HomeMy WebLinkAboutMt. Spurr Geothermal Interconnect Feasibility Study Report - FINAL - Nov 2024 - REF Grant 7015025Table of Contents
Executive Summary .................................................................................................................... ES-1
1.Introduction ............................................................................................................................ 1
2.Scope of Work ......................................................................................................................... 1
3.Intertie Alignments ................................................................................................................. 2
3.1 Alignment Concept A .......................................................................................................... 2
3.2 Alignment Concept B .......................................................................................................... 2
3.3 Alignment Discussion .......................................................................................................... 2
3.3.1 Concept A - Advantages .......................................................................................... 2
3.3.2 Concept A - Disadvantages...................................................................................... 2
3.3.3 Concept B - Advantages .......................................................................................... 3
3.3.4 Concept B - Disadvantages ...................................................................................... 3
4.Preliminary Engineering Analysis ............................................................................................ 5
4.1 Voltage and Conductor Selection ........................................................................................ 5
4.2 Interconnection at Source and Delivery Point .................................................................... 5
4.3 Conductor Selection ............................................................................................................ 6
4.3.1 Voltage Versus Clearance ........................................................................................ 6
4.3.2 Helicopter Construction Constraints ....................................................................... 6
4.3.3 Structures ................................................................................................................ 7
4.3.4 Fiber Optic Communication and Lightning Protection ......................................... 10
4.3.5 Foundations .......................................................................................................... 10
4.3.6 Route Review ........................................................................................................ 11
5.Cost and Financial Study ....................................................................................................... 12
5.1 Transmission Line Cost Estimate ....................................................................................... 12
5.2 Substation Cost ................................................................................................................. 12
5.3 Construction and Permitting Schedule ............................................................................. 13
6.Permitting/Licensing Requirements ..................................................................................... 13
7.Environmental Screening ...................................................................................................... 15
7.1 Complex National Environmental Policy Act (NEPA) Process ........................................... 15
7.2 Delays in Negotiating ROW Leases ................................................................................... 16
8.Financial Modeling and Tax Incentives ................................................................................. 16
9.Summary of Cost Estimate .................................................................................................... 18
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List of Tables
Table 1. Concepts A & B Projected Transmission Line Capital Costs ........................................ ES-2
Table 2. Projected Substation Capital Costs .............................................................................. ES-2
Table 3. Quantity of Structures ..................................................................................................... 11
Table 4. Concepts A & B Transmission Line Monopole Construction Cost Estimates .................. 12
Table 5. Construction and Permitting Schedule ........................................................................... 13
Table 6. Adjusted Transmission & Substation Capital Cost, Concept A...................... ................. 17
Table 7. Adjusted Transmission & Substation Capital Cost , Concept B........................................ 17
Table 8. Total Transmission Line (Monopole) and Substation Construction Costs ...................... 19
List of Figures
Figure 1. Alignment for Transmission Line Concepts A & B............................................................ 4
Figure 2. 138-kV Tangent and Dead-End Structures....................................................................... 8
Figure 3. H-Frame Type Construction ............................................................................................ 9
Appendices
Appendix A – Topographic Map of Study Area
Appendix B – Transmission Design Criteria
Appendix C - Standard Steel Structures
Appendix D - Transmission and Substation Cost Estimates
Appendix E - Water Bodies – Wetlands
Appendix F - Land Ownership in Study Area
Appendix G - Land Ownership in Eastern Study Area
Appendix H – Potential Permits and Fees
Appendix I – Cost Estimates – Permitting
Appendix J – Substation One-line Concepts
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Acronyms
AEEC/HEA Alaska Electric & Energy Cooperative, Inc., a subsidiary of Homer Electric
Association Inc.
ADNR Alaska Department of Natural Resources
ADSS All-dielectric self-supporting
ACSR aluminum conductor steel reinforced
CEA Chugach Electric Association
CIRI Cook Inlet Regional, Inc.
EA Environmental Assessment
EIS Environmental Impact Statement
GSU Generator step-up
kCMIL Thousand circular mils
kV kilovolts
kVA kilovolt ampere
MVA Megavolt ampere
MW megawatts
OHGW overhead ground wire
OLF Overload factor
OPGW optical ground wire
MVA Megavolt ampere
NEPA National Environmental Policy Act
NESC National Electric Safety Code
psf pounds per square foot
RUS Rural Utilities Service
T&E Threatened and endangered
WPE West Peak Energy, LLC
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Executive Summary
West Peak Energy, LLC (WPE) was contracted by Alaska Electric & Energy Cooperative, Inc., a
subsidiary of Homer Electric Association, Inc. (AEEC/HEA), to complete a transmission
interconnection study and cost estimate for a future proposed geothermal resource to be located
at Mt. Spurr on the Alaska Peninsula. The transmission line would connect the geothermal plant,
located at 61.246659 Latitude and -152.226784 Longitude, to the existing Chugach Electric
Association (CEA)-owned Beluga Power Plant and Substation/Switchyard (138/230 kilovolt) at
Beluga, Alaska located approximately 61.186425 Latitude and -151.037044 Longitude.
The geothermal resource consists of two 35 megawatt (MW) plants (70 MW total) and requires
delivery of this power output to the Alaska Railbelt transmission facilities at CEA’s Beluga Power
Plant and associated switchyard site at Beluga, Alaska. WPE’s team concluded that this power
can be delivered with a steel monopole structure transmission facility energized at 138-kilovolt
(kV) RUS 1 standard construction methods and carried on a 477 thousand circular mills (kCMIL)
aluminum conductor steel reinforced (ACSR) conductor at an average of 600-foot spans.
Winter construction for the remote transmission line with no permanent road development for
access is anticipated, like other Southcentral Alaska transmission lines. Conceptual routes for the
transmission line were explored. Two likely conceptual routes for the transmission line alignment
are a 53-mile route (alignment Concept A), and a 41-mile route (alignment Concept B).
Either route serves the need for transmission of power from the renewable geothermal energy
resource on Mt. Spurr to the Alaska Railbelt transmission grid. These routes would be further
refined and finalized in a single route decision through a future design development effort.
These two potential routes considered are identified as Concept A and Concept B in this study
and have advantages and disadvantages discussed in Section 3 below.
Concept A is a 53-mile (and approximately 512 monopole structures) route that runs between
the CEA Beluga Power Plant site and follows the Cook Inlet coast to southeast of the base of
Mt. Spurr and then northwesterly, departing from the Cook Inlet to reach the geothermal site on
Mt. Spurr. This longer route has several advantages that would locate the transmission line closer
to already-developed infrastructure including access roads and airports. Additionally, this route
keeps the transmission facilities at a lower elevation and out of the steeper and ravine-laden
terrain of its alternative in the Concept B route. The Concept A route would facilitate better
access for maintenance, operations, and collaborative cost-sharing opportunities. This route
contains more landowner diversity and right-of-way (ROW) acquisition and leases that would be
more challenging and potentially more costly to maintain.
1 U.S. Department of Agriculture Rural Utilities Service Bulletin 1724E-200 Design Manual for High Voltage
Transmission Lines
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Concept B is a 41-mile (and approximately 396 monopole or 222 H-Frame structures) route that is
more of a direct line cross country from the Beluga Power Plant and the associated 138/230 kV
switchyard site to the proximity of the geothermal resource on Mt. Spurr. This route keeps the
transmission facilities at a higher elevation with steeper and ravine-laden terrain which has access
challenges for construction, maintenance, and operations. This route, while 12 miles shorter than
Concept A, is potentially more remote and difficult to access. We have taken that into account in the
construction costs, which may have more helicopter work involved to construct and maintain the
transmission line. It potentially is a simpler route to permit and has fewer landowners to cross, and
therefore, a simpler ROW acquisition involved. See additional information in Section 4.3.6, Route
Review section below.
There is a Construction and Permitting Schedule in Table 5 Section 5.3 which gives a range of probable
construction, ROW acquisition, and permitting times for the two Concept A and B routes. It is likely
that the material procurement has the potential to have the longest time impact not presented but
may adversely affect the construction schedules. At this time, supply chain issues, like large power
transformers for instance have a 1-to-2-year acquisition time once designed, and that needs to be
factored into project planning.
The transmission routes have the conceptual costs associated with their development shown in
Table 1; these are fully burdened costs from an owner ’s perspective, not just direct construction cost.
Table 1. Concepts A & B Projected Transmission Line Capital Costs
53-Mile 138-kV Line Route
with Contingency
41-Mile 138- kV Line Route
with Contingency
$61,4439,727* $47,881,957*
*Note: See Sections 8 and 9 below for supporting cost details.
Table 2. Projected Substation Capital Costs
138-kV Substations with Contingency
$15,693,633*
*Note: See Section 9 below for supporting cost details.
The Inflation Reduction Act of 2022 includes a geothermal federal tax credit amount equal to
30 percent of the eligible investment in a qualified geothermal facility if prevailing wage and
apprenticeship requirements are satisfied (otherwise 6 percent). The Inflation Reduction Act also
includes the cost of transmission property when determining the credit available to a qualified
geothermal facility. In addition to credits under the Inflation Reduction Act, the Internal Revenue
Service allows for certain transmission assets to be depreciated over a 20-year depreciation life,
excluding non-depreciable assets as land. The combination of these two results, tax credit and
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depreciation, have a potential range of reductions of capital cost from approximately 60 percent
to about 50 percent of the costs. See Section 8 for the details of these impacts.
Permitting, leasing, and easement requirements have various time impacts and may be
dependent on the connected actions of the development of the geothermal resource and
possible National Environmental Policy Act requirements. The level of effort for environmental
permitting would be similar for Concept A and Concept B; however, lease and ROW acquisition
for Concept A would be much more time-consuming and difficult due to the numerous small
landowners involved. Finally, several organizations whose land would be crossed by one or both
concepts studied do not have well-defined or predictable processes for granting ROW leases.
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1.Introduction
West Peak Energy, LLC (WPE) was contracted by Alaska Electric & Energy Cooperative, Inc., a
subsidiary of Homer Electric Association, Inc. (AEEC/HEA), to complete a transmission
interconnection study and cost estimate for a future proposed geothermal resource to be located
at Mt. Spurr on the Alaska Peninsula. The transmission line would connect the geothermal plant
to the existing Chugach Electric Association (CEA)-owned Beluga Power Plant and Substation at
Beluga, Alaska. This would be a remote-constructed transmission line over undeveloped virgin
lands of various ownership and terrain.
Conceptual routes for the transmission line were explored. Two likely conceptual routes for the
transmission line alignment are a 53-mile route (alignment Concept A), and a 41-mile route
(alignment Concept B). Either route serves the need for transmission of power from the
renewable geothermal energy resource on Mt. Spurr to the Alaska Railbelt transmission grid.
2.Scope of Work
The scope of this Feasibility Study includes an evaluation of the proposed alignment, structure
configuration, voltage and conductor analysis, construction cost estimate, environmental issue
identification, and financial evaluation for this transmission connection to the geothermal
resource of two 35 megawatt (MW) plants for a total of 70 MW. The premise that winter
construction and remote transmission right-of-way (ROW) with no permanent road development
for access is assumed, as is common for Alaska transmission resources.
WPE and its consultants have reviewed the transmission line routes, possible voltage levels,
reliability, and construction issues. In review of the Mt. Spurr transmission line, consideration of
three different voltages were included—69 kilovolts (kV), 138 kV, and 230 kV, to transmit 70 MW
from the geothermal site to the Beluga Power Plant. Available transmission voltages at the Beluga
substation are 138 kV and 230 kV.
The industry standard is to have redundancy in the system in case of failure, reliability, and
maintenance needs. The geothermal plant is assumed to consist of two 35 MW steam turbines
with a generator output of 13.8 kV. Therefore, there would be some inherent redundancy with
this setup, if one unit was down for maintenance or a failure, the remaining unit could still
produce power. In this same situation, it is typical to have two transformers stepping up the
voltage from the 13.8 kV to the transmission voltage. A simple one-line diagram of this typical
setup is attached as Appendix J, Substation One-line Concepts.
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3.Intertie Alignments
3.1 Alignment Concept A
Alignment for a new transmission line, Concept A, as shown in the diagram below, would extend
from the existing transmission facilities at the CEA Beluga Power Plant, where it intercepts the
Alaska Railbelt transmission system at the switchyard, to the geothermal resource on Mt Spurr.
Running southwest for a distance along the Cook Inlet shoreline from Beluga at lower elevations,
then continuing northwest from the shore of Cook Inlet and northwest along the foothills at the
base of Mt. Spurr where it intercepts a proposed switchyard (see Appendix J), and the geothermal
resource on Mt. Spurr (see Figure 1 below). In general, easements and/or permits will be
required for all portions of the Concept A route and Appendix F and G show the land ownership
in the study area.
3.2 Alignment Concept B
Alignment for transmission line Concept B, as shown in Figure 1 below, begins at the Alaska
Railbelt transmission facilities at the CEA Beluga Power Plant switchyard extending to the west
toward the geothermal resource on Mt Spurr. There, it intercepts a proposed switchyard at the
geothermal resource on Mt. Spurr (see Appendix J). In general, easements and/or permits will
be required for all portions of the Concept B route and Appendix F and G show the land ownership
in the study area.
3.3 Alignment Discussion
Alignment Concept A and Concept B are both constructible and require winter construction
techniques. Both alignments have a variety of landowners that will need easements and permits
addressed to acquire a more contiguous route; an effort that is beyond the scope of this study.
3.3.1 Concept A - Advantages
This longer route has several advantages that would locate the transmission closer to already
developed infrastructure including access roads and airports along Cook Inlet. Additionally, this
route keeps the transmission facilities at a lower elevation and out of the steeper and ravine-
laden terrain of its alternative in the Concept B route. This Concept A route would facilitate better
access for maintenance, operations, and collaborative cost-sharing opportunities. This route has
the potential to have better access to a road, if developed, for access to the geothermal source.
3.3.2 Concept A - Disadvantages
This route is 12 miles longer including more landowner diversity and ROW acquisition, leases, and
permits that would be more challenging and potentially more costly to maintain. It will require
more angle and dead-end structures with more guys and anchors than the Concept B alignment.
Clearing is assumed required for most of this Concept.
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3.3.3 Concept B - Advantages
This route is 12 miles shorter than Concept A and therefore less expensive to construct.
Concept B would be a simpler route to permit. It has fewer landowners to cross and therefore a
simpler ROW acquisition involved. It has fewer dead-end and angle structures with fewer guys
and anchors. See additional information in Section 4.3.6, Route Review, below.
3.3.4 Concept B - Disadvantages
This route, while 12 miles shorter than Concept A, is potentially more remote and has difficult
terrain to access. The entire route is remote from all known infrastructure and land development.
This route keeps the transmission facilities at a higher elevation with steeper and ravine-laden
terrain which provides challenges for construction, maintenance, and operations. The route has
more helicopter work involved to construct and maintain the transmission line; and as a result, it
is riskier to construct and access. Clearing is assumed required for most of this alignment.
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Figure 1. Alignment for Transmission Line Concepts A & B
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A third alignment option could be explored once more information is acquired about the land
ownership and propensity to allow an overhead transmission facility in proximity to the existing
infrastructure. This would most likely be in between the range of cost options developed in this
Feasibility Study.
4.Preliminary Engineering Analysis
4.1 Voltage and Conductor Selection
Voltages of 69, 138, and 230 kV were considered for this Feasibility Study. Our analysis concluded
that 477 thousand circular mills (kCMIL) ACSR would be the optimum conductor to use due to the
rated strength and span lengths involved. The light electrical loading of the circuit, 70 MW, is not
the driver for the selection but there would be ample room for additional power delivery should
the geothermal source size increase.
Transformer selection for this type of configuration would typically be a 40/50/60 megavolt
ampere (MVA) unit, thus, the lower rating could easily carry one 35 MW turbine and up to 60 MVA
of generation in case one of the two transformers was down for maintenance. HEA solicited
115/25 kV 20 MVA transformers in 2023 and received ˜$52-124/kVA bids. The budget level cost
for transformers in 2024 is approximately $100/kilovolt amp (kVA) using the lower rating, so a 40
MVA (40,000 kVA) unit would be $4,000,000. Using this budget amount, four 69-kV transformers
would cost $16 million as compared to two 138-kV or 230-kV transformers at approximately $8
million, excluding the remaining interconnection costs. This comparison supports the 138-kV
voltage selection.
Based on the above comparison, the 69-kV transformation was ruled out and follow-up
investigations were conducted for the existing 138-kV and 230-kV voltages that are available at
the Beluga substation.
WPE reviewed 138-kV and 230-kV transmission criteria using RUS Bulletin 1724E-200 (Design
Manual for High Voltage Transmission Line, 2015 in Section 9-1, Table 9-1), which recommends
the minimum conductor size for 138-kV to be 336.4 kCMIL ACSR and for 230 kV to be 795 kCMIL
ACSR. As stated, these minimums are based on a combination of radio noise, corona, and
mechanical sag and strength considerations. See Appendix B for the design criteria used for this
evaluation.
4.2 Interconnection at Source and Delivery Point
Since the interconnection voltage at the Beluga substation is 138 kV or 230 kV, economically using
transformation to either of these two voltages would be a logical choice. The total geothermal
generation out of 70 MW would potentially allow a 69-kV voltage selection for the transmission
system. However, this setup would require two 13-kV/69 -kV transformers at the geothermal
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plant plus two 69-kV/138 -kV or two 69-kV/230 -kV transformers at Beluga substation. Using 69 kV
would also require additional substation equipment and protection schemes and would increase
the costs.
The 138-kV interconnection concept at the Beluga substation is assumed to consist of an A-Frame
take-off structure, a 138-kV circuit breaker, two 138-kV switches, some aluminum bus work with
stands and insulators, additional control wiring, grounding, and relaying. This would be the least
expensive interconnection to the existing substation at Beluga.
Our conclusion is that a 138-kV transmission system with Generator Step-Up (GSU) transformers
at the geothermal site and additional 138-kV switchyard breakers and associated interconnection
equipment at the Beluga substation site is the recommended voltage choice. This approach
simplifies the design and reduces the number of required transformers and costs.
4.3 Conductor Selection
In review of these minimum criteria, a 477-kCMIL ACSR 26/7 Hawk conductor was selected for
the 138-kV transmission voltage and 795-kCMIL ACSR 26/7 Drake conductor for the 230 kV.
Typical weight, rated strength, and ampacity ratings from Southwire for these two conductors are
as follows:
•477 kCMIL Hawk – 0.656 lbs/ft – 19,500 lbs rated – 659 Amps
•795 kCMIL Drake – 1.093 lbs/ft – 31,500 lbs rated – 907 Amps
The transmission of 70 MW will require 292 amps at 138 kV and 176 amps at 230 kV.
Therefore, either of these conductors will be sufficient to transmit the power along the line.
Sag of the conductors and the strength dictate the span length and the pole height to maintain
the required National Electrical Safety Code (NESC) 2023, clearances from an energized conductor
to the ground and/or objects.
4.3.1 Voltage Versus Clearance
Higher voltages would require higher structures to maintain NESC clearances, thus, taller
structures and higher costs. Higher voltages would also result in larger transformers, substation
breakers, switches, and other ancillary substation equipment. Larger transformers are also
heavier, which logistically would cost more to transport them to the remote site. Based on these
simple assumptions and considerations, use of the lower 138-kV voltage versus 230-kV voltage is
economically justified.
4.3.2 Helicopter Construction Constraints
Transmission line construction over Concept A and B routes may require the use of helicopters to
fly in personnel and equipment, due to limited access and environmental restrictions.
The heights and weights of typical structures were reviewed to allow for aerial transport of the
steel monopoles and/or sections of the monopole below approximately 4,000 pounds.
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A medium-sized heavy-lift helicopter, such as a Bell 214 B-1 or Huey type, has a lift capacity over
5,000 pounds and would provide an additional safety factor due to weather, wind, or other
climatic conditions. Other heavy lift sizes are available and may be used by the final line
contractor at their discretion and schedule. Costs for these types of activities are included in this
concept level cost estimate but would be left to the final designer and contractor to propose the
most cost-effective and least environmental impact approach.
4.3.3 Structures
Typical structures for a transmission line are wood or a steel multi-section pole in a single
monopole or in an H-frame configuration. An H-frame would consist of two poles and a crossarm
attached approximately 5-10 feet down from the top of the poles with the conductor attached by
suspension insulators. H-frame structures typically have an optical ground wire (OPGW), and an
overhead ground wire (OHGW) attached at the top of each pole for lightning protection and
communications.
Shown in Figure 2 below is a standard steel monopole-type structure. Wood poles have been used
extensively for years with an average life of 40 years for utilities throughout Alaska and other areas of
the United States. The main issue with wood poles is the weight and available heights. Logistically,
transporting wood poles to a remote site with the required height would be difficult. Steel monopoles
have replaced wood structures over the years with a corresponding life span. These poles are typically
a wood-pole equivalent size and are in two-to-four-piece sections that are 12 sided for strength.
They have a high strength-to-weight ratio that are a slip-fit connection and are jacked together in the
field. Depending on the weight, these could be assembled in a fly yard such as the bottom buried
section along with the next upper section and flown out to the final pole site. The upper section with
the insulators could be flown out and set on the base sections.
Structures are selected for the NESC wind and weight spans, along with standard industry
practice, for the area where the line will be constructed. Based on the wire size, NESC loading,
NESC clearances, and potential helicopter weight constraints, a span length of approximately
600 feet was analyzed which resulted in a structure height of 85 feet with an H4 rating. An 85-
foot H4 pole is a two-section pole with an approximate section weight of 3,035 pounds. The
actual section weights would be designed by a manufacturer, but these would be well within the
helicopter lifting capacity even if the insulators were also attached before the lift.
H-frame type construction was reviewed and in comparison, to the same number of monopole
structures and foundations, the H-frame (Figure 3) would require span lengths of approximately
1,000 feet and a wider ROW. To achieve this span length, 85-foot H-6 steel monopoles weighing
3,950 pounds would be required to maintain clearances. While the 85-foot H-6 monopoles are a
minimum of two sections, each pole would require one lift each. Thus, an H-frame would require
approximately three helicopter lifts per structure (one for each pole plus one for the crossarm).
H-frame construction would also require an additional OHGW. H-frame construction is
achievable, but it would result in additional lifts with the same type of medium-lift helicopter or
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less lifts with a heavy-lift helicopter, such as a Boeing Vertol with twin blades. Additional
construction costs would occur in H-frame construction; but for the purpose of this high-level
study, it was ruled out as being more costly, with potentially more ROW impacts, and
environmental issues.
Using monopole construction (see Figure 2), the conductors would be attached in a Delta
configuration with an optimum phase-to-phase spacing. A braced post, 138-kV polymer insulator
would be used with an acceptable strength to support the conductor under the NESC loading
conditions as well as extreme wind and extreme ice loading for this area (Appendix B).
Figure 2. 138-kV Tangent and Dead-End Structures
For Concept B, two different structure options were reviewed, a steel monopole structure and a
steel H-frame structure. The steel monopole line would have approximately 600-foot spans and
require 396 structures. The H-frame line with 1,000-foot spans would require 222
structures. Each option has advantages and disadvantages. The monopole line would have a
narrower ROW, but involve more site locations with the potential for additional environmental
impacts. The H-frame line would require a wider ROW but involve less sites to be impacted
environmentally. The H-frame line is approximately $3 million more than the monopole line,
which is mainly due to the crossarm costs along with the additional OHGW.
138-kV Dead-end Structure138-kV Tangent Structure
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If winter construction was used on the 41-mile route, fewer structures would result in lower
logistical costs since moving structures on frozen ground could lessen the environmental impact.
If summer construction was used, then it is likely helicopter construction will be required due to
environmental impacts. Therefore, helicopter construction could significantly impact the cost of
construction due to the number of lifts for each structure type. For example, if the monopole
structures could be performed in one lift, then this would be 396 lifts, but for the H-frame, the
222 structures would require three per structure, or 651 lifts.
Figure 3. H-Frame Type Construction
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Angle and dead-end structures would be designed with different insulator attachments along
with anchors and guys to support the loads. Dead-end structures would also be placed along
straight tangent lengths at a designed distance to prevent a cascading failure event.
4.3.4 Fiber Optic Communication and Lightning Protection
On typical transmission lines, a fiber optic line is used for communication for reporting,
protection, and control of the line and substation. This could be either an optical ground wire
(OPGW) that is strung at the top of the pole above the transmission conductors which also serves
as lightning protection, or it could be an all-dielectric self-supporting (ADSS) fiber optic cable that
is attached below the transmission conductors. The incidence of lightning in this project area is
not high, so, further study would need to be performed to select either OPGW or ADSS. From a
protection standpoint, the OPGW would help reduce any transients if a lightning strike did occur.
Standard industry practice in parts of Alaska do use an overhead ground wire. Industry practice
in many areas is to use OPGW for communications in place of an overhead ground wire. ADSS is
typically used on distribution lines with shorter span lengths but have been used on longer span
transmission lines.
4.3.5 Foundations
Transmission line structure foundation requirements vary depending on the soils encountered.
Soil borings would need to be obtained along the selected transmission route to support final
foundation designs. If good soils are encountered, the monopole structures are typically buried
10 percent of the pole height plus 2 feet but may be increased during the design. This would
involve auguring a hole in the ground, setting the pole to the design depth, and backfilling the
hole with good native backfill or non-frost susceptible crushed stone.
If bad soil is encountered that has minimal strength, then other types of foundations may be used.
Concrete foundations have been ruled out due to the remote location. Other types that may be
encountered are vibratory caissons or helical piles with a pole attachment.
Vibratory caissons could be an extension of the 12-sided pole section, driven into the ground to
a certain distance, and the bottom section of the transmission pole designed for a slip-fit
connection. Other caissons used in Alaska are driven H-piles with the pole attached to them, pipe
piles with the poles set inside of the pipe pile, or multiple driven H-piles with a welded pile cap
and the base-plated pole attached to the pile cap.
It is noted that foundation selection may be affected by the transmission line route selected since
Concept A may be near existing or new roads, as compared to Concept B, which is the “cross-
county” remote route requiring winter construction on ice and snow.
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4.3.6 Route Review
A review of the two different routes, based on approximate 600 -foot spans for the steel monopole
configuration and the 1,000-foot H-frame configuration, has resulted in the following quantities
of structures:
Table 3. Quantity of Structures
Concept A - Long
Route
53 Miles
Concept B1 - Direct
Route
41 Miles
Concept B2 –
H-Frame Route
41 Miles
H-Frame StructuresMonopole Structures Monopole Structures
Tangents 479 Tangents 373 Tangents 199
Light Angles 10 Light Angles 5 Light Angles 5
Running
Angles
5 Running
Angles
3 Running
Angles
3
Dead-end 18 Dead-end 15 Dead-end 15
Total 512 Total 396 Total 222
A transmission line is comprised of three different structure types:
•Tangent structures are the most used structures for the transmission line path, which is
mainly straight or with a line angle that is between 0 and 2 degrees. For this arrangement,
a braced post insulator assembly is planned to support the conductor for the tangent
structures. The braced post insulator assembly consists of a horizontal post insulator with
the end of the post supported by a suspension insulator at a 45-degree angle attached to
the pole along with hardware to provide the necessary electrical insulation and strength
for load transfer. The OPGW (shield-wire) is attached near the top of the pole with a
suspension assembly.
•Running angle structures are for changes in the direction of the line angle between 2 and
45 degrees. A suspension insulator assembly is used to support the conductor at an angle
for the running angle structures. The OPGW (shield-wire) is attached near the top of the
pole with a suspension assembly.
•Dead-end structures are designed for full conductor tension loads and the line angle is
between 0 to 90 degrees. They are designed to withstand some unbalanced wire tensions
in one direction of one or all wires on one face of the structure. Dead-end structures are
also used as a stop structure in the event of a cascading event which could prevent the
entire line from failing.
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5.Cost and Financial Study
5.1 Transmission Line Cost Estimate
Construction cost estimates for the two different routes are listed below with the summary and
detail shown in Appendix D.
Table 4. Concepts A & B Transmission Line Monopole Construction Cost Estimates
53-Mile 138-kV Line Route
with Contingency
41-Mile 138- kV Line Route
with Contingency
$61,439,727* $47,881,957*
*Note: See Appendix D and Section 9 for additional cost and financial details.
In Appendix D, all structures have the following unit costs that include manufacture (material,
labor, equipment) and delivery of the structure to site (laydown yard) and is based on the
estimated steel weight.
•Installation cost is the cost to haul, assemble, and install the structure, insulators, and
grounding assemblies. This cost includes access to the structure location and restoration.
•Hardware cost includes material cost for insulator, line hardware, and grounding
assemblies.
•Since soil conditions are unknown, some assumptions have been made which include that
one-third of the foundations will involve a special steel foundation, one-third will involve
boring in rock, and one-third will be direct buried.
5.2 Substation Cost
A new substation at the geothermal plant would need to be built to transform the assumed 13.8-kV
generated power for each 35-MW turbine. A one-line diagram is attached as Appendix J,
Substation One-line Concepts. As stated earlier, two 40/50/60-MVA 13.8/138-kV transformers
would be installed in a parallel configuration allowing operation at a lower output rating,
independently. Metal clad switchgear would be used on the 13.8-kV side which would allow each
turbine unit to run independently or in parallel. A control building to house the relaying, metal
clad switchgear, and battery systems could be built on-site or a prefabricated building, in sections,
could be moved to the site. The estimated cost of this substation is $14,715,247.
The transmission interconnection at the Beluga Power Plant switchyard would be with a single
138-kV breaker addition, and an expansion to the 138-kV bus, ancillary, and control equipment.
It is assumed that the transmission line breaker, relaying, and controls are incorporated into an
existing control building at the CEA Switchyard in Beluga. The estimated cost for this
interconnection is $978,386.
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5.3 Construction and Permitting Schedule
The transmission and substation construction schedules for Concept A and Concept B are similar
activities but differ in duration due to their line lengths. Also, due to the winter construction
activities, which are normally constrained between November and March each year to minimize
the environmental impacts to the transmission line ROW corridor, the longer Concept A may
require longer time depending on winter weather conditions each year. Concept A requires a 2-year
construction window, whereas Concept B, a 12-mile shorter route, requires a 1.5-year
construction window not including permitting or ROW acquisition. Permitting, leasing, and
easement requirements have various time impacts and may be dependent on the connected
actions of the development of the geothermal resource and possible NEPA requirements. Some
of the organizations whose land would be crossed by one or both concepts studied do not have
well-defined or predictable processes for granting ROW leases.
Table 5. Construction and Permitting Schedule
Range of Months
Concept A Transmission Route Construct 24 to 30
Concept B Transmission Route Construct 18 to 20
Transmission ROW Acquisition or Lease
(typical)
24 to 36
Pre-Application Studies 12 to 18
Permitting (except NEPA) 6 to 12
NEPA EA (if applicable) 12 to 24
NEPA EIS (if applicable) 36 to 60
Environmental permits, plan development, and plan implementation cost estimates are provided
in 2024 dollars in Appendix I.
6.Permitting/Licensing Requirements
Federal, state, and local agencies and Native landowner organizations were contacted to confirm
permitting, leasing, and easement requirements for an aerial transmission line on the west side
of Cook Inlet. The agencies and organizations that are involved will depend on the exact route of
the transmission line. For purposes of this discussion, two concepts for the transmission line
were evaluated (see Appendix A):
•Concept A – a 53-mile route from the Beluga substation heading southwest along existing
coastal development then turning northwest up a river valley and finally west to the
geothermal power plant site; and
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•Concept B – a 41-mile direct line route heading due west from the Beluga substation to
the geothermal plant site.
Landowner details are provided in Appendices F and G which indicate Concept B has Mental
Health Trust Authority, Alaska Department of Natural Resources, and Cook Inlet Regional
Corporation as the largest landowners while Concept A has those three as well as Tyonek Native
Corporation, and numerous small agencies and private landowners. Wetlands and anadromous
waterbodies are shown on Appendix E. Both concepts avoid federal and state conservation units
such as parks or refuges.
Federal, state, local, and native agencies or organizations were screened to determine likely
permits or requirements for an aerial transmission line. The Federal and State entities screened
included:
Federal
Bureau of Land Management
Fish & Wildlife Service
National Marine Fisheries Service
National Park Service
US Army Corps of Engineers
National Forest Service
Native
Bureau of Indian Affairs
Cook Inlet Regional, Inc. (CIRI)
Tyonek Native Corporation
Local
Kenai Peninsula Borough and the River
Center
Miscellaneous Private Landowners
State
Alaska Mental Health Trust Authority
Alaska Department of Natural Resources
(ADNR) Division of Mining, Land, and Water
ADNR Office of History & Archaeology and
State Historic Preservation Office
Alaska Department of Fish & Game
Alaska Department of Environmental
Conservation Division of Water, Air Quality,
Food Safety & Sanitation, Solid Waste
Program
Department of Transportation & Public
Facilities
DNR Alaska Park System
University of Alaska
Permitting or approval details for an aerial transmission line are only provided for entities
requiring such permits or approvals and for landowners with property along Concept A or B in
Appendix I.
An important assumption embedded in the permit analysis (Appendix H) is that all cross-country
transmission line construction would be in the winter and without a permanent road consistent
with standard Alaska construction practices. Temporary snow or ice roads would be constructed
to facilitate ROW clearing and transmission line construction. The level of effort for
environmental permitting would be a similar order of magnitude for Concept A and B; however,
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lease and ROW acquisition for Concept A would be much more time-consuming and difficult due
to the numerous small landowners involved.
7.Environmental Screening
Most permits and approvals identified in Appendix H are routine with acceptable environmental
impacts and limited risk of unreasonable permit terms and conditions. The most significant risks
are identified as follows in Sections 7.1 and 7.2.
7.1 Complex National Environmental Policy Act (NEPA) Process
The future construction project, as conceived, will likely trigger a NEPA process due to either
wetlands permitting with the US Army Corps of Engineers or an Endangered Species Act Section 7
consultation with the US Fish & Wildlife Service. However, both wetlands impact and threatened
and endangered (T&E) species issues for an overhead transmission line are expected to be
minimal as long as the future construction project uses winter construction techniques with
temporary snow or ice roads. While NEPA compliance will be required, a simple environmental
assessment (EA) process will likely be used by federal agencies.
However, if a permanent year-round road is constructed to support the project, the
environmental impacts would be much more extensive, and the NEPA process would be much
more complex, likely including preparation of an Environmental Impact Statement (EIS).
Construction of the geothermal power plant would be viewed by federal agencies as a connected
action to the transmission line for NEPA purposes so environmental impacts would be bundled
together into one EA or EIS. If a permanent road is constructed for the power plant, but not
necessarily to support the transmission line, it would still be a connected action for NEPA
purposes.
A permanent road raises a host of issues that are not associated with a transmission line or power
plant construction that would need to be studied in a NEPA process, as follows:
•Permanent damage to tundra, wetlands, and other ground cover,
•River crossings with bridges or culverts disrupting hydrology and fish passage,
•Potential floodplain impacts,
•Careful road placement due to the potential to encounter cultural resource sites or
sensitive T&E species habitat, and
•Opening up virgin territory to road traffic for a variety of new commercial or recreational
uses.
The NEPA process to address a new permanent road would be expensive ($5 to $10 million) and
lengthy (3 to 5 years). It also has the potential to result in expensive mitigation stipulations.
Of note, for the Ambler Access Road on the south side of the Brooks Range, the Biden
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Administration recently denied NEPA approval of the new road into virgin territory reversing a
prior NEPA approval by the Trump Administration.
7.2 Delays in Negotiating ROW Leases
Some of the organizations whose land would be crossed by one or both of the concepts studied
do not have well-defined or predictable processes for granting ROW leases. For instance, the
Mental Health Trust Authority, whose land would need to be crossed under any transmission
route, readily admits that its ROW approval process is slow with a sliding fee scale based on
perceived ability to pay. Similarly, the two native corporations with extensive land holdings in the
area – CIRI and the Tyonek Native Corporation – have processes without clear approval criteria or
defined schedules. The application for a ROW lease becomes a negotiation over terms and
conditions including the lease fee. The same would be true for negotiations with other private
landowners.
8.Financial Modeling and Tax Incentives
The Inflation Reduction Act of 2022 includes a geothermal federal tax credit amount equal to
30 percent of the eligible investment in a qualified geothermal facility, if prevailing wage and
apprenticeship requirements are satisfied (otherwise 6%). To satisfy the prevailing wage
requirement, laborers, mechanics, contractors, and subcontractors must be paid wages at least
at prevailing rates, which are determined by the Secretary of Labor, during the construction,
alteration, and repair of the facility and for 10 years thereafter. To satisfy the apprenticeship
requirement, the percentage of total labor hours for construction, alteration, or repair work on
the qualified renewable generation facility must be performed by qualified apprentices at
12.5 percent in 2023 and 15 percent in 2024 and beyond. There must be one apprentice for each
taxpayer, contractor, or subcontractor that employs four or more individuals to construct, alter,
or repair the renewable generation facility. The credit amount is increased by 10 percent, if
certain domestic content requirements are satisfied. The Inflation Reduction Act also includes
the Energy Community Tax Credit Bonus which allows for up to a 10 percent bonus for certain
investment tax credits for facilities located in energy communities. Increased credit amounts or
rates are available to taxpayers that satisfy certain energy community requirements under
Sections 45, 48, 45Y, or 48E of the Internal Revenue Code.
The Inflation Reduction Act also includes the cost of transmission property when determining the
credit available to a qualified geothermal facility. Qualified interconnection with respect to a
qualified geothermal facility includes any tangible property which is part of an addition,
modification, or upgrade to a transmission or distribution system which is required at or beyond
the point at which the qualified geothermal facility interconnects to the transmission or
distribution system in order to accommodate interconnection, and either is constructed by the
taxpayer or for which the construction cost of the property is paid by the taxpayer.
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In addition to credits under the Inflation Reduction Act, the Internal Revenue Service allows for
certain transmission assets to be depreciated over a 20-year depreciation life, excluding non-
depreciable assets as land. Developers typically monetize the value of depreciation and take
advantage of available tax credits by structuring the project company into a partnership where
the developer is the primary equity investor, and a tax-equity investor is the second partner that
is primarily interested in the tax credits and tax depreciation. The realized value of the monetized
depreciation and credits will vary by eligible costs and negotiated financial terms.
Based on the discussion above, we adjusted the total projected capital cost for the estimated
value of the credits and deprecation. The range of values provided in the table below vary by
whether the domestic content bonus can be obtained, and the range of financial terms
negotiated with the tax equity investor.
Table 6. Adjusted Transmission & Substation Capital Cost
Concept A (53-mile Line)
Low Case High Case
Projected Capital Cost $73,276,692 $73,276,692
Investment Tax Credit Value $36,638,346 $29,310,677
Depreciation Value $6,823,125 $6,732,596
Net Projected Capital Cost $29,815,221 $37,233,419
Notes: Low case assumes 50% credits and 7.50% discount rate; High case assumes 40% credits
and 8.50% discount rate.
Source: www.congress.gov/bill117th-congress/house-bil/5376
Table 7. Adjusted Transmission & Substation Capital Cost
Concept B (41-mile Line)
Low Case High Case
Projected Capital Cost $60,396,806 $60,396,806
Investment Tax Credit Value $30,198,403 $24,158,722
Depreciation Value $5,697,852 $5,618,206
Net Projected Capital Cost $24,500,551 $30,619,878
Notes: Low case assumes 50% credits and 7.50% discount rate; High case assumes 40% credits
and 8.50% discount rate.
Source: www.congress.gov/bill117th-congress/house-bil/5376
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9. Summary of Cost Estimate
WPE developed a model of the expected costs to reflect an owner ’s perspective. In that analysis,
several factors and/or assumptions were included to derive the final transmission line and
substations costs. These include the application of Owner ’s costs prior to construction, electrical
interconnection studies, and start-up personnel, ROW acquisition or permit fees, financial
construction, like interest charges during construction and non-construction costs, and owner
construction, remote access and risk contingencies. See Appendix D for further details on these
cost factors.
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Table 8. Total Transmission Line (Monopole) and Substation Construction Costs
Alignment Concept A - 53 miles Alignment Concept B - 41 Miles
Qty Unit $ or % Extended $ Unit $ or % Extended $
Owner's Cost
Design & Owners Engineering 1 LS 15.0% 7,376,916$ 15.00% 6,204,759$
Permitting & Environemental 1 LS 2,082,771$ 2,082,771$ 1,597,843$ 1,597,843$
Consultants (other & Legal)1 LS 75,000$ 75,000$ 75,000$ 75,000$
Owners Cost Prior to Construction (labor & travel)1 LS 75,000$ 75,000$ 75,000$ 75,000$
Owner's Site CM & Admin (during construction)1 LS 7.00% 3,442,561$ 7.00% 2,895,554$
System Upgrades/Interconnection and Studies (electrical CEA)1 LS 150,000$ 150,000$ 150,000$ 150,000$
Geotechnical 1 LS 397,500$ 397,500$ 307,500$ 307,500$
Owner's Engineer Part Time 4 YRS - 1 Man-Yr 1 LS 180,000$ 180,000$ 180,000$ 180,000$
Owners Start-Up Personnel / 3rd Party Testing 1 LS 50,000$ 50,000$ 50,000$ 50,000$
Working Capital 1 LS 75,000$ 75,000$ 75,000$ 75,000$
Insurance 1 LS 1.50% 737,692$ 1.50% 620,476$
Financial Costs (Includes legal & commitment fees, Independant Engineer)1 LS 0.75% 385,135$ 0.75%323,939$
IDC - 2-Yr at 6%1 LS 3,132,467$ 3,132,467$ 2,634,733$ 2,634,733$
Owner Contingency@5% of Total Construction Cost outside of owner cost.1 LS 2,458,972$ 2,458,972$ 2,068,253$ 2,068,253$
Owner Contingency on Owner Items @5% of Owner cost 1 LS 751,379$ 751,379$ 627,754$ 627,754$
Totall Owner's Cost 21,370,392$ 17,885,811$
Remote Alaska Access Factor1 (Helicopter subcontract)1 LS 5,985,027$ 3,931,561$
Mark-up on Remote Access Helicopter contingency 1 LS 10.0% 598,503$ 10.0% 393,156$
Transmission Line Base Costs (See Appendix D)38,239,596$ 30,425,216$
Substation Base Costs (See Appendix D)10,939,843$ 10,939,843$
Transmission Line Cost (Including Owners costs)61,439,727$ 47,881,957$
Substation Cost (including Owners costs)15,693,633$ 15,693,633$
TOTAl Project Projected Transmission and Substation Costs 77,133,360$ 63,575,590$
(Miles)53.0 41.0
($/Mile)Tx 1,159,240$ Tx 1,167,850$
Note 1 : The remote access takes into account that there will be a higher risk and more helicopter time required to lift structures and personnel into the more remote location Concept B
Appendix A
Topographic Map of Study Area
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D:\D_GIS\Projects\2024 B Mt Spurr\APRX\Mt Spurr Interconnect.aprx
DRAWN BY:
CHECKED BY:
PLOT SCALE:
DATE OF PLOT:
PROJECT NO:
PROJECT:
CLIENT:
SHEET CONTENTS:
FIGURE NO:
1
Topographic Map
of Study Area
Mt Spurr
Interconnection
Feasibility Study
Alaska Electric &
Energy Cooperative
4904-2404
04OCT2024
Barscale
BH/JH
FP
8
8 0 2 4 6 km
0 2 41 mi
N
NAD 1983 UTM ZONE 5N
Map created with ESRI ArcGIS Pro v. 3.3.2
Cook InletSusitna Flats
State Game
Refuge
Trading Bay
State Game
Refuge
Beluga Lake
L
o
w
e
r
B
e
l
u
g
a
L
a
k
e
Matanuska-Susitna Borough
Kenai Peninsula Borough
Legend:8 Geothermal Generation Station
8 Beluga Substation
Mt Spurr
Concept A
Concept B
Mat-Su-Kenai Peninsula Borough Boundary
Trading Bay State Game Refuge
Susitna Flats State Game Refuge
Mt Spurr
Geothermal Generation Station
Beluga Substation
Appendix B
Transmission Design Criteria
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Appendix B
Transmission Design Criteria – Mt. Spurr Geothermal Interconnection Study
Condition Radial
Ice (in) Wind Temp
(°F)
OLF
Transverse
Wind
Loads
OLF
Wire
Tension
Loads
OLF
Vertical
Loads
NESC heavy (NESC Rule 250B) 0.5 4 psf 0 2.50 1.65 1.50
Extreme Wind
(NESC Rule 250C) 0 100
mph 60 1.00 1.00 1.00
Extreme Ice (Assumed) 1.0 0 30 1.00 1.00 1.00
Concurrent Ice and Wind
(NESC Rule 250D) 0.25 60 mph 15 1.00 1.00 1.00
Maximum Operating
Temperature (Conductors) 0 0 212 1.00 1.00 1.00
OLF – overload factor
psf – pounds per square foot
mph – miles per hour
Strength Factors
Components Rule 250B Rule 250C, 250D
Metal and Prestressed-Concrete Structures 1.0 1.0
Wood Structures, Crossarms, and Braces 0.65 0.75
Support Hardware 1.0 1.0
Guy Wire 0.9 0.9
Foundation 1.0 1.0
Ground Clearance
Categories RUS NESC
Vertical – Roads, streets, and other accessible to truck traffic 23.1’ 20.6’
Appendix C
Standard Steel Structures
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GOUND NUT
GROUND SLEEVE
10% POLEHEIGHT+ 2'-0"
GROUND NUT
GROUND LINE
REV DATE DESCRIPTION
A 09/17/24 ISSUED FOR REVIEW
DES CHK APP
MRH BTC DCG
SHEET NUMBER:
SHEET NAME:PROJECT NAME:
PCA1-2401-1201
BRACED POSTTANGENTMT SPURR GEOTHERMAL 138KVTRANSMISSION LINE
ALEUTIAN ARC, ALASKA
REV DATE DESCRIPTION
A 09/17/24 ISSUED FOR REVIEW
DES CHK APP
MRH BTC DCG
SHEET NUMBER:
SHEET NAME:PROJECT NAME:
CONDUCTOR ASSEMBLY
OPGW ASSEMBLY
GROUND NUT
GROUND LINE
GOUND NUT
GROUND SLEEVE
10% POLEHEIGHT+ 2'-0"
PCA1-2401-1203
90° DEADENDMT SPURR GEOTHERMAL 138KVTRANSMISSION LINE
ALEUTIAN ARC, ALASKA
GROUND NUT
GOUND NUT
GROUND SLEEVE
10% POLEHEIGHT+ 2'-0"
GROUND LINE
REV DATE DESCRIPTION
A 09/17/24 ISSUED FOR REVIEW
DES CHK APP
MRH BTC DCG
SHEET NUMBER:
SHEET NAME:PROJECT NAME:
PCA1-2401-1202
RUNNING ANGLEMT SPURR GEOTHERMAL 138KVTRANSMISSION LINE
ALEUTIAN ARC, ALASKA
REV DATE DESCRIPTION
A 09/17/24 ISSUED FOR REVIEW
DES CHK APP
MRH BTC DCG
SHEET NUMBER:
SHEET NAME:PROJECT NAME:
PCA1-2401-1204
H-FRAME TANGENTMT SPURR GEOTHERMAL 138KVTRANSMISSION LINE
ALEUTIAN ARC, ALASKA
Appendix D
Transmission and Substation Cost Estimates
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Alignment Concept A - 53 miles
Qty Unit $ or % Extended $ Unit $ or % Extended $
Owner's Cost
Design & Owners Engineering 1 LS 15.0% 7,376,916$ 15.00% 6,204,759$
Permitting & Environemental 1 LS 2,082,771$ 2,082,771$ 1,597,843$ 1,597,843$
Consultants (other & Legal)1 LS 75,000$ 75,000$ 75,000$ 75,000$
Owners Cost Prior to Construction (labor & travel)1 LS 75,000$ 75,000$ 75,000$ 75,000$
Owner's Site CM & Admin (during construction)1 LS 7.00% 3,442,561$ 7.00% 2,895,554$
System Upgrades/Interconnection and Studies (electrical CEA)1 LS 150,000$ 150,000$ 150,000$ 150,000$
Geotechnical 1 LS 397,500$ 397,500$ 307,500$ 307,500$
Owner's Engineer Part Time 4 YRS - 1 Man-Yr 1 LS 180,000$ 180,000$ 180,000$ 180,000$
Owners Start-Up Personnel / 3rd Party Testing 1 LS 50,000$ 50,000$ 50,000$ 50,000$
Working Capital 1 LS 75,000$ 75,000$ 75,000$ 75,000$
Insurance 1 LS 1.50% 737,692$ 1.50% 620,476$
Financial Costs (Includes legal & commitment fees, Independant Engineer)1 LS 0.75% 385,135$ 0.75% 323,939$
IDC - 2-Yr at 6%1 LS 3,132,467$ 3,132,467$ 2,634,733$ 2,634,733$
Owner Contingency@5% of Total Construction Cost outside of owner cost.1 LS 2,458,972$ 2,458,972$ 2,068,253$ 2,068,253$
Owner Contingency on Owner Items @5% of Owner cost 1 LS 751,379$ 751,379$ 627,754$ 627,754$
Totall Owner's Cost 21,370,392$ 17,885,811$
Remote Alaska Access Factor1 (Helicopter subcontract)1 LS 5,985,027$ 3,931,561$
Mark-up on Remote Access Helicopter contingency 1 LS 10.0% 598,503$ 10.0% 393,156$
Transmission Line Base Costs (See Appendix D)38,239,596$ 30,425,216$
Substation Base Costs (See Appendix D)10,939,843$ 10,939,843$
Transmission Line Cost (Including Owners costs)61,439,727$ 47,881,957$
Substation Cost (including Owners costs)15,693,633$ 15,693,633$
TOTAl Project Projected Transmission and Substation Costs 77,133,360$ 63,575,590$
(Miles)53.0 41.0
($/Mile)Tx 1,159,240$ Tx 1,167,850$
Note 1 : The remote access takes into account that there will be a higher risk and more helicopter time required to lift structures and personnel into the more remote location Concept B
Page D-1
Alignment Concept B - 41 Miles
Appendix D
Total Transmission Line (Monopole) and Substation Consruction Cost
Recapitulation of Sections:LABOR MATERIALS
Group - 1 Wood Pole Units $0.00 $0.00
Group - 1a Steel Pole Units $3,960,000.00 $4,264,155.00
Group - 2 Pole Top Assembly Units $1,461,600.00 $1,208,250.00
Group - 3 Conductor Assembly Units $2,421,545.28 $4,149,676.98
Group - 4 Guy Assembly Units $110,000.00 $38,340.00
Group - 5 Anchor Assembly Units $476,000.00 $204,000.00
Group - 6 Misc. Assembly Units $9,561,248.93 $2,570,400.00
Group - 7 N/A
Total: $17,990,394.21 $12,434,821.98
TOTAL COST:30,425,216.19$
SUMMARY
Mt. Spurr 138kV 41 Mile Route
TRANSMISSION CONSTRUCTION
Recapitulation of Sections:LABOR MATERIALS
Group - 1 Wood Pole Units $0.00 $0.00
Group - 1a Steel Pole Units $5,120,000.00 $5,512,377.50
Group - 2 Pole Top Assembly Units $1,886,400.00 $1,559,250.00
Group - 3 Conductor Assembly Units $3,130,290.24 $5,364,216.58
Group - 4 Guy Assembly Units $145,200.00 $55,080.00
Group - 5 Anchor Assembly Units $609,000.00 $261,000.00
Group - 6 Misc. Assembly Units $11,347,031.38 $3,249,750.00
Group - 7 N/A
Total: $22,237,921.62 $16,001,674.08
TOTAL COST:38,239,595.70$
SUMMARY
Mt. Spurr 138kV 53 Mile Route
TRANSMISSION CONSTRUCTION
Recapitulation of Sections:LABOR MATERIALS
Group - 1 Wood Pole Units $0.00 $0.00
Group - 1a Steel Pole Units $4,520,000.00 $6,075,965.00
Group - 2 Pole Top Assembly Units $696,000.00 $1,318,000.00
Group - 3 Conductor Assembly Units $2,951,921.28 $4,284,803.79
Group - 4 Guy Assembly Units $110,000.00 $38,340.00
Group - 5 Anchor Assembly Units $476,000.00 $204,000.00
Group - 6 Misc. Assembly Units $10,299,613.18 $2,848,800.00
Group - 7 N/A
Total: $19,053,534.46 $14,769,908.79
TOTAL COST:33,823,443.25$
SUMMARY
Mt. Spurr 138kV 41 Mile Route
H-FRAME TRANSMISSION CONSTRUCTION
Description Quantity Per Unit Cost Total Cost
Land Development - Acre 1 50,000.00$ 50,000.00$
138kV Breaker, Fnd, Wiring, Installation 1 76,500.00$ 76,500.00$
138kV CCVT, stands, Fnds, Wiring, Installation (3 qty)1 44,301.00$ 44,301.00$
138kV Disconnect Switches, stands, Fnds, Wiring, Inst.,3 phas 2 47,610.00$ 95,220.00$
Bus Support, bus, and fittings 3 35,000.00$ 105,000.00$
Control Building Additional Relaying 1 75,000.00$ 75,000.00$
Cable, Conduit, Grounding, Fencing 1 30,000.00$ 30,000.00$
138kV A-Frame Structure & Fnds 1 150,000.00$ 150,000.00$
138kV Surge Arrestors 3 2,000.00$ 6,000.00$
Misc.1 50,000.00$ 50,000.00$
682,021.00$
Beluga 138kV Substation UpgradeCost
Appendix D
Description Quantity Per Unit Cost Total Cost
Land Development - Acre 2 50,000.00$ 100,000.00$
40/50/60 MVA Transformer 2 4,000,000.00$ 8,000,000.00$
138kV Breaker, Fnd, Wiring, Installation 2 76,500.00$ 153,000.00$
138kV Breaker, Fnd, Wiring, Installation 2 76,500.00$ 153,000.00$
138kV CCVT, stands, Fnds, Wiring, Installation (3 qty)2 44,301.00$ 88,602.00$
138kV Disconnect Switches, stands, Fnds, Wiring, Inst.,3 phas 2 47,610.00$ 95,220.00$
13.8kV Metal Clad Switchgear 1 450,000.00$ 450,000.00$
Control Building 1 500,000.00$ 500,000.00$
Cable, Conduit, Grounding, Fencing 1 100,000.00$ 100,000.00$
Transformer Concrete Foundations 2 100,000.00$ 200,000.00$
138kV A-Frame Structure & Fnds 1 150,000.00$ 150,000.00$
138kV Surge Arrestors 9 2,000.00$ 18,000.00$
Transformer Oil Containment 2 100,000.00$ 200,000.00$
Misc.1 50,000.00$ 50,000.00$
$ 10,257,822.00
Mt. Spurr 138kV Substation Cost (Rev 1)
Appendix D
Appendix E
Water Bodies - Wetlands
Mt. Spurr Geothermal Interconnection
Feasibility Study
www.westpeakenergy.net
“Experience You Can Trust”
D:\D_GIS\Projects\2024 B Mt Spurr\APRX\Mt Spurr Interconnect.aprx
DRAWN BY:
CHECKED BY:
PLOT SCALE:
DATE OF PLOT:
PROJECT NO:
PROJECT:
CLIENT:
SHEET CONTENTS:
FIGURE NO:
4
Waterbodies
and Wetlands
Mt Spurr
Interconnection
Feasibility Study
4904-2404
04OCT2024
Barscale
BH/JH
FP
8
8
0 2 4 6 km
0 2 41 mi
N
NAD 1983 UTM ZONE 5N
Map created with ESRI ArcGIS Pro v. 3.3.2
Mt Spurr
Low
e
rBel
u
g
a
L
a
k
e
Cook Inlet
Alaska Electric &
Energy Cooperative
Legend:
8 Geothermal Generation Station
8 Beluga Substation
Mt Spurr
Concept A
Concept B
Anadromous Streams
Streams
National Wetland Inventory
Estuarine and Marine Wetland
Freshwater Emergent Wetland
Freshwater Forested/Shrub Wetland
Freshwater Pond
Lake
Appendix F
Land Ownership in Study Area
Mt. Spurr Geothermal Interconnection
Feasibility Study
www.westpeakenergy.net
“Experience You Can Trust”
D:\D_GIS\Projects\2024 B Mt Spurr\APRX\Mt Spurr Interconnect.aprx
DRAWN BY:
CHECKED BY:
PLOT SCALE:
DATE OF PLOT:
PROJECT NO:
PROJECT:
CLIENT:
SHEET CONTENTS:
FIGURE NO:
2
Land Ownership
in Study Area
Mt Spurr
Interconnection
Feasibility Study
4904-2404
04OCT2024
Barscale
BH/JH
FP
8
8
0 2 4 6 km
0 2 41 mi
N
NAD 1983 UTM ZONE 5N
Map created with ESRI ArcGIS Pro v. 3.3.2
Cook InletMt Spurr
Alaska Electric &
Energy Cooperative
Legend:
8 Geothermal Generation Station
8 Beluga Substation
Mt Spurr
Concept A
Concept B
Land Ownership in the Study Area
ADNR
BIA
BLM
CIRI
Chugach Electric
KPB
Mental Health Trust
Other Private
Tyonek Native Corp
Appendix G
Land Ownership in Eastern Study Area
Mt. Spurr Geothermal Interconnection
Feasibility Study
www.westpeakenergy.net
“Experience You Can Trust”
D:\D_GIS\Projects\2024 B Mt Spurr\APRX\Mt Spurr Interconnect.aprx
DRAWN BY:
CHECKED BY:
PLOT SCALE:
DATE OF PLOT:
PROJECT NO:
PROJECT:
CLIENT:
SHEET CONTENTS:
FIGURE NO:
3
Land Ownership
Eastern Study Area
Detail
Mt Spurr
Interconnection
Feasibility Study
4904-2404
04OCT2024
Barscale
BH/JH
FP
8
0 1 2 3 km
0 0.5 1 1.5 mi
N
NAD 1983 UTM ZONE 5N
Map created with ESRI ArcGIS Pro v. 3.3.2Cook InletAlaska Electric &
Energy Cooperative
Legend:
8 Geothermal Generation Station
8 Beluga Substation
Mt Spurr
Concept A
Concept B
Land Ownership in the Study Area
ADNR
BIA
BLM
CIRI
Chugach Electric
KPB
Mental Health Trust
Other Private
Tyonek Native Corp
Appendix H
Potential Permits and Fees
Mt. Spurr Geothermal Interconnection
Feasibility Study
www.westpeakenergy.net
“Experience You Can Trust”
Table H-1: Potential Permits and Fees
Mt. Spurr Geothermal Interconnection Feasibility Study
Alaska Electric and Energy Cooperative
Agency Department/Permit Applicability
Concept Includes?
(Yes/No/
Maybe)
Environmental Field
Activity Required?
(Yes/No/ Maybe)
Contact Info Permit Application Typical Time for Review/Decision Fee
STATE
Alaska Mental Health Trust
Authority (ADNR)
Trust Land Office
Land Use Application
If located on Mental Health Trust land, or access
through Mental Health Trust land is needed.
Easement, Lease options
Both Concepts cross Mental Health Land so
require an Easement. A Lease would be required
if additional land is needed to support the
transmission line.
Y N
Pete Mueller, Easements Manager:
pete.mueller@alaska.gov
907-269-8737
-Trust Land Office Land Use Application,
online entry only at
https://alaskamentalhealthtrust.org/trust-land-
office/land-sales/land-use-application/
6 to 12 months:
1 month - application review
1 to 3 months - consultation, public
notice, BID affirmed
1 to 3 months - legal description,
stipulations, annual rate
1 to 3 months - signed contract, bond,
insurance, 1st payment, as-built survey
1 month - audit for completeness, TLO
Executive Director signs
1 month - official record, certified copy
Application fee:
$500
Annual fee:
$1 to $5/lf of transmission line on Trust
Land
Division of Mining, Land, and Water: Land Section
Easement
If located on State land, or access through State
land is needed.
Both Concepts cross ADNR Land, and therefore
require an Easement.
Y N
EASEMENT:
-Easement Application form, and
-Written Development Plan with map, and
-Environmental Risk Questionnaire
Easement: 6-8 months
Application fee:
$480 for <= 1 acre
$1,200 for >1 acre
Land Use Authorization:
Public easement: $120/acre or $0.56/lf
Final Easement: One-time fee based on
as-built survey of use area.
Division of Mining, Land, and Water: Land Section
Lease
If State land will be used for commercial,
industrial, agricultural, grazing or private use.
A Lease would be required if additional ADNR
land is needed to support the transmission line
(e.g., substations, helicopter landing pad,
support buildings, etc.).
M N
LEASE:
-Lease Application, and
-Development Plan, and
-Environmental Risk Questionnaire
Lease: 9-12 months
Project specific: Agency review of
development plan and performance of a
title search. Author Preliminary Decision,
with a 30-day public notice for comments.
Final Finding and Decision, then a 20-day
appeal period. If no appeals are received,
the Final Finding and Decision becomes
effective on the 31st day after issuance.
Fee includes:
-Application fee based on number of
acres of requested lease area.
-Annual rental fee.
-May also require a survey, appraisal,
insurance, and bonding.
Division of Mining, Land, and Water: Land Section
Permit
If located on State land
A Limited Material Sale Contract may be
required if material (gravel) borrow pits are
needed.
Y N
PERMIT OPTIONS:
-Land Use Permit (LUP) plus map and
supporting info - use for up to 5 years
-Limited Material Sale Contracts (200 cy of
stone, gravel, sand, other aggregates)
Permit: Up to 30 days
LUP: 14-day public and agency notice Determined after application, based on
proposed use.
Division of Mining, Land, and Water: Land Section
Land Use Permit with Supplemental Form (Heavy
Vehicle Use)
Off-road vehicle travel across state land
A Cross-Country travel permit is required for
roadless construction.
Off-road heavy vehicle travel permit is also
required for roadless construction.
Y N
PERMIT FOR TRAVEL:
-Authorization required for heavy equipment
under Land Use Permit with Supplemental
Forms
-Cross-country travel permit for light vehicle
travel across ADNR land with no installation of
transmission poles.
Permit: Target is 30 days unless subject to
14-day agency review and public notice $400
Division of Mining, Land, and Water: Land Section
Generally Allowed Use
Generally Allowed Use: Activities allowed on State
land without a permit, lease, or easement. Many
activities included; most applicable to project
work is brushing or cutting a survey line.
Advanced surveying is allowed without a permit
as long as the survey line is <5 ft wide.
Y N
-No permit required for brushing or cutting a
survey line <5 ft wide using only hand tools
(includes chainsaw).
-If setting a survey monument (permanent,
official marker), written survey instructions
must be issued by DMLW.
N/A N/A
Southcentral - Anchorage: dnr.pic@alaska.gov,
907-269-8400Alaska Department of Natural
Resources (ADNR)
September 2024 Table H-1 Page 1
Table H-1: Potential Permits and Fees
Mt. Spurr Geothermal Interconnection Feasibility Study
Alaska Electric and Energy Cooperative
Agency Department/Permit Applicability
Concept Includes?
(Yes/No/
Maybe)
Environmental Field
Activity Required?
(Yes/No/ Maybe)
Contact Info Permit Application Typical Time for Review/Decision Fee
Division of Mining, Land, and Water: Water
Resources
-Consumptive use of 5,000 gallons/day or more
from a single source in a single day;
-Regular/recurring consumptive daily use of 500
gpd from single source for >10 days/year;
-Non-consumptive use of >30,000 gpd from a
single source; or
- Any water use that may adversely affect water
rights of other appropriators or the public interest.
Project is assumed to not require large
quantities of water.
N N
Anchorage: 907-269-8505
dnr.twua@alaska.gov
-Temporary Water Use Authorization (signed
application form) with detailed project
description, legible map, habitat permit (if
applicable), well logs (if applicable) and
bathymetry or other source volume or flow rate
data, if applicable and available
60 days $450
State Historic Preservation Office
Concurrence
For land disturbances on federal or state lands or
project funding is provided by federal or state
entities
Desktop study required to determine if known
cultural sites have been identified along the
project route.
Y N
DNR Public information office: 907-269-8721
OHA Review and Compliance Coordinator: 907-
269-8720
-Concurrence form (State lands - under Alaska
Historic Preservation Act, Federal lands -
Section 106 Concurrence)
Target is 30 calendar days after receipt;
After 90 days, may apply to governor for
permission to proceed without
concurrence
None
Office of History & Archaeology
State Cultural Resource Investigation Permit
State Cultural Resource Investigation Permit
(SCRIP): if cultural resource monitoring or surveys
needed on state lands.
SHPO evaluates desktop study and determines
if a full or limited field study is required.
M Y
Alaska Heritage Resources Survey:
oha.ibs@alaska.gov
SCRIP: oha.permits@alaska.gov, 907-269-8728
-SCRIP Application
-Final Report to State Archaeologist
-Alaska Heritage Resources Survey (AHRS)
records
-Application review: Minimum 30 calendar
days after receipt but dependent on
response time of land managers
-Final report submitted within 6 months
of completion of fieldwork
-AHRS records for new sites and
reinvestigated sites must be submitted to
OHA
None
Alaska Department of Fish & Game
Habitat Section
Permit
Authorization
-Project is within or will cross state game refuge,
critical habitat area or a wildlife sanctuary, or
includes a stream crossing.
-Project potentially impacts federal or state
threatened or endangered species
ADF&G Habitat Permit is required regardless of
time of construction. A winter construction
project is less onerous.
Y N
Soldotna (KPB): dfg.hab.infosxq@alaska.gov,
907-714-2475
Wayne.Haimes@alaska.gov
-Habitat permit
-Authorization for Stream Crossing
-Authorization for travel through state refuge,
sanctuary, or critical habitat
30 days Typically No charge
Alaska Department of
Environmental Conservation
(ADEC)
Division of Water
Construction Stormwater General Permit
Section 401 Certification
-Plan to divert, dewater, impound, withdraw or
use any fresh water
-Construction activity meets requirements for
stormwater GP
A CSGP will be required for ROW clearing.
Y Y Division of Water, DEC: 907-269-6285
Online application through EDMS, requires an
account:
-Notice of Intent (NOI) for Construction
Stormwater General Permit (GP) if >1 acre
disturbed
-Section 401 Certification (in conjunction with
Section 404 permit - DEC determines if 401
certification is required)
-File NOI for Construction GP at least 14
days prior to commencing construction
activity
-Construction General stormwater
permit: $580
- One-time "dredge or fill" permit;
Section 401 certification:
Waiver of certification: $130
Disturbing < 1 ac: $600
Disturbing 1 to 5 ac: $765
Disturbing 5.01 to 20 ac: $1,160
Disturbing > 20 ac: $2,375
ADNR
September 2024 Table H-1 Page 2
Table H-1: Potential Permits and Fees
Mt. Spurr Geothermal Interconnection Feasibility Study
Alaska Electric and Energy Cooperative
Agency Department/Permit Applicability
Concept Includes?
(Yes/No/
Maybe)
Environmental Field
Activity Required?
(Yes/No/ Maybe)
Contact Info Permit Application Typical Time for Review/Decision Fee
Division of Food Safety & Sanitation
Small Camp Authorization
Large Camp Permit, Plan Review & Authorization
Small Camp Authorization: 24 or fewer people at
same remote location for 14 days or more
Large Camp Permit: Plan Review and
Authorization required for 25 or more people
Project construction is assumed to require a
single camp with capacity of 24 or fewer people
for less than 14 days at a given location. Thus,
no permit or authorization required.
N N
Small Camp Authorization
dec.fsspermit@alaska.gov, 907-269-6289
Large Camp Permit
Drinking Water :
anchorage.dw.engineering@alaska.gov,
Food Service: Noelani Thompson, 907-334-5919
Solid Waste (see Division of Environmental
Health, Solid Waste Program entry)
Wastewater: Tonya Bear, 907-451-2177
-Small Camp Authorization: Online form entry
-Large Camp Permit:
Drinking Water : Application including
applicable components for Water Storage or
Water Haul Vehicle.
Food Service: FF-4 Labor Camp Food Service
permit, including Hazard Analysis Critical
Control Point (HACCP) plan.
Solid Waste (see Remote Camp Solid Waste
below)
Wastewater: Permit to Construct and Permit to
Operate
Small Camp: Annual authorization;
Expires Dec 31 each year.
Large Camp:
Drinking Water - minimum 30 day review
for construction approval
Food Service -
Solid Waste - not provided
Wastewater -
Small Camp - Annual fee of $250 + $30
wastewater fee
Large Camp -
Drinking Water : Plan Review fee: $675
Food Service : Plan Review fee:
Equivalent to Annual fee amount.
Annual fee: $400 to $580. HAACP Plan:
Annual fee of $125 and review fee of
$125
Solid Waste : See entry below.
Wastewater : Design Review fee:
$3,320. Annual fee: $765.
Division of Environmental Health, Solid Waste
Program
General Permit: Remote Camps
Remote camp that does not haul solid waste
offsite and wants to leave it buried at end of
activity
Solid waste is assumed to be backhauled to a
permitted landfill.
N N
Southcentral + Western, Kaylie Holland, Regional
Manager: 907-269-7622
GP for Remote Camps with <50 Residents
(requires monthly monitoring, annual report
and closure report)Not provided
GP for Remote Camps: Application:
$115, Annual fee: $115
Division of Air Quality
Land Clearing/Open Burn Permit
Construction Project Information Form
Construction Project Permit
Minor Permit
-Open burn of <40 acres woody debris
- An Air Quality Construction Permit is required
for certain sources.
This project will not meet the criteria for an air
quality construction permit. If ROW clearing
material is open burned, an Open Burn permit is
required.
M N
Open Burns:
Ross Douglas, Juneau, 907-465-5103
Enhanced Smoke Management Plan: Morgan
Frank, Anchorage, 907-269-4913
-Land Clearing Application
Not provided Open Burn: $387
Alaska Department of
Transportation & Public Facilities Right-of-way Permit
If operating within DOT&PF rights-of-way (ROW).
No DOT ROW has been identified in the study
area.
N N
Central Region: cynthia.ferguson@alaska.gov,
907-269-0693
ONLINE only at
https://dot.alaska.gov/row/Login.po
Application for Utility Permit on State ROW
form 25D-261 + specific utility form(s) + Plan
sheets + Letters of non-objection + Other
regional forms
-Major Utility Permit (new aerial utility lines
requiring poles or >200 lf)
-Minor Utility Permit (aerial lines not requiring
poles in ROW and <200 lf; underground lines
outside roadway prism not requiring pedestal,
manhole or structure and <200 lf)
Varies, depending on project complexity.
Steps required:
-Application and review;
-Application approval;
-Construction authorization and utility
installation:
-Inspection, certification, and surety
release.
Major Permit: $600 + $1/lf over 200 ft
Minor Permit: $100
Bonds/Sureties may also be required.
Alaska State Park System
Division of Parks & Outdoor Recreation
Access Fee
Special Use Permit for motorized access
to/across State Park Lands.
No parklands will be crossed in the study area.
N N Parkpermitting@alaska.gov
Director's office: 907-269-8700
-Online application only:
https://form.jotform.com/240076605420043
30 days
Application fee - $100
Access fee (thru park land to non-state
owned/controlled land) - $100/yr
Utilities, telecom, other non-
recreational structures - Fee based on
fair market value
University of Alaska
UA Land Management
Land Use Application
If located on University land, or access through
University land is needed.
No University lands have been identified in the
study area.
N N
Anchorage: 907-786-7766
Fairbanks: 907-450-8133
-Land Use Application (access or easements)
Not provided Application fee - $500
Permit fee - TBD based on proposed use
ADEC
September 2024 Table H-1 Page 3
Table H-1: Potential Permits and Fees
Mt. Spurr Geothermal Interconnection Feasibility Study
Alaska Electric and Energy Cooperative
Agency Department/Permit Applicability
Concept Includes?
(Yes/No/
Maybe)
Environmental Field
Activity Required?
(Yes/No/ Maybe)
Contact Info Permit Application Typical Time for Review/Decision Fee
FEDERAL
Bureau of Land Management
Land Use Permit/ROW Lease
If disturbance is proposed on federally owned
lands
If BLM land is crossed, a Land Use Permit (ROW
Lease) will be required.
M M
Anchorage Field Office: 907-267-1246
Glennallen Field Office: 907-822-3217
Fairbanks/Arctic District Office: 907-474-2200
-Land Use Permit
-ROW Lease
Application fee: $1,500
One-time fee of $0.70/lf
National Park Service
Permit
When working on or requesting access to National
Park Service land
There is no NPS Land in the study area.
N N File permit request online at
https://irma.nps.gov/RPRS/
Fish & Wildlife Services
Section 7 Consultation
Special Use Permit
-If work includes areas with known Threatened
and Endangered Species
-Access to National Wildlife Refuge lands
There are no National Wildlife Refuge lands in
the study area. A Threatened and Endangered
Species screening will likely be required
potentially triggering NEPA evaluation.
M Y Kenai Fish and Wildlife Conservation Office:
907-262-9863
-Endangered Species Act Section 7
Consultation
-Special Use Permit - General Activities on
National Wildlife Refuge land Not provided. Request specific project
area review via iPaC to determine
applicability of endangered species
No fee for initial determination of
endangered species in project area.
US Department of Defense
Corps of Engineers
NEPA Evaluation
Section 404 Permit (wetlands)
Section 10 Permit (dredge & fill, bridges)
Work within Rivers, Streams, Lakes, Ponds and
associated fresh water wetlands
Section 10 permit not required. Section 404
likely required, including NEPA Evaluation.
M M On west side of Kenai Peninsula: Kenai
Regulatory Field Office, 907-283-3519
-NEPA Review: If work disturbs >5 acres of
wetlands
-Section 404: Discharge of dredge or fill
material within fresh water wetlands or rivers,
streams, lakes, ponds
-Section 10: All structures or work within
navigable waters of the US.
US Department of Commerce
National Marine Fisheries Service or NOAA
Fisheries
Authorization
If actions potentially impact wildlife including
whales, dolphins and porpoises, seals and seal
lions, federal fisheries, essential fish habitat,
habitat areas of particular concern and most
marine species listed as threatened/endangered.
Project is onshore so an NMFS authorization is
not required.
N N Alaska Marine Mammals Management Office:
800-362-5148
Marine Mammal Protection Act Authorization
Not provided. Most requests are related to
Incidental Takes of marine mammals. Not provided.
United States Environmental
Protection Agency (EPA)
Spill Prevention, Control and Countermeasure
Plan (SPCC)
Self-implementing
If at least 1,320 gallons of fuel or oil will be stored
onsite in 55-gallon or greater containers
The Project Camp will likely require fuel storage
for power generation, heating, and mobile fleet
support. Assuming <10,000 gallons of storage
will be onsite, a Self-Certified SPCC Plan would
be needed.
Y N
https://www.epa.gov/oil-spills-prevention-and-
preparedness-regulations/spill-prevention-
control-and-countermeasure-19
Self-Certified SPCC Plan
Not applicable.
Submittal to EPA is not required. Cost is
limited to development of the SPCC
Plan.
US Department of Agriculture
United States Forest Service
Special Use Authorization
If work will occupy, use, or build on National
Forest land (temporary or long-term), if there is a
fee being charged for the use, if activity involves
75 or more participants, or if an easement or
lease is needed.
There are no USFS lands in the study area.
N N
-Contact the Forest Service Office where access
is needed for the application.
-Arrange a preapplication meeting with the local
staff.
Special Use Authorization
Not provided
Cost Recovery Fee - agency processing
costs
Land Use Fee - based on fair market
value
US Department of Interior
September 2024
Table H-1 Page 4
Table H-1: Potential Permits and Fees
Mt. Spurr Geothermal Interconnection Feasibility Study
Alaska Electric and Energy Cooperative
Agency Department/Permit Applicability
Concept Includes?
(Yes/No/
Maybe)
Environmental Field
Activity Required?
(Yes/No/ Maybe)
Contact Info Permit Application Typical Time for Review/Decision Fee
NATIVE
Bureau of Indian Affairs (BIA)
Alaska Region Environmental Program
ROW Lease
NEPA Review
Access to BIA land
If BIA Lands are crossed, a ROW Lease with
NEPA Review is required.
M N 907-271-4004
-Categorical Exclusion request
-Environmental Assessment to determine if
Environmental Impact Statement is required or
a Finding of No Significant Impact
Application fee: $1,500
One-time fee of $0.70/lf Not provided
Cook Inlet Region, Inc. (CIRI)
CIRI Land and Resources Department
Written request to evaluate land access (for ROW
Lease)
Any use of land or access across CIRI lands
Both Concepts cross CIRI Land so a written
request to access land is required.
Y N
907-263-5140
permitting@ciri.com
-No formal application. Request must be in
writing.
-Provide maps showing where access is
needed, including .kmz or .shp files.
-Identify the authorized person including title,
mailing address, contact info.
-Administrative fee must be paid for initial
review of materials.
-Additional access fees to be determined
based on project.
-Insurance must list CIRI as additionally
insured for $1,000,000 injury/death and
$2,000,000 fire.
Not provided.
-$800 initial review of request
-Additional fees charged for activity (no
scale/guide provided).
Tyonek Native Corporation (TNC)
TNC Lands Department
Land Access Application (for ROW Lease)
Any use of land or access across Tyonek Native
Village lands
Concept A crosses Tyonek Land so a written
request to access land is required.
Y N
907-272-0707
lands@tyonek.com
-Application for Land Access
-Legal description of parcels
-Operations Plan
-Insurance naming Tyonek Native Corporation
as additionally insured.
Not provided. -Fees charged depend on activity (no
scale or guide provided).
LOCAL GOVERNMENT
Land Management Division
Easement
Individual Construction Project Permit
For access to or construction of utilities upon KPB
land
Concept A crosses KPB Land so an Easement
with Individual Construction Project Permit is
required.
Y N 907-714-2205
lmweb@kpb.us
-Easement application
-Application for Individual Construction
Project Permit + Proposed plans, traffic routine
narrative statement
-30 days is typical
-90 to 180 days for large project or
request
Application fees:
Easement: $500
Individual Construction Project Permit:
$50 + $0.10/ft after first 200 ft
Annual fees:
Easement: Fair market value
The River Center
ADNR Office of State Parks Conditional Use
Permits
ADF&G Habitat Division Permits
KPB 50-ft Habitat Protection Area, Floodplain
Development and Coastal Zone Management
Permit
Coordinates permitting with USACE and USFWS.
Activity within 50 ft of an anadromous water body
or within a floodplain
Consultation with the River Center will be
required to minimize impacts to anadromous
water bodies and floodplains.
Y M After receiving permit, must contact River Center
3 days prior to construction
-KPB Habitat/Floodplain
-KPB Conditional Use Permit
-KPB Floodway Development -30 days is typical for Habitat permit
-Floodplain Development permit and
Conditional Use permits may require
additional time
Habitat/Floodplain: $50
Conditional Use: $300
Floodway Development: $300
PRIVATE
Multiple private lands owners Individual landowner easement agreements
Concept A may require case-by-case
consultation with each private landowner to
cross private property.
M N
Kenai Peninsula Borough
September 2024 Table H-1 Page 5
Appendix I
Cost Estimates - Permitting
Mt. Spurr Geothermal Interconnection
Feasibility Study
www.westpeakenergy.net
“Experience You Can Trust”
Table I-1: Ballpark Cost Estimate for Known Fees
Mt. Spurr Geothermal Interconnection Feasibility Study
Alaska Electric and Energy Cooperative
Landowner Authorization type
Concept A
Linear Feet of
Transmission Line
or Unit Count
Concept B
Linear Feet of
Transmission Line
or Unit Count
Unit Cost Concept A
Estimated Cost
Concept B
Estimated
Cost
Easement - Application Prep 1 1 $10,000 $10,000 $10,000
Easement - Application Fee 1 1 $500 $500 $500
Easement - Annual fee 25,143 92,494 Up to $5/LF $125,715 $462,470
Easement - Application Prep 1 1 $10,000 $10,000 $10,000
Easement - Application Fee 1 1 $1,200 $1,200 $1,200
Easement - Annual fee 1 49,197 54,369 $0.56/LF $27,550 $30,447
Final Easement fee 1 49,197 54,369 $0.56/LF $27,550 $30,447
Material Sales Contract 2 200 200 Assume $75/cy $15,000 $15,000
Heavy Equipment Travel Permit 1 1 $400 $400 $400
Cross-Country Travel Permit 1 1 $400 $400 $400
Easement - Application Prep 1 1 $10,000 $10,000 $10,000
Easement - Application Fee 1 1 $1,200 $1,200 $1,200
Right-of-Way Fee (one-time)4,036 0 $0.70/LF $2,825 $0
Easement - Application Prep 1 1 $10,000 $10,000 $10,000
Easement - Application Fee 1 1 $1,200 $1,200 $1,200
Right-of-Way Fee (one-time)2,803 0 $0.70/LF $1,962 $0
CIRI Access - Application Prep 1 1 $10,000 $10,000 $10,000
CIRI Access - Application Fee 1 1 $800 $10,000 $800
CIRI Access 18,476 67,290 Assume $5/LF $92,380 $336,450
Tyonek Native Corporation (TNC) Application Prep 1 0 $10,000 $10,000 $0
Tyonek Native Corp Access Application 134,552 0 Assume $5/LF $672,760 $0
KPB - Application prep 1 1 $10,000 $10,000 $10,000
KPB Land Management - Easement fee 1 0 $500 $500 $0
KPB Land Management - Permit for use 42,682 0
$50 + $0.1/lf after first
200 ft $4,298 $0
Kenai River Center
Assume 15 River
Crossings
Assume 15 River
Crossings $50 $750 $750
BIA
BLM
Mental Health Trust
Authority
KPB Lands
ADNR-DMLW
Native Lands
September 2024 Table I-1Page 1
Table I-1: Ballpark Cost Estimate for Known Fees
Mt. Spurr Geothermal Interconnection Feasibility Study
Alaska Electric and Energy Cooperative
Landowner Authorization type
Concept A
Linear Feet of
Transmission Line
or Unit Count
Concept B
Linear Feet of
Transmission Line
or Unit Count
Unit Cost Concept A
Estimated Cost
Concept B
Estimated
Cost
Construction General Permit 1 1 $580 $580 $580
Wetlands Desktop Review 1 1 $20,000 $20,000 $20,000
SWPPP - cost to develop Construction SWPPP 1 1 $10,000 $10,000 $10,000
SPCC Plan - cost to develop self-certified plan 1 1 $8,000 $8,000 $8,000
Field Implementation - SWPPP + SPCC 3 72 36 $10,000 per wk $720,000 $360,000
Cultural/Archaeological Desktop Review 1 1 $20,000 $20,000 $20,000
Cultural/Archaeology Field Survey + SCRIP permit 4 12 12 $6,000 per wk $72,000 $72,000
Threatened & Endangered (T&E) Species Desktop Review 1 1 $20,000 $20,000 $20,000
T&E Species Field Survey 4 12 12 $6,000 per wk $72,000 $72,000
Helicopter Fees for Cultural + T&E Surveys 4 60 60 $1400 per day $84,000 $84,000
cy: cubic yards Estimated Total Cost 5 $2,082,771 $1,597,843
LF: linear foot
2 Maximum of 200 cy of stone, other aggregate allowed for pad construction
3 Field implementation is assumed to require 12-hour days, 7 days/week for the project duration identified for Concepts A and B.
4 Cultural and T&E species surveys are assumed to require 12-hour days, 5 days/wk for 12 weeks, regardless of Concept, and will occur simultaneously to reduce helicopter fees.
5 Contingency not included
1 ADNR Annual fee is based on estimated length of transmission line and charged annually until the final survey is submitted. Final Easement Fee is a one-time charge based on the
length of transmission line identified in the final recorded survey.
Other Environmental
permits and plans
September 2024 Table I-1 Page 2
Appendix J
Substation One-Line Concepts
Mt. Spurr Geothermal Interconnection
Feasibility Study
www.westpeakenergy.net
“Experience You Can Trust”
REV DATE DESCRIPTION
A 09/17/24 ISSUED FOR REVIEW
DES CHK APP
MRH BTC DCG
SHEET NUMBER:
SHEET NAME:PROJECT NAME:
PCA1-2401-1500
ONE LINE DIAGRAMMT SPURR GEOTHERMAL 138KVTRANSMISSION LINE
ALEUTIAN ARC, ALASKA
G G
AUX LOADS
35MW
GEOTHERMAL
TURBINE
35MW
GEOTHERMAL
TURBINE
N.O.
13.8 KVBREAKER
(TYPICAL)
138 KV
BREAKER
138 KV
BREAKER
13.8 KVSWITCH
13.8 KVMETAL
CLAD
40/50/60 MVA
138/13.8 KV
AUX LOADS
13.8 KVSWITCH
40/50/60 MVA
138/13.8 KV
CCVT
138 KV
SWITCH
CCVT
138 KV
SWITCH
138 KV TRANSMISSION LINE
TO BELUGA SUBSTATION
Appendix J
REV DATE DESCRIPTION
A 10/15/24 ISSUED FOR REVIEW
DES CHK APP
MRH BTC
SHEET NUMBER:
SHEET NAME:PROJECT NAME:
PCA1-2401-1501
ONE LINE DIAGRAMMT SPURR GEOTHERMAL 138KVTRANSMISSION LINE
ALEUTIAN ARC, ALASKA
NO. 7
726
48/64/80
725
60.1 MW
NO. 8
826
48/64/80
825
60.1 MW
025
STA. SVC
712
715
812
815
012
015
MT. SPURR 138KV LINE SWITCH
MT. SPURR 138KV LINE SWITCH
MT. SPURR 138KV BREAKER
MT. SPURR 138KV LINE
41 OR 53 MILE LINE
POSSIBLE MT. SPURR CONNECTION
WOULD BE ON THE 138KV BUS SECTION
BETWEEN BREAKERS 712 AND 812
PARTIAL ONE LINE OF BELUGA SUBSTATION
CCVT
MT. SPURR
CONNECTION