following tasks already completed or
in progress:
- 65% designs completed.
- FERC Final License Application submitted (docket P-14514).
- Resource studies covering hydrology, geology, mineral potential, fisheries, wetlands, botany, wildlife,
recreation, subsistence, scenery, and cultural resources have been completed.
- Energy resource has been characterized with 8+ years of on-site hydrology study covering both Jim’s Lake
and Crooked Creek. Site topography and lake bathymetry have also been surveyed.
- Other major permit applications have been submitted and will be adjudicated as part of/or concurrent
with the FERC licensing process.
- Engineer’s Energy Estimate and Cost Estimates completed.
- Business Plan completed, including current utility load profile, load trends and pro forma financials.
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These deliverables have already been submitted to AEA as part of the prior grant, and are included with this
application as described in sections 11 and 12.
The requested funds are to complete the current permitting and design stage:
1.1. Continue the FERC licensing process already under way. ECUC is already advancing the licensing
process, and requested funds will be used to help support this process beyond July 2021, including to
address follow-on study requirements or other items that may arise from the upcoming review and
consultation processes. We expect these will be better defined by the time grant expenditures are
authorized in July 2021.
1.2. Obtain other remaining federal permits for the project, to include Corps wetland permit (NWP 17),
USFS Special Use Permit (site control).
1.3 Obtain other remaining state permits for the project, to include ADNR water use permit (cases LAS
29817, LAS 29818). ECUC has already obtained a finding from ADFG that no fish habitat permit is required.
2.1. Complete design documents. ECUC will need to finish the existing 65% design documents once final
permit terms and conditions are issued and regulatory design constraints are finalized.
2.2. Update energy estimate, cost estimate, business plan, and financing plan for the project to reflect final
designs and final permit terms and conditions.
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.
Not applicable.
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 July 20, 2020. Please note that letters of support from legislators will not count
toward this criterion.
This project is included in the Southeast Integrated Resource Plan prepared for AEA in 2012 by Black and
Veatch. It is on the “Refined Screened Potential Hydroelectric Project List” of Table 10-4 and referenced
throughout the report narrative as the only alternative to continued diesel-fired generation for the
community.
See applicable support letters included with the application.
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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.
ECUC has successfully and fully complied with all other grant awards from AEA for this (see application
section 2.6) and other projects, including:
Electric distribution system upgrade (AEE Project 05-02-9825, 2010)
Bulk fuel upgrade (grants / loans, approximately 1998 to 2000)
Diesel Powerhouse upgrade (RPSU program, 2007).
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.
The following existing studies, and related project information are included with this application:
- 2010 Reconnaissance Study
- 2011 Feasibility Study
- 2020 FERC Final License Application
- Initial Statement
- Exhibit A, Project Description
- Exhibit E, Environmental Report (Includes 12 resource studies as attachments*)
- Exhibit F, Project Drawings (FERC CEII, public distribution is restricted. Available upon request.)
- Exhibit G, Project Land Map
- 2020 Business Plan
* ECUC has also completed a Cultural Resources Study. This includes confidential information, and is
available upon request.
SECTION 12 – LIST OF ADDITIONAL DOCUMENTATION SUBMITTED FOR CONSIDERATION
In the space below, please provide a list of additional information submitted for consideration.
None. Please see Section 11.