HomeMy WebLinkAboutNenana River Hydropower Scheme Reconnaissance Study 2009Golden Valley Electric Association
Nenana River Hydropower Scheme
Healy, Alaska
onnaissance Study
Knight Piesold
CONSULTING
Rev. No.
Rev A
RevB
RevC
RevO
Golden Valley Electric Association
Nenana River Hydropower Scheme
Reconnaissance Study
Healy, Alaska
Final Report
January 7, 2009
Prepared for
Golden Valley Electric Association
P.O. Box 71249
Fairbanks, Alaska 99207
Telephone: (907) 452-1151
Date
12/01/08
12/18/08
12/22/08
01/07/09
Telefax: (907) 451-5657
Prepared by
Knight Piesold and Co.
1580 Lincoln Street, Suite 1000
Denver, Colorado 80203
Telephone: (303) 629-8788
Telefax: (303) 629-8789
Project DV103-00209.01
Description Knight Piesold
For Internal Review John Dwyer
Issued for Review/Approval John Dwyer
Issued for Review/Approval John Dwyer
Issued as Final John Dwyer
Client
Paul Park
Paul Park
Paul Park
Paul Park
Knight Piesold
CONSULTING
Golden Valley Electric Association
Nenana River Hydropower Scheme
Healy, Alaska
Reconnaissance Study
Final Report
Table of Contents
List of Figures ................................................................................................................................ iii
List of Appendices ......................................................................................................................... iv
Executive Summary .................................................................................................................. ES-1
1.0 lntroduction ............................................................................................................................ l-1
1.1 Scope of Work ........................................................................................................... 1-1
1.2 Sources of Information .............................................................................................. 1-1
2.0 General Site Conditions ......................................................................................................... 2-1
2.1 Site Location .............................................................................................................. 2-1
2.2 Basin Description ....................................................................................................... 2-1
2.3 Climate ....................................................................................................................... 2-1
2.4 Geology ...................................................................................................................... 2-1
2.4.1 Regional Geologic Considerations ............................................................. 2-1
2.4.2 Diversion Alternatives (Alternatives I, 2 and 3) ........................................ 2-2
2.4.3 Lower lnstream Alternative (Alternative 4) ............................................... 2-2
3.0 Hydrology and Hydraulics ..................................................................................................... 3-1
3.1 Hydrologic Analysis .................................................................................................. 3-1
3.2 Instream Flow Requirement. ...................................................................................... 3-2
3.3 Peak Flows ................................................................................................................. 3-2
4.0 Project Arrangement and Alternatives ................................................................................... 4-1
4.1 Diversion Alternatives (Alternatives 1, 2 and 3) ...................................................... .4-1
4.2 lnstream Alternative (Alternative 4) .......................................................................... 4-3
4.2.1 Weir. ............................................................................................................ 4-3
4.2.2 Powerhouse Structure ................................................................................. 4-4
4.2.3 Turbine Types ............................................................................................. 4-4
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Table of Contents (Continued)
4.2.4 Transmission Line ....................................................................................... 4-4
4.2.5 Electrical Equipment ................................................................................... 4-5
4.2.5.1 Single Line Diagram .................................................................... 4-5
4.2.5.2 Electrical System Layout ............................................................. 4-6
4.2.6 Other Design Considerations ...................................................................... 4-6
5.0 Energy Generation Potential .................................................................................................. 5-1
6.0 Estimated Costs ...................................................................................................................... 6-1
6.1 General ....................................................................................................................... 6-1
6.2 Basis for Construction Costs ...................................................................................... 6-1
7.0 Economic Evaluation ............................................................................................................. 7-1
7 .I General ....................................................................................................................... 7-1
7.2 Annual Costs .............................................................................................................. 7-1
7.3 Cost-Benefit Evaluation ............................................................................................. 7-1
7.4 Economic Analysis Results ........................................................................................ 7-2
8.0 Critical Issues ......................................................................................................................... 8-1
9.0 Conclusions and Recommendations ...................................................................................... 9-1
9.1 Conclusions ................................................................................................................ 9-1
9.2 Recommendations ...................................................................................................... 9-2
10.0 Certification ....................................................................................................................... 10-1
11.0 References .......................................................................................................................... 11-1
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List of Figures
Figure Title
2.1 Project Location
3.1 Nenana River near Healy -Mean Monthly Flow
3.2 Nenana River near Healy -Flow Duration Curve
4.1 Alternative 4-Conceptual Site Plan
4.2 Weir and Powerhouse-Conceptual Layout Plan
4.3 Weir and Powerhouse-Conceptual Layout Sections
4.4 Nenana River Hydro Project-Single Line Diagram
5.1 Average Monthly Power Output
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List of Appendices
Appendix Title
A Cost Estimate
B Economic Analyses
C Photos
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Golden Valley Electric Association
Nenana River Hydropower Scheme
Healy, Alaska
Reconnaissance Study
Final Report
Executive Summary
This report presents a reconnaissance-level investigation of four alternatives for the construction
of a small run-of-river hydropower facility on the Nenana River near the town of Healy, Alaska,
and includes a description of the physical characteristics of the site and an analysis of the four
alternatives. Also included are a conceptual project layout, an estimate of power generation, the
estimated conceptual costs, and an analysis of the economic feasibility for the preferred
alternative.
The first phase of the study was a fatal flaw analysis to investigate if the project is technically
feasible and if there are significant impediments to the project. This phase involved a site visit, a
conceptual geologic and geotechnical assessment of the project site, evaluation of flow and head
available for power generation, and an estimation of the potential turbine and generator capacity.
The fatal flaw analysis did not identify technical fatal flaws that would preclude development of
any of the four alternatives. Results of the fatal flaw analysis were summarized in a memo
issued by Knight Piesold in November, 2008 (Knight Piesold, 2008).
Alternatives I through 3 would consist of a low-impact diversion weir across the river at a sharp
left bend in the river about 3 river miles upstream from the confluence with Healy Creek. A
portion of the river flow would be conveyed from the diversion weir through a 6,800-foot long
tunnel and/or penstock, to a powerhouse on the east bank of the Nenana River about 2,000 feet
upstream from the Healy Creek confluence. Several major disadvantages make Alternatives 1
through 3 unattractive. Each of these alternatives require diversion of water from the river.
Based on preliminary estimates received from the Alaska Department of Fish and Game, the
instream flow requirements for fish (grayling) in this section of the river would considerably
reduce the amount of flow available for diversion and thus the amount of energy that could be
produced. Secondly, experience with other projects suggests that for a hydropower project to be
attractive, the pressurized water conductor should be no longer than about 40 times the available
net head. At this location, the available net head is about 50 feet, and thus the tunnel or penstock
should be no longer than about 2,000 feet. The tunnels and/or penstocks for these alternatives
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would be over 6,800 feet long. In addition, the estimated diameter of the tunnel or penstock
required to minimize head loss at the estimated design flow is 17.5 feet, which would be very
expensive to construct. For these reasons, Alternatives 1 through 3 were eliminated from further
consideration.
Alternative 4 would consist of a low-head concrete weir across the full width of the river, with a
powerhouse built into the weir. This facility would be located upstream of the Healy Creek
confluence, where sufficient river width is available and a net head of about 15 feet can be
achieved. This would be a low-head scheme, but there would be no penstock or tunnel, and no
water would be diverted from the river. The mean monthly flow at this location varies from
434 cubic feet per second (cfs) in March to 9,884 cfs in June. The powerhouse would include
three pit turbines and generators, each having a design flow of 3,250 cfs, a design head of 15 feet
(4.57 m), and an installed capacity of 3,700 kilowatts (kW), for a total installed capacity of
11,100 kW. Based on 29 years of daily flow data from the nearby United States Geological
Survey (USGS) gaging station, the average annual energy production for this facility was
estimated to be 23.6 gigawatt-hours (GWh). Power could be produced for 167 days (May II
through October 24) during an average year. The weir would need to include a fish ladder for
grayling migration, with fish bypass flow requirements estimated to be I ,000 cfs. The weir
would create an impoundment that would extend approximately 3,700 feet upstream, which
probably would not affect whitewater rafting in this reach of the river. The last whitewater
rapids in the river are just downstream of the section known as "Garner", which is about one
mile upstream of the proposed hydropower site. Therefore, these rapids should not be influenced
by the impoundment from the weir. A whitewater raft chute could be installed at the weir,
which may require an additional bypass flow that has not been accounted for in this study. This
issue would need to be coordinated with the local rafting companies and other interested parties.
The estimated cost of the project is 55 million dollars, which is considered accurate to within
plus or minus 30 percent. Assuming an installed capacity of 11.1 megawatts (MW), an avoided
cost rate of $0. I 3/k Wh escalated at 2 percent per year, a 30-year operating period, and a discount
rate of 6 percent, the project would have a positive net cash flow I 7 years after startup, a cost
benefit ratio of 0.91, and a present worth of net benefits of -$5,176,000. Thus, the project is not
economically feasible under these assumptions.
Assuming a discount rate of 4 percent, the project has a positive cash flow in the sixth year after
startup, with a cost benefit ratio of I .16, and a present worth of net benefits of $9,318,000.
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Assuming a discount rate of 6 percent, the cash flow for the project is positive during the first
year if the avoided cost rate is $0.176/kWh.
If GVEA decides to continue investigating a hydropower project at this site, recommendations
include:
• Conduct further studies to determine ifthe economics can be improved by increasing
the weir height and/or the design flow.
• Perform detailed topographic mapping and river channel surveys at the site to define
the site topography, including the channel geometry and the inundation area for the
weir and reservoir.
• Conduct geotechnical field investigations to determine the depth to bedrock for
construction of the weir, the foundation treatment for the weir and powerhouse,
dewatering requirements, and the availability of construction materials in the vicinity.
• Initiate baseline environmental studies at the project site to provide the basis for an
Environmental Assessment or Environmental Impact Statement.
• Conduct an investigation of fisheries resources and recreational use to determine the
requirements for bypass flows and other mitigation measures.
• Investigate the potential effects of sediment loading on the weir, the impoundment
and the turbines.
• Identify the specific requirements for perm1ttmg and licensing of the proposed
facility. FERC (Federal Energy Regulatory Commission) and other appropriate
regulatory agencies and community stakeholders should be contacted early in the
planning process to identify and address potential environmental and safety concerns.
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Golden Valley Electric Association
Nenana River Hydropower Scheme
Healy, Alaska
Reconnaissance Study
Final Report
1.0 Introduction
Knight Piesold and Co. (Knight Piesold) was retained by Golden Valley Electric Association
(GVEA) to investigate the potential for construction of a small run-of-river hydropower facility
on the Nenana River near the town of Healy, Alaska.
1.1 Scope of Work
The first phase of the study was a fatal flaw analysis to determine if the project is technically
feasible and if there are significant impediments to the project. This phase involved a site visit, a
conceptual geologic and geotechnical assessment of the project site, evaluation of flow and head
available for power generation, an estimate of the potential turbine and generator capacity, and a
description of four possible alternatives for the proposed hydropower facility. The results of the
fatal flaw analysis were summarized in a memo issued by Knight Piesold in November, 2008
(Knight Piesold, 2008), which concluded that there were no technical fatal flaws to preclude
development of a hydropower scheme. Four alternatives were identified for the hydropower
facility during this phase of the study.
The second phase, presented in this report, includes a more detailed description and analysis of
the four alternatives. Also included for the preferred alternative are development of a conceptual
project layout; an estimate of power generation; the estimated conceptual costs; and an analysis
ofthe economic feasibility.
1.2 Sources of Information
Information used during the study included survey data, information on energy economics, and
facility design criteria received from GVEA; information on the physical setting collected by
Knight Piesold staff during a site visit; hydrologic data and topographic maps from the United
States Geological Survey (USGS); site imagery from Google Earth software; geologic reports
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from the Geophysical Institute at University of Alaska Fairbanks; and fisheries information from
the State of Alaska Department of Fish and Game, Division of Habitat, Fairbanks, Alaska.
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2.0 General Site Conditions
2. 1 Site Location
The proposed hydropower project is located on the Nenana River south of Healy, Alaska. The
intake and power plant would likely be located in a stretch of the river between the Alaska
Highway 3 bridge crossing and the confluence of Healy Creek. Figure 2.1 shows the locations of
the four alternatives that were considered for this study.
2.2 Basin Description
The Nenana River is a tributary of the Tanana River. Its drainage basin area above the gaging
station near Healy is 1,910 square miles, and includes a portion of the northern slopes and
foothills of the Alaska Range. Its headwater region is the Nenana Glacier, southwest of Mt.
Deborah and northeast of Cantwell, and its total length is about 150 miles. The river flows north
along the eastern boundary of Denali National Park to its confluence with the Tanana River at
the town of Nenana, about 60 miles southwest of Fairbanks. The Nenana River is one of the
most popular destinations for whitewater rafting in Alaska.
2.3 Climate
The average annual precipitation in the Nenana River watershed ranges from over 50 inches in
the high mountains of the Alaska Range, to 14.8 inches at Healy, which has an average annual
snowfall of 79 inches. The climate of Healy is typical of interior Alaska, with seasonal
temperature extremes that can range from -60°F in mid-winter to as high as +85°F in the
summer. Average January temperatures range from -22°F to -2°F. Average July temperatures
range from +50°F to +72°F.
2.4 Geology
2.4.1 Regional Geologic Considerations
The area is characterized by exposed schist bedrock, alluvial material on the valley bottom and
remnants of a complex series of outwash gravel terraces on the valley sides. Schist exposed at
the valley sides is composed predominantly of quartz and fine grained mica. Foliation is well
developed and strikes eastward and dips approximately 20° southward. Basalt dikes are common
in well developed cross joints in the schist. The dikes are generally vertical, strike roughly
north-south and range from 5-50 feet thick. The schist is inherently weak and prone to
separating along planes of foliation. Once exposed to air and frost, fresh schist surfaces may
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weather to depths of 5 to 6 inches in less then a year. Rockslides and rockfalls are common in the
schist where foliation dips or fold axes plunge toward the river. The majority of bedrock in the
area is covered with a thin veneer of gravels deposited from down-slope movements caused by
freeze-thaw action.
An anticline is located approximately Y4 mile north of the proposed project site, trending
generally east-west, parallel to the south side of the Healy Creek. Aerial photographs of the
region suggest deformation of Quaternary deposits in much of the northern foothills that may
contribute to the regional seismic hazards.
2.4.2 Diversion Alternatives (Alternatives 1, 2 and 3)
The diversion alternatives are located about 2 to 3 miles upstream from the Healy Creek
confluence. The majority of subsurface or underground work in this area would be through schist
containing widely spaced basalt dikes. Alluvial fan or glacial deposits may be encountered north
of sections 4 and 5 where the topography flattens. These deposits are poorly consolidated and
would make tunneling difficult. As such, a shorter tunnel option may be more viable. The schist
should have sufficient strength to support the diversion structure.
According to the river guide, the river is approximately 10 to 20 feet deep at the proposed
diversion weir and intake location. Based on the exposed rock walls in this section of the valley,
alluvial material is anticipated to be several feet thick. Remnant terrace and glacial deposits are
exposed along the valley walls and may pose stability issues. Glacial deposits may contain clay
and various unconsolidated soils. Instabilities were observed in the railroad fill slopes on the
west side of the valley walls.
Access to the diversion weir and tunnel inlet would involve constructing a bridge over Healy
Creek and pioneering a road to the intake site. Large cuts into the steep schist slopes within a
half mile downstream of the inlet would likely need to be stabilized by a combination of rock
bolting, wire mesh and shotcrete.
2.4.3 Lower lnstream Alternative (Alternative 4)
The lower instream alternative is located about 2,000 feet upstream of the Healy Creek
confluence. Outwash gravel deposits are preserved in this area as remaining sections of an
extensive complex of terraces. Gravels generally consist of well-rounded pebbles, cobbles,
boulders and coarse to very coarse clean sands and clays. Gravel covered terraces form an
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approximately one-mile wide area adjacent to the site. On the lower level terraces, gravels are
generally between 5 to 10 feet thick. In the area of the proposed in-stream hydropower facility,
the Nenana River has cut through the terrace gravels into the schist. Thus the left and right
abutments are schist and the river bed is likely to consist of fluvial gravels, cobbles and boulders
overlying schist. The fluvial gravels are estimated to be about 5 to I 0 feet thick.
Slumps and earthflows are common in the unconsolidated or poorly consolidated debris on the
canyon walls along the Nenana River. These failures are well documented along the railroad line
adjacent to the site. According to previous studies of failures in the area, sliding planes for the
failures are 10 to I 00 feet below the surface and up to several thousand feet wide. Additional
investigation is required to confirm the potential impact of slope failures within the immediate
site area. The Healy Fault trends east-west, and it is understood to be an active fault reverse fault.
However, it appears that the fault is north and west of the proposed site development and would
not cross the site. Additional investigation would be required to determine if this fault is a
potential source of ground shaking that could affect the project.
For this study, a suitable foundation for a low weir was assumed to be available at a reasonable
depth at this site. This assumption should be confirmed by site-specific drilling and geotechnical
analysis during future studies. A detailed discussion of the foundation treatment and river
diversion required for this project is beyond the scope of this report, and should be addressed
during feasibility studies and preliminary design.
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3.0 Hydrology and Hydraulics
3. 1 Hydrologic Analysis
The stream gaging station nearest the proposed project site on the Nenana River is located just
upstream of the confluence with Healy Creek. The USGS monitored the flows at this station
(No. 15518000) from October I, 1950 through September 30, 1979. The mean monthly flows
for this station are shown in the table below and on Figure 3.1. The mean flow for the period
from May through October is 6,353 cfs. The mean monthly flow varies from a low of 434 cfs in
March to a high of 9,884 cfs in June. The peak recorded flow for the period of record was
46,800 cfs on July 25, 1967. The flow pattern is typical for interior Alaska, with high flows from
May through October and low flows from November through April. The 1,910 square mile
drainage area includes a number of glaciers, and therefore the summer flows tend to be sustained
at a fairly high rate. Conversely, most of the winter precipitation falls as snow, and winter flows
can become very low.
Nenana River Station No. 15518000 near Healy, Alaska
Mean Monthly Flow, cfs
Jan Feb Mar Apr May Jun Jul Au~ Sep Oct Nov Dec
Av~ 558 473 434 514 3,885 9,884 9,516 7,872 4,879 2,149 1,021 688
Max 890 640 610 1,700 17,000 35,900 38,600 29,200 18,200 5,470 2,600 2,600
Min 200 190 190 190 270 3,720 4,060 2,600 1,450 650 290 240
Mean daily flow records for the Nenana River gaging station 15518000 were downloaded from
the USGS web site and used to develop the flow-duration curve shown in Figure 3.2. The flow-
duration curve is a cumulative-frequency curve that shows the percentage of time that specified
discharge values are met or exceeded during a given period.
The practical power generation period was assumed to be from May through October.
Therefore, the flow-duration curve was developed for only those months. As shown in the table
above, the flows from November through April are significantly lower and the river typically
freezes over. Based on the recorded flows for the period from May through October, it appears
that there is probably adequate water available for power generation, depending on the amount of
water that needs to remain in the river for rafting and fish.
As a starting point, normal flows in the 25-percent exceedance range are selected for analysis of
the project installed capacity and energy output. For the flow-duration curve shown in Figure
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3.2, the 25-percent flow would be about I 0,000 cfs. Initially, GVEA assumed a design flow of
3,000 cfs for the Alternative Energy Grant Proposal for this project. This design flow would
leave significant flow in the river for recreational rafting and fish. Depending on the alternative
design selected for the hydropower facility, it may be possible to increase the design flow and
still leave sufficient water in the river for rafting and fish.
Cross sections of the river at USGS Gaging Station No. 15518000 near Healy, Alaska were
obtained from the USGS for several discharges to assist in determining the depth of the water
and shape of the river channel at this location. The cross sections indicate a deep channel on the
right side of the river looking downstream that varies from about 11.0 to 12.5 feet deep for flows
of about 3,400 to 7,200 cfs, respectively.
3.2 lnstream Flow Requirement
The Alaska Department of Fish and Game filed an application with Alaska Department of
Natural Resources' Division of Land and Water Management in 1996 for instream flow
reservation (to protect and maintain fish habitat and passage) on a reach of the Nenana River that
includes the area of interest. The table below shows the comparison of the mean daily flows in
the river by month with the minimum flows requested for fisheries habitat. The table indicates
that diversion available for power production would likely be limited to the months of June, July,
August and September. Flows available for power production would be less than half of the
mean daily flow during these months, which would significantly affect the economic feasibility
of the hydropower facility.
Nenana River near Healy, Alaska
M can on ly ow an ns ream eserve ow eqUiremen s M th I Fl d I t R Fl R t
Flow (cfs)
Jan Feb Mar Apr May Jun Jut Au~ Sep Oct Nov Dec
Mean
Monthly
Flow 558 473 434 514 3,885 9,884 9,516 7,872 4,879 2,149 1,021 688
lnstream
Reserve
Flow 527 470 430 500 3,506 5,760 5,760 5,760 3,506 2,104 1,000 670
3.3 Peak Flows
Peak flows for selected return periods were estimated by applying the Type-1 Extremal (Gumbel)
distribution to the annual peak flows for the period of record. The results of this analysis are
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summarized in the table below. The I 00-year peak flow estimate ( 50,481 cfs) was used to
develop a conceptual design and preliminary cost estimate for the weir and powerhouse. A weir
and hydropower facility at this location may be required to be designed for the Probable
Maximum Flood (PMF). Calculating the PMF was beyond the scope of this study.
Return
Period
Peak
Nenana River near Healy, Alaska
Peak Flows for Selected Return Periods
2-yr 5-yr 10-yr 50-yr 100-yr
Flow 20,836 28,772 34,027 45,592 50,481
(cfs)
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500-yr
61,779
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4.0 Project Arrangement and Alternatives
Based on the available flow data and survey information collected by GVEA on the river
gradient, several possible run-of-river alternatives were identified and evaluated for potential
hydropower generation on the Nenana River upstream of the town of Healy.
PDC Engineers (PDC Engineers, 2008) surveyed water surface elevations at three points along
the Nenana River, beginning at the gaging station upstream from Healy Creek and continuing for
6.6 miles farther upstream. The total elevation difference over this distance was 149 feet, giving
an average river gradient of 0.43 percent. This gradient shows that sufficient head is available
for a potential run-of-river scheme at this location, such as described in Alternatives I through 3.
An instream alternative (Alternative 4) that would utilize a low-head weir with an integral
powerhouse was also considered. The four alternatives are described in the following sections,
and their locations are shown on Figure 2.1.
4.1 Diversion Alternatives (Alternatives 1, 2 and 3)
These alternatives would consist of a low-impact diversion weir across the river, at a sharp left
bend in the river about 3 river miles upstream from the confluence with Healy Creek. The weir
would be designed to incorporate a bypass channel or whitewater rafting chute. The almost
vertical rock wall on the east side of the river at this bend would provide a good location for a
tunnel portal.
For Alternative I, the tunnel would extend for about 2 miles from the intake to a point on the east
bank of the Nenana River, just upstream from the confluence with Healy Creek where the river
starts to widen. According to the survey conducted by PDC Engineers, the river gradient is
about 0.39 percent in this area, which would produce a net drop in the river water surface of
about 62 feet over 3 miles. The tunnel diameter would be about 17.5 feet to provide a net head
of about 50 feet. Based on a design flow of 3,000 cfs and net head of about 50 feet, the installed
capacity would be about 10.8 MW.
A second sharp left bend in the river and rock face was observed during the raft trip about
2 miles upstream of the Healy Creek confluence. The net drop in the river water surface for this
location would be about 41 feet over the 2 miles. A 1.3 mile long tunnel would be required from
this site to the powerhouse site near Healy Creek. The net head would be about 33 feet, which
would provide an installed capacity of about 7 .l MW for a design flow of 3,000 cfs. Access to
the weir and tunnel portal would be along the east side of the Nenana River and would be
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difficult and costly to construct due to the steep terrain and the required bridge across Healy
Creek. According to discussions during the field trip, this is a smaller hydropower facility than
GVEA is interested in developing; therefore, this site was excluded from further consideration.
Alternative 2 would be a combination of a tunnel and penstock. The tunnel portal would be at
the same location as Alternative I, with the tunnel extending for about 1.2 miles where it would
daylight near the river about one mile upstream of the Healy Creek confluence. A penstock
would then extend for about one mile from the end of the tunnel to the power plant site near
Healy Creek as described above. The penstock would likely be above ground with steel or
concrete supports. The tunnel and penstock would both be 17.5 feet in diameter. Based on a
design flow of 3,000 cfs and net head of about 49 feet, the installed capacity would be about
10.6 MW.
Alternative 3 would consist of a penstock along the east side of the Nenana River from the weir
to the power plant site near Healy Creek. The penstock would be about 3 miles long and would
likely be above ground with steel or concrete supports. The penstock would be about the same
diameter as described above. Based on a design flow of 3,000 cfs and net head of about 44 feet,
the installed capacity would be about 9.5 MW. Access for not only the weir, but also
construction of the penstock would be difficult due to the steep terrain and extensive rock
outcrops.
Several major disadvantages make the diversion alternatives unattractive. Each of the
alternatives described above require diversion of water from the river. As indicated earlier in this
report, the instream flow requirement for fish would considerably reduce the amount of energy
that could be generated with a diversion scheme. A general guideline is that for a hydropower
project to be attractive the pressurized water conductor should be no longer than about 40 times
the available net head. For the available net head of about 50 feet, the tunnel or penstock should
be less than about 2,000 feet long. The tunnels described above are over about 6,800 feet long.
In addition, the diameter of the tunnel and/or penstock would be relatively large, to minimize
head losses for the design flow, which makes it very expensive to construct. For these reasons,
the diversion alternatives were eliminated from further consideration.
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4.21nstream Alternative (Alternative 4)
Alternative 4 would consist of a weir and hydropower facility located upstream of the Healy
Creek confluence, where sufficient river width is available and a net head of about 15 feet can be
achieved. The location should be as near to the confluence of Healy Creek as possible to
minimize the length of the access road and transmission lines and to avoid interference with the
railroad. The conceptual site plan for this alternative, showing possible locations for the access
road and transmission line, is shown in Figure 4.1. The key components of this alternative are
described in the following sections.
4.2.1 Weir
A hydropower facility at this site would consist of a low-head concrete weir across the Nenana
River with the hydropower facility integrated into the weir. This would be a low-head scheme,
but there would be no penstock or tunnel and no water would be diverted from the river. The
weir would need to include a fish ladder for fish migration, but the bypass flow requirements
would probably be less than the instream flow requirements given in the table in Section 3.2.
For this report, the bypass flow requirement for Alternative 4 was assumed to be I ,000 cfs.
The weir would experience a relatively large head range and a very large potential flow
variation. Based on the cross sections of the river obtained from the USGS, the weir would need
to be a minimum of 30.0 feet above the river bed at its deepest point to maintain a head
differential of about 15.0 feet on the turbines. These characteristics indicate use of bulb, "pit" or
S-type turbines incorporated into the weir. For a design flow of about 9,750 cfs (based on the
25 percent exceedance on the flow duration curve) and a net head of about 15 feet, the installed
capacity would be about II. I MW. The hydropower facility would consist of three 3.7 MW
turbine and generator units.
The weir would create an impoundment that would extend approximately 3,700 feet upstream,
which probably would not affect whitewater rafting in this reach of the river. The last
whitewater rapids in the river are just downstream of the area known as "Garner'', which is about
one mile upstream of the proposed hydropower site. Therefore, these rapids should not be
influenced by the impoundment from the weir. A whitewater raft chute could be installed at the
weir, which may require an additional bypass flow that was not accounted for in this study. This
issue would need to be coordinated with the local rafting companies and other interested parties.
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The maximum weir height is uncertain due to the lack of adequate topographic mapping of the
area. The exiting USGS Healy (D-4) Quadrangle, dated 1950, has a contour interval of I 00 feet,
with some 50 foot contours. More detailed topographic data would be needed to establish the
maximum potential height of the weir at this site.
4.2.2 Powerhouse Structure
For the instream alternative described above, the powerhouse would be a semi-indoor reinforced
concrete structure with roof hatches for access to install and maintain the turbines and
generators. A permanent crane would not be included in the structure. The water intake would
include gates for emergency shut down of the turbines. Stoplog slots would be included on the
intake and draft tube to dewater the turbine to perform maintenance. Trashracks would be
included on the intake to prevent large debris and ice from entering the waterway and damaging
the turbines. The conceptual plan view and cross-sections of the weir and powerhouse are shown
in Figures 4.2 and 4.3.
4.2.3 Turbine Types
The instream site would be characterized as low-head, high-flow as far as the turbines are
concerned. These working conditions are especially suited for propeller-type turbines. These
turbines are available in vertical, inclined and horizontal shaft alignments and configurations
designated by the names vertical shaft, tube, bulb, and pit types. For the instream site on the
Nenana River, the preferred configuration would be the horizontal-axis, adjustable-blade pit type
turbine, due to its high efficiency across the expected wide range of flows. This type of turbine
has gained popularity over recent decades for its compact construction, ease of maintenance and
efficient performance.
The pit turbine considered for the instream site has three elements m the power train: an
adjustable-blade Kaplan turbine, a speed increaser and a high-speed synchronous generator.
These are arranged on a horizontal axis within the water passage, with access to the generator
and speed increaser from above.
4.2.4 Transmission Line
The existing GVEA 138 kilovolt (kV) transmission line from the existing Healy power plant is
located about 0.5 miles northeast of the proposed instream hydropower site on the Nenana River.
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4.2.5 Electrical Equipment
The electrical system would be designed to connect the three generators to the GVEA 138kV
transmission line located just northeast of the powerhouse site. For the purpose of the electrical
system design, the following assumptions were used:
• Generators designed to operate at 13.8kV.
• Electrical equipment housed in the generation building, no separate control needed.
• Switchyard contains a 13.8 to 138kV step-up transformer and 138kV breaker switch.
• Line protection required for the 138kV line.
• Point of interconnection is the bushings of the 138kV potential transformers. GVEA
to provide the dead end structure, lightening arrestors and disconnect switches.
• GVEA to provide any Supervisory Control and Data Acquisition (SCADA)
equipment required. The construction cost estimate does not include GVEA SCADA
allowances.
4.2.5.1 Single Line Diagram
A preliminary single line diagram for the proposed hydropower facility is shown in Figure 4.4.
Each generator would have an SEL-300G providing primary protection consisting of over and
under voltage elements, over and under frequency elements, differential elements, over-current
elements and synch check. Backup protection would be provided by a SEL-351 relay that would
provide over and under voltage elements, over and under frequency elements, over-current
elements and synch check. Each generator would be high resistance grounded to protect the
generators from damaging ground fault currents.
The main breaker would have an SEL-351 to provide over-current protection with some back up
protection for voltage and frequency disturbances. Synch-check would also be used on this relay
to ensure the utility cannot be closed into the generators. The main 13.8kV bus would also be
protected with an SEL-587Z high impedance bus differential relay for high speed protection
against bus faults.
The step up transformer would be a three winding, wye-delta-wye, transformer that would
provide a ground source for both the utility and the generation facility. The facility side of the
transformer would be resistance grounded to 200A for selective clearing of ground faults. The
utility side would be solidly grounded unless directed otherwise by the utility. The transformer
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would be protected by an SEL-587 transformer differential relay with back-up protection
provided by an SEL-551C relay. Line protection for the 138kV transmission line would be
provided by an SEL-421 distance relay. Some back-up protection would be provided by the
SEL-551 C relay as well.
All of the relays would be connected to an SEL-2032 communications processor for plant
monitoring and control. No SCADA control from the utility is shown. Trip and close terminals
for the main breaker would be made available to the utility.
A motor control center is included to provide station service for the facility. The station service
loads include the hydraulic units for the generators, power for station lights, HVAC, control
equipment and miscellaneous motor loads that could be expected in such a facility.
4.2.5.2 Electrical System Layout
The 15kV switchgear and 480V station service equipment would be located in a dedicated
electrical room in the generation facility. The main breaker in the 15kV gear would be
connected to the step-up transformer via underground cables. The station service transformer
would be located in the same yard. This yard would be on the opposite side of the wall from the
electrical room to minimize cable lengths.
4.2.6 Other Design Considerations
Hydropower facilities in cold climates sometimes include design features to prevent ice
formation near critical components, and to withstand spring season ice-out For example,
bubbler pipes and/or heaters can be used to prevent ice formation at the turbine intakes;
trashracks can be used to prevent floating ice from entering the turbine intake; and log booms
can be installed upstream of the weir to trap floating ice. Specific design features to prevent ice
formation and withstand ice-out should be included in the feasibility study and preliminary
design.
The specific effects of sediment loading on impoundment storage capacity and turbine runners at
the site should be addressed in future studies. A sampling program to characterize suspended
and bedload sediment in the river may be required. A detailed analysis of the effects of sediment
loading is beyond the scope of this report.
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5.0 Energy Generation Potential
The concept for the hydropower facility includes a powerhouse integrated into a low-head weir
located upstream from the confluence of Healy Creek. The powerhouse would include three pit
turbines and generators, each turbine having a design flow of 3,250 cfs, design head of 15 feet,
and an installed capacity of 3,700 kW, for a total installed capacity of 11,100 kW.
The mean daily flow data for the entire period of record was used in the energy generation
calculations. Flows in the river from 20 percent to 110 percent of the design flow (II ,000 cfs)
were used to calculate the average annual energy generation, which is estimated to be 23.6 GWh.
Ten percent of the design flow (I ,000 cfs) was subtracted from all mean daily flows to allow for
diversion from the turbine intakes for a fish migration facility.
Efficiency of a Kaplan turbine is above 90 percent but is not constant, gradually rising and then
falling moderately as the flow increases. The Kaplan operating range can be from 110 percent of
design flow down to about 20 percent of design flow. The efficiency of the speed increaser
would be fairly constant at around 98.5 percent, and the efficiency of the generator would be
about 98 percent at full design flow but drops to around 94.5 percent at 20 percent of full load.
The combined efficiency would be 89.3 percent from 60 percent to 100 percent of design flow.
At 20 percent flow the combined efficiency would be 78.2 percent. Based on these values, an
overall average efficiency of 86 percent was used for the energy generation calculations.
A constant head of 15 feet was assumed since topographic data was unavailable to calculate the
headwater and tailwater elevations in the river channel at various flows. The crest of the weir
was assumed to be approximately 15 feet above the tailwater elevation at the design flow. The
design head was assumed to remain relatively constant throughout the range of flows since both
the headwater and tailwater elevations would increase when the flow increases. The results of the
annual energy generation analyses are summarized in the table below, and the average monthly
power output is shown in Figure 5.1.
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Weir Height
(ft)
15
20
25
Notes:
Nenana River Hydropower Study
Annual Energy Generation Summary11 l
Installed
Capacity
(MW)
11.1
Bypass Flow
Annual Energy
Production
(GWhr)
I) The average annual energy production period is 167 days, from May lith through October 24th, based on
average values for the 27-year period of record ( 1951 to 1978).
2) Energy production is based on mean daily flows for the period of record, minus 1,000 cfs for fisheries bypass
flow requirements.
3) Transformer efficiency is assumed to be 99.5 %.
4) Unscheduled outages are assumed to be 3 %.
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6.0 Estimated Costs
6.1 General
An opinion of probable project costs for Alternative 4 was developed based on November 2008
dollars. The opinion of probable project costs includes construction costs, contingency,
engineering, permitting, and legal fees. Estimated project costs are discussed below and
presented in Appendix A.
6.2 Basis for Construction Costs
Construction costs were estimated for each of the project components using cost data from
available guidelines, manuals, previous projects, and preliminary quotes from vendors. Where
necessary, estimated costs were escalated to the third quarter of 2008 using escalation rates
published by the Bureau of Reclamation (USBR, 2002) and Corps of Engineers.
Estimated construction costs were developed for each of the following project components:
• Mobilization and demobilization
• Access roads
• Powerhouse and ancillary facilities
Weir and apron, including temporary river diversion and earthwork
• Power generation package (turbines, speed increasers, generators, governors,
controls, switchgear and hydraulic pressure unit, transformer, draft tube gate and
installation)
• Switchyard
• Transmission line
• Fish passage
The costs for mobilization and demobilization were estimated as a percentage of the total
construction costs. Costs for the powerhouse, weir and apron construction, temporary river
diversion, and earthwork were based on a conceptual design using available guidelines and data
from previous projects, with dimensions and site conditions estimated from reconnaissance-level
topographic and geotechnical information. It was assumed that the foundation of the weir would
extend I 0 feet below the river bed. Costs for the turbines, generators, hydraulic pressure units
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(HPUs), controls and switchgear are based on a preliminary quote from Andritz VA Tech Hydro
Canada, Inc. Switchyard electrical costs were based on a preliminary quote from NEI Electric
Power Engineering, Inc. of Arvada, Colorado. Transmission line costs were based on
information from GVEA. Fish passage construction costs were from a report by INEEL, 2003,
which estimates these costs as a function of plant capacity based on data from other hydropower
projects. The total estimated construction cost was calculated by adding 25 percent for
contingency. The contingency allowance covers the cost of unexpected and unlisted items that
would normally be included in a more detailed estimate. The contingency also allows for
possible price increases due to unforeseen circumstances.
Overall project cost was established by adding engineering, permitting, and legal fees. These
fees were estimated to be:
• Engineering @ 15 percent of total construction cost with contingency
• Permitting @ 4 percent of total construction cost with contingency
• Legal@ 4 percent of total construction cost with contingency
Engineering costs include the feasibility study, preliminary and final design, procurement,
construction management, and administration.
Estimated construction costs and the total project cost are shown in Appendix A. The total
project cost estimate is $55,182,000, which should be considered accurate to within plus or
minus 30 percent.
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7.0 Economic Evaluation
7.1 General
An economic evaluation was completed for Alternative 4, including annual costs, annual
revenues, benefit/cost ratio, net present value of costs and revenues, present worth of net benefits
and accumulated net cash flow. The economic analysis was based on energy generation using a
net head of 15 feet, a design flow of I 0,000 cfs, and the estimated costs from Appendix A
7.2 Annual Costs
Project annual costs were divided into two components: annual debt service and annual operation
and maintenance (O&M) cost. Annual debt service provides payment of interest and principal
over the bond repayment period. Maintenance was assumed to take place during the off-season.
Fixed operation and maintenance costs were estimated to be $0.0062/kWh [INEEL, 2003]. The
annual operation and maintenance cost for the first year of operation was estimated to be
$146,320. Operation and maintenance costs were escalated at an annual rate of 2 percent over
the life of the project to account for increased costs associated with aging machinery.
7.3 Cost-Benefit Evaluation
An economic analysis was completed for Alternative 4 assuming a 30-year project life, a
discount rate of 6 percent, and bond repayment term of 30 years. Energy production was
assumed to begin in 2011. Project permitting, planning, engineering and construction were
assumed to consume about two years from early 2009 through 2010. Annual revenue was
calculated by multiplying GVEA's avoided cost rate by the average annual energy production.
The GVEA avoided cost rate was estimated to be $0.13/k Wh in 2008, escalated at 2 percent
annually over the 30-year life of the project.
Several analyses were performed to determine the economic feasibility of the project. The first
analysis calculated the benefit-to-cost ratio for an installed capacity of 11.1 MW, assuming an
avoided cost rate of $0.13/k Wh escalated at 2 percent per year and a 6 percent discount rate. The
second analysis assumed the same avoided cost rate and a 4 percent discount rate. A third
analysis determined the minimum avoided cost rate required to produce a completely positive
cash flow for the entire period assuming a 6 percent discount rate.
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7.4 Economic Analysis Results
The table below summarizes the results of the economic analysis for the assumed installed
capacity of 11.1 MW and discount rates of 6 percent and 4 percent. For an operating life of
30 years and a discount rate of 6 percent, the project is not economically feasible. For a discount
rate of 4 percent, the project is economically feasible if a positive net cash flow that begins
6 years after startup is acceptable. The cash flow for the project is positive during the first year if
the avoided cost rate is $0.176 per kWh. Details of the economic analysis are included in
Appendix B.
Nenana River Hydropower Study
Alternative 4
Economic Analysis Results for 30 Years of Operation
Average Initial Present
Installed Annual Avoided Discount Benefit Worth of Net Years of
Capacity Energy Cost Rate Cost Benefits Cash Negative
(MW) (GWh) ($/kWh) (%) Ratio ($) Flow Cash Flow
11.1 23.6 0.13 6 0.91 -5,176,000 Negative 16
11.1 23.6 0.13 4 1.16 9,318,000 Negative 5
11.1 23.6 0.176 6 1.23 13,433,000 Positive 0
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8.0 Critical Issues
The following critical issues for Alternative 4 were identified during this study. These issues
could have a significant impact on the design and/or the economic feasibility of the project.
• The economic feasibility of hydropower at this site depends on the weir height and
turbine design flow, as well as on the value of the energy produced and the bond
discount rate. Further investigation would be required to evaluate the effect of these
parameters on the project economics.
• More accurate topographic data is required for the entire site, including the river
channel, to determine the dimensions and design of the weir and powerhouse, the area
of inundation, and the design of the required river diversion.
• A site-specific geotechnical field investigation is needed to determine the depth to
bedrock for construction of the weir, the foundation treatment for the weir and
powerhouse, dewatering requirements, and the availability of construction materials
in the vicinity.
• Geologic and seismic hazard investigations should be conducted at the site, including
the potential effect of inundation on the stability of the railroad fill slopes upstream
from the weir.
• An accurate determination offish bypass flow requirements is required since grayling
are present in the river at the site. The fish bypass requirements will affect the
potential for energy generation and hence the economic feasibility of the project.
• The effects of sediment loading on impoundment storage capacity and on the turbine
runners at the site should be addressed. This issue affects the turbine design as well
as possible requirements for flushing or otherwise removing sediment from the
impoundment.
• The potential effects of the project on whitewater rafting, and any necessary
mitigation measures, should be addressed in cooperation with the local rafting
companies and other interested parties.
• Specific requirements for permitting and licensing ofthe proposed facility need to be
identified. FERC (Federal Energy Regulatory Commission) and other appropriate
regulatory agencies and community stakeholders should be contacted early in the
planning process to identify and address any potential environmental or safety
concerns.
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9.0 Conclusions and Recommendations
9. 1 Conclusions
The following conclusions are based on the reconnaissance level studies described in this report:
• Development of a hydropower facility at the initially identified diversion weir sites
(Alternatives 1 to 3) does not appear to be economically or environmentally feasible
due to the potentially high costs and instream flow requirements. Construction of a
long, large-diameter tunnel or penstock for these sites would be very costly,
particularly when compared to the available head. In addition, the instream flow
requirements requested by the Alaska Department of Fish and Game would adversely
reduce the annual energy generation at these sites.
• Development of a hydropower facility at the instream site (Alternative 4) appears to
be technically feasible. The estimated cost of the project is $55,182,000 considered
accurate to within plus or minus 30 percent. Assuming an installed capacity of
11.1 MW, an electricity rate of $0.13/kWh escalated at 2 percent per year, a 30-year
operating period, and a discount rate of 6 percent, the project would have a negative
net cash flow for a period of 16 years after startup, a cost benefit ratio of 0.91, and a
present net worth of benefits of -$5,176,000. Thus, the project is not economically
feasible under these assumptions.
• Assuming a discount rate of 4 percent, the project has a positive net cash flow in the
sixth year after startup, with a cost benefit ratio of 1.16.
The economic feasibility of hydropower at this site depends on the weir height and
turbine design flow, as well as on the value of the energy produced and the bond
discount rate. Further study would be required to determine if raising the weir height
and increasing the installed capacity would improve the economics of the project.
• Small hydropower projects are currently eligible for federal Production Tax Credits
(PTCs) of $0.0 1/kWh during the first ten years of operation. Further investigation
would be required to determine how this could affect the economics of the project.
• Accurate existing topography is required to determine the weir height, layout of the
potential hydropower facility, and access road alignment.
• Geotechnical field investigations are required to determine the depth to bedrock for
construction of the weir, the foundation treatment for the weir and powerhouse,
dewatering requirements, and the availability of construction materials in the vicinity.
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9.2 Recommendations
If GVEA decides to continue investigating a hydropower project at this site, recommendations
include:
• Conduct further studies to determine if the economics can be improved by increasing
the weir height and/or the design flow.
• Investigate the possible impact of production tax credits on the economics of the
project.
• Perform aerial mapping and river channel surveys at the site to define the site
topography, including the channel geometry and the inundation area for the weir and
reservoir.
• Conduct geotechnical field investigations to determine the depth to bedrock for
construction of the weir, seismic and geologic conditions at the site, and availability
of construction materials in the vicinity of the site.
• Identify land ownership at the project site, and in the area that would be flooded by
the weir.
• Initiate baseline environmental studies at the project site to provide the basis for an
Environmental Assessment or Environmental Impact Statement.
• Conduct an investigation of fisheries resources and recreational use to determine the
requirements for bypass flows.
Investigate the potential effects of sediment loading on the weir, the impoundment,
and the turbines.
• Initiate discussions with state and federal agencies to identify potential environmental
and permitting issues.
• Investigate the potential effects of price volatility of material costs, fuel costs and
electricity prices on the economic feasibility of the project.
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10.0 Certification
This report, entitled ''Golden Valley Electric Association, Nenana River Hydropower Scheme,
Healy, Alaska, Reconnaissance Study, Final Report" was prepared for Golden Valley Electric
Association by Knight Piesold and Co. The material in this report reflects the best judgment of
Knight Piesold and Co. in light of the information available to both firms at the time of the report
preparation. Any usc which a third party makes of this report, or any reliance on or decisions
made based on it, are the responsibility of such third parties. Knight Piesold and Co. and Golden
Valley Electric Association accept no responsibility for damages, if any, suffered by any third
party as a result of decisions made or actions taken based on this report.
This numbered report is a controlled document. Any reproductions of this report arc
uncontrolled and may not be the most recent revision.
This report was completed by Knight Piesold and Co. under the coordination of Gilberto
Dominguez, P.E., Principal, and was prepared by John Dwyer, P.E., Project Engineer and
Charles Hutton, P.E., Senior Consultant. AI Gipson, P.E., Senior Consultant, and Steve Farrand,
Geologist, prepared the geology and geotechnical sections. The electrical systems design was
furnished by NEI Electric Power Engineering, and the mechanical systems design by Ken
Laurence, P.E., Senior Consultant. Final review was conducted by Gilberto Dominguez, P.E.,
Principal and Sam Mottram, P.E, Manager, Power Systems.
~£~
Project Engineer
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Charles C. Hutton, P.E.
Senior Consultant
January 6, 2009
Knight Piesold
CONSULTING
11.0 References
Idaho National Engineering and Environmental Laboratory, June 2003, "Estimation of Economic
Parameters of U.S. Hydropower Resources".
Knight Piesold, October 2008. "Nenana River Hydropower Reconnaissance Study -Technical
Fatal Flaw Analysis", Memorandum to Golden Valley Electric Association.
The Geological Society of America, 2007, "Neotechtonic Framework of the North-Central
Alaska Range Foothills", Special paper 431, Bemis, S.P. and Wallace, W.K.
PDC Engineers, 2008. GVEA Tok-Healy Hydro Study, Survey Report. PDC Memorandum No.
F08116 from Craig Ranson to Paul Park. October 1, 2008, Fairbanks, Alaska.
U.S. Army Corps of Engineers, July 1979, "Feasibility Studies for Small-Scale Hydropower
Additions", Hydrologic Engineering Center, Davis, California.
U. S. Department of the Interior, July 1980, "Reconnaissance Evaluation of Small, Low-Head
Hydroelectric Installations", Water and Power Resources Center, Engineering and
Research Center.
United States Department of the Interior, Geological Survey, 1976, "Healy Alaska D-4
Quadrangle, Alaska-Denali Borough", 1 :63 360 Topographic Map.
United States Department of the Interior, Geological Survey 1958, "Quaternary and Engineering
Geology in the Central Part of the Alaska Range", Professional Paper 293, Wahrhaftic,
C. and Black, R.F.
DV103.00209 01 11-1 January 7, 2009
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Figures
LEGEND:
PROPOSED TUNNEL
- - -PROPOSED PENSTOCK
GOLDEN VALLEY ELECTRIC ASSOCIATION
NENANA RWER HYDROPOWER PROJECT
PROJECT LOCATION
5000 0 5000 10000 FEET
Knigl!( fi!~l?ltl
RE'o/ISIOH
A
n\WIP\Nenono_O I 000\F;gure 2 .1 .dwg
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12,000
10,000
-8,000 tn
'1-
(.) -6,000 3:
0 -4,000 LL
2,000
0
Nenana River-Mean Monthly Streamflow
1950-1979 OAT A Sta. 15518000
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Figure 3.1 -Nenana River Mean Monthly Flows
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45,000
40,000
35,000
30,000 -.!!! 25,000 () -3: 20,000 ..2
LL
15,000
...
~
~ ...
10,000
5,000
0
0% 10%
DV103.00209.0
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20%
Nenana River Near Healy
Flow Duration Curve (May-October)
30% 40% 50% 60%
Percent of Excedence
I---USGS 15518000 I
70%
Figure 3.2 -Nenana River Flow Duration Curve
~~
80% 90% 100%
January 6, 2009
.. · ....
. .. ·' .
2000 0 2000 4000 FEET
G.\ 103\00209.01 \CAO\Des;gn\WIP\Nenono _01 DOO\F;gu<e 4 .1.dwg
LEGEND:
- -PROPOSED ACCESS ROAD
-PROPOSED WEIR LOCATION
- - -PROPOSED TRANSMISSION LINE
EXISTING TRANSMISSION LINE
GOLDEN VALLEY ELECTRIC ASSOC IATI ON
NENANA RWER HYDROPOWER PROJECT
DEStGNED BY I JO
DRAWN BY ! LLT
ACTMTY CODE N/A
ALTERNATIVE 4
CONCEPTUAL SITE PLAN
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LOCATlO'ol I PROJECT NUMBER
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WEIR AND POWERHOUSE
CONCEPTUAL LAYOUT -PLAN
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[L[VATlOOS ffTT, LINLESS
GOLDEN VALLEY ELECTRIC ASSOCIAnON
NENANA RIVER HYDROPOWER PROJECT
WEIR AND POWERHOUSE
CONCEPTUAL LAYOUT -SECTIONS
Knig~tfi#N!l4
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GOLDEN VALLEY ELECTRIC ASSOCIATION
PROJ£CT
NENANA RIVER HYDROPOWER PROJECT
TITLE
SINGLE LINE DIAGRAM
r--:ii:l Knigll( fil~qlt/ ~~~~~ DESIGNED BY LOCATION : PROJECT NIJMSER i F1GVRE NUM6ER >lEV!SION
electric power engineering DRAWN BY I OV103 209.01 I 4.4 A
I (3g~)8 ~31 13:i9s Arvcdo, CO 80001
F'AX {303) 4.31-1836
Knight Piesold
CON.ULTING
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9
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:::2: 5 --[4 -::::s
0 3
~
~ 2
Q.
1
0
J
I
I
I
I
JAN FEB
Nenana River Hydropower Scheme
Average Monthly Power Output
r-r-
r--
r---
r-
MAR APR MAY JUN JUL AUG SEP
Month
Figure 5.1-Average Monthly Power Output
[l
OCT
Notes: 1) Based on mean daily flows for the peri od of record (1 951-1978 ), minus 1000 cfs for fishe ri es requirements.
2) T ransformer efficiency is assumed to be 99 .5 %.
3) Unscheduled outages are assumed to be 3 %.
I
I
I
I
I
NOV DEC
DV1 03.00209.0
Rev 0-Nenana Hydropower Rec on.doc January 6 , 2009
Appendix A
Cost Estimate
Appendix A
RECONNAISSANCE LEVEL OPINION OF PROBABLE CONSTRCTION COSTS
Nenana River Hydroelectric Project
(3 Pit Turbines@ 3.7 MW = 11.1 MW Installed Capacity)
ITEM UNIT QUANTITY tiT RATE
($)
PRELIMINARY & GENERAL
Mobilization and Demobilization L.S. 1 1,380,000
SITE DEVELOPMENT
Access Roads mi 0.80 425,000
POWERHOUSE and ANCILLARY SERVICES
Dewatering L.S. 1 802,000
Excavation L.S. 1 400,000
Foundation Treatment L.S. 1 152,000
Civil Works and Structure L.S. 1 7,623,000
Intake Gate LS. 1 600,000
WEIR
Diversion and Care of Water L.S. 1 221,000
Excavation cyd 20,000 25
Roller Compacted Concrete cyd 10,000 150
Concrete (weir and and abutments) cyd 1,500 1,000
Foundation Treatment LS. 1 175,000
POWER GENERATION (Water to Wire Package) L.S. 1.0 11,700,000
Installation & commissioning LS. 1.0 2,925,000
SWITCHYARD AND TRANSMISSION LINE
Switchyard LS. 1 2,054,000
Transmission Line (138 kV) mile 0.5 335,000
ENVIRONMENTAL COMPONENTS
Fish Passage LS. 1 3,850,000
CONSTRUCTION COST SUBTOTAL
CONTINGENCY (% of Construction Cost) % 25
TOTAL ESTIMATED CONSTRUCTION COST
Engineering, Administration & Construction Management % 15
Licensing and Permits % 4
Legal Fees % 4
Subtotal Other Costs
TOTAL PROJECT COST
Rev 0 ·Final
Print1/7/09 14 30
AMOUNT
($)
1,380,00C
340,00C
802,00C
400,00C
152,00C
7,623,00C
600,000
221,000
500,000
1,500,000
1,500,000
175,000
11,700,000
2,925,000
2,054,000
168,000
3,850,000
$ 35,890,000
$ 8,973,000
$ 44,863,000
$ 6,729,000
$ 1,795,000
$ 1,795,000
$ 10,319,000
$ 55,182,000
Appendix B
Economic Analysis
Project: Nenana River Hydropower Reconnaissance Study
Feature: Economic Analysis Using a Discount Rate of 6 \
Detail:
Pile:
Alt Ro. • 11 .1 MW Installed Capacity
Initial Cost (2008 prices)
Construction cost = $44 1 863,000
Other cost ., SlO. 319 000
Total Project Cost .,
First Year Ann Costs •
Input from Power Analysis:
Average Annual Energy =
Average Mo Capacity =
2008
2009
2010
2011
2012
Year
Year
No
2013
2014
2015
2016
2017 10
2018 11
2019 12
2020 13
2021 14
2022 15
2023 16
2024 17
2025 18
2026 19
2027 20
2028 21
2029 22
2030 23
2031 24
2032 25
2033 26
2034 27
2035 28
2036 29
2037 30
2038 31
2039 32
Net Present Value
Ann Debt
Service
($)
4,0081912
410081912
4,008,912
4,008, 912
410081912
410081912
4,008,912
41008,912
4,008,912
410081912
41008,912
4,008,912
4,008,912
4, 0081912
41008,912
4, 008,912
4, 008,912
41008,912
4,008,912
4, 008,912
41008,912
4,008,912
4,008,912
41008,912
4,008,912
4,008,912
4,008,912
41008,912
4,008,912
41008,912
Benefit Cost Ratio
Costs
Annual
O&M Cost
($)
1461 320
1491246
152,231
1551276
158,381
161,549
164,780
1681076
171,437
1741866
178,363
181,931
1851569
1891281
193' 066
196' 927
2001866
204' 883
208,981
2131161
217,424
221,772
226' 208
230,732
235,347
2401053
244 I ass
249,752
254,747
259,842
Present Worth of Net Benefits, $
Notes:
1. Avoided Cost "' $0. 13/kWh
2. Discount and Interest Rate • 6 t
3. 0 & M Escalation Rate "" 2 t
4. Avoided Cost Escalation Rate • 2t
$55' 182' 000
$146' 320
23' 600' 000 kWh
0 kW
Total
Cost
($)
411551232
4,158,159
411611144
4,164,188
4,1671294
4,170,461
4,173,692
4,176,988
4,1801349
4,183,778
4,187,275
411901843
4,194,481
4,198,193
41201,978
4,205,840
4,209,778
4,213,796
4,217,893
4,2221073
4,226,336
4,230,685
4,2351120
4,239,644
41244,259
4,248,966
4,253,767
4,258,664
4,263,659
4,268,754
$57,686,353
Energy
Revenue
($)
3,068,000
3,129,360
3 ,191, 947
3,255,786
3,320,902
3,387,320
31455,066
3,5241168
3,5941651
3,666,544
3,739,875
3,814,672
3,890,966
3, 968,785
4,048,161
4,1291124
41211,707
4,295,941
4,381,859
414691497
4,558,887
4,650,064
4,743,066
4,837,927
4,934,685
5,033,379
5,134,047
5,236,728
5,341,462
5,448,292
0. 91
(5,176,000)
Salvage Value:
Hydro val• $0
Pi Pel val• $0
Total SV= $0
Revenues
Capacity
Revenue
($)
Job No:
By, CCH
Chkd.By'
Yearly Total
Revenue
($)
3,068,000
3,129,360
311911947
3,2551786
3,320,902
3,387,320
3,455,066
31524,168
3,5941651
3, 666,544
3,739,875
3,814,672
3,890,966
3,9681785
4, 048,161
4,129,124
41211,707
4,295,941
4,381,859
4,469,497
4,558,887
4, 650,064
4,743,066
4,8371927
4,934,685
5,033,379
51134,047
512361728
51341,462
51448,292
$52,510,630
Sheet #":
Date: 12/18/08
Date:
Capacity value mult.
Yearlv Capacity value •
Economic Parameters:
0. 00\
Loan Repayment Period = 3 0 y rs
Avoided Cost of Energy Value • 0.13000 /kWh
Capacity Value = $0.00 /kW-mo
Avoided Cost Escalation Rate •
0 & M Cost Escalation :E
Const. Cost Escalation =
Discount and Interest Rate "'
2 '
2 '
0 '
6 '
Cash Flow
Net
Cash Flow
($)
(1,087,232)
(1' 028' 799)
(969, 196)
(908,402)
(846,392)
(783,141)
(718, 626)
(652,820)
(585,698)
{517,234)
(447,401)
1376,170)
(303,516)
(229,408)
"153,818)
(76, 716)
1, 928
82' 145
163,966
247,424
332,551
419,380
507,946
598,283
690,427
784,413
880' 280
9781064
1,0771803
1,179,538
Accum Net
Cash Flow
($)
(1,087,232)
(2,116,031)
(3,085,227)
(3. 993. 629)
14,840, 021)
(5,623,163)
(6,341,789)
(6,994,609)
(7,580,307)
(8' 097' 541)
18,544,942)
(8, 921, 112)
(9,224,628)
(9,454,036)
(9,607,853)
(9,684,569)
(9,682,640)
(9,600,495)
19,436,529)
(9, 189, lOS)
(8' 856' 555)
(8,437,1751
(7' 929, 229)
(7' 330, 946)
(6, 640, 520)
(5,856,106)
(4,975,826)
(3' 997' 762)
(2,9191959)
(1, 740,421)
5. The average annual energy production period is 167 days, from May 11th through October 24th, and is based on average values for the period of record from 1951 to 1978.
NEW~Nenana Economic Analysis.xls 1211812008
Project: Nenana River Hydropower Reconnaissance Study
Peature: Economic Analy•i• U•ing a Discount Rate of 4 !\
Detail:
Pile:
Alt llo. • 11.1 MW Installed Capacity
Initial Cost (2008 prices )
Construction cost • $44,863,000
Other cost • $10, 319. 000
Total Project Cost •
First Year Ann Costs •
Input from Power Analysis :
2008
2009
2010
2011
2012
2013
2014
Year
Year
No
2015
2016
2017 10
2018 11
2019 12
2020 13
2021 14
2022 15
2023 16
2024 17
2025 18
2026 19
2027 20
2028 21
2029 22
2030 23
2031 24
2032 25
203 3 26
2034 27
2035 28
2036 29
2037 30
2038 31
2039 32
Average Annual Energy •
Average Mo Capac! ty •
Ann Debt
Service
($)
3,191,181
3,191 ,181
3' 191,181
3,191,181
3,191,181
3,191,181
3,191,181
3,191,181
3, 191 ,181
3,191 ,181
3,191,181
3,191,181
3,191,181
3 ,191,181
3,191,181
3' 191, 181
3,191,181
3,191,181
3,191 ,181
3, 191,181
3' 191,181
3,191,181
3,191,181
3, 191,181
3' 191,181
3,191,181
3,191,181
3 ,191,181
.3,191,181
3,191,181
Costs
Annual
O&:M Cost
($)
146,320
149,246
152,231
155.276
158,381
161,549
164,780
168. 076
171,437
174,866
178,363
181,931
185,569
189,281
193,066
196. 927
200,866
204,883
208,981
213,161
217,424
221,772
226,208
230,732
235,347
240' 053
244. 855
249,752
254,747
259,842
Net Present Value
Benefit CO !!It Ratio
Present Worth of Net Benefits, $
Notes:
1 . Avoided Cost • $0 .13/kWh
2. Discount and Interest Rate • 4 t
3. 0 & M Escalation Rate -2 t
4. Avoided Cost Escalation Rate • 2\
S55, 182' 000
S146, 320
23 ,600 ,000 kWh
0 kW
Total
Cost
($)
3,337,501
3,340,427
3,343,412
3,346,456
3 , 349,562
3,352,730
3,355,961
3,359,256
3,362,618
3,366,046
3 ,369,544
3,373,111
3 ,376,750
3 , 380,461
3, 384,247
3,388,108
3,392,047
3 ,396,064
3,400,162
3,404,341
3,408,604
3,412,953
3,417,388
3 ,421,912
3,426,527
3 ,431,234
3. 436,035
3, 440,932
3,445,927
3,451,022
$58.412' 185
Energy
Revenue
($)
3,068,000
3,129,360
3,191,947
3,255,786
3,320,902
3,387,320
3,455,066
3,524,168
3,594,651
3,666,544
3,739,875
3,814,672
3,890,966
3,968,785
4 ,048,161
4 ,129,124
4,211,707
4,295, 941
4 ,381,859
4,469,497
4,558,887
4,650,064
4. 743. 066
4,837,927
4,934,685
5,033,379
5,134,047
5,236,728
5,341,462
5,448, 292
1.16
9, 318,000
Salvage Value:
Hydro val• $0
Pipel val• $0
Total sv. $0
Revenues
Capacity
Revenue
($)
Job No:
By: CCH
Chkd.By '
Yearly Total
Revenue
($)
3,068,000
3,129,360
3, 191,947
3,255,786
3 ,320,902
3,387,320
3,455,066
3,524,168
3,594,651
3,666,544
3, 739,875
3,814,672
3,890,966
3,968,785
4,048,161
4,129,124
4,211,707
4' 295,941
4, 381,859
4,469 ,497
4,558,887
4,650,064
4, 743,066
4,837,927
4,934,685
5,033,379
5,134,047
5,236,728
5,341,462
5,448,292
$67,729,691
Sheet #:
Date: 12/18/08
Date:
Capacity value mult.
Yearlv Caoacitv val\l.fL• _ _____Q__,___Q_Q_t
Economic Parameters:
Loan Repayment Period ,. 3 0 y rs
Avoided Cost of Energy Value • 0.13000 /kWh
Capacity Value •
Avoided Cost Escalation Rate •
0 & M Cost Escalation •
Const . Cost Escalation •
Discount Rate •
$0 . oo /kW-mo
2 '
2 '
0 '
4 '
Cash Flow
Net
Cash Flow
($)
(269,501 )
(211, 067 '
:151,465 )
(90,670 )
(28, 660 )
34' 590
99, 106
164,911
232,033
300,498
370,331
441,561
514,216
588.324
663,914
741,016
819.660
899,877
981,698
1,065,156
1,150,282
1,237,112
1,325,677
1,416,015
1,508,158
1,602,145
1 ,698,012
1 , 795 ,796
1,895,535
1,997,269
Accum Net
Cash Flow
($)
(269,501 )
(480 567 )
(632 ,032 )
(722, 702 )
(751,363 )
(716, 772 )
(617' 667 )
(452 . 755 )
(220' 722 1
79,776
450,107
891,668
1, 405, 884
1,994,208
2, 658,122
3,399,138
4, 218.798
5, 118,675
6,100,373
7,165, 529
8, 315,811
9, 552,923
10,878,600
1212941 614
13,802,773
15,404,918
17,102,930
18,898,725
20,794,260
22,791,530
5. The average annual energy production period is 167 days, from May 11th through October 24th, and is based on average values for the period of record from 1951 to 1978.
NEW-Nenana Economic Anatysis.xls 12/18/2008
Proj•et: Nemma River Hydropowll!lr Reconnaiss:~mce Study
Feature~ Eeonomic Analysis to Calculate Avoided Cost for Positive Cash Flow in Firat Y•
Datail:
File:
Alt No. • ll.l MW Installed Capacity
Initial
Construction cost
cost
Tota: Project Cost
First Year Ann Costs
Input fro'!l Power Analysis:
200B
2009
2010
201::.
2012
2013
201::,
Year
Year
No
2016 9
2017 10
2018 11
2019 12
2020
2021 14
2022
2023 16
2024 17
20/':1 :.a
2026 19
2027 20
2028 21
22
23
2031 24
2032 25
2033 26
2034 ;;.:7
20.35 28
2036 29
2037 30
2038 3:
2039 32
Average Annual
Ave:r-ag~ Mo
A.."ln Debt
Service
I~ I
4' 008' 912
4,0081912
4,008,912
4' 008. 912
4,008,912
4' 912
4' 912
4' !112
4' t 912
4,008,91:).
4,008,912
4,008,912
4,008,912
4,008,912
4,008,912
4,008,912
4,008,912
4,008,912
41006,912
4,008,912
4, 912
4' 008' 912
4,008,912
4,008,912
4,008,912.
41008,912
4,008,912
4' 005,912
912
4,006,912
costs
A.\'mual
C'o~:>r
14£,320
149,246
152,231
155,276
158,381
161,54.9
l64,780
168,0'/6
174,
178,363
181' 931
1851 569
189,281
193' 066
196,927
866
204' 883
208,981
213,1-61
217,424
221,
226' 208
230,732
235,347
~40, 053
244' 855
249,752
254.' '/47
842
No>t Present
Benefit Cost Ratio
Present Worth of Net Benetio::s, S
Notes
1. Avoidt"d Cost-$0,172/kW"h
2. Discount and ::nterest ?:ate 6 l
3. 0 & M Esca!.a~.ion Rate = 2 %
4. Avoided cost Escalat::..on Rate = 2't
pt::ices)
$44,Af3,
$10.319' 000
coo
$146,320
23 1 600, kWh
Total
Cost
4,155,232
4 I 1 SA.
41161,144
154' 188
4,167,294
4, 1'10,461
4,173,692
4117(,,998
4,180,349
4,183,778
'' 4, S43
4,194,481
4,198,193
41 201,978
4,205,840
4,209,778
213' 795
891
4,222,073
4' ':'136
4,230,685
4,235,120
4,239,644
4,24iL259
4, 248,966
4,253,767
4,258,664
4,263,659
268' 754
J53
kW
Energy
RevenuE'
1$1
4.155. 232
4,2'H!,337
4,323,104
4,409,566
41497,757
4,~87,712
4,679,466
4, T/1,056
868,517
4,965,887
5,065,205
5,166,50'9
5,269,839
5,375,236
5,482. 741
'1, 592,396
5,?04,243
!;,18181328
9.34,695
61053,389
6,1"?4,457
6' 297' 946
6,423,905
6,552,383
6,68'3,430
6,817,099
€, 953,441
7,032,51/)
7,234,360
7,379,04.7
1. 23
13,433,
Salvage Vahle
Hydro val=
Pipel val"" $0
Total SV= $0
Revenues
Capacity
Revenue
i$}
Job No:
By:
Chkd.By:
Yearly Total
Revenue
41155,232
4,238,337
4,323 !04
4,409,566
4,497,757
•L 587 I 712
4,679,466
4,773,056
4,868, S17
4,965,887
~,065,205
5, 509
5,269,839
5,375,236
5,48:21741
5,592,396
:3,704,:24:\
!::>,818,328
934,69!1
05J,389
6,174,457
1'1,297,946
6,423,905
6,552,383
6, 6R3, 430
6,817,099
6,953,441
7,092,";:10
., '234, 360
7,379,047
Sheet ;; :
Date: 12/18/08
Date:
Capacity value mult.
Yearly CapacitY value ""
Econorni-:.~ Parameters:
0 Q\
Loan Period 30
Avoided Cost 0.17607
Capacity Vahle
Avoided Cost. Escalation Rat.e =
& M Cost Escalation =
Const. Cost Escalation
Discount
/kW-mo
2 ' 2 %
0 •
G %
Cash Flow
:f{er.
cash Flow
1$1
80,1/A
61,9€0
45,378
30,453
417'
505' 774
596' 068
6B8, l67
782,109
877' 9?.9
975,666
:,075,358
1,1771
1,280,762
1,386,556
1,494,165
1,604,533
1,716,802
1, 316
120
2,067,2[>1
2,198,785
2,312,739
2,439,172
:2,568.
2' 699 J 674
2,833,A46
2,970,701
,1!0,293
Accum Net
Cash Flow
($)
178
242,139
487' 516
817,979
1,235,230
1,741,004
2,337,072
3,025,239
3,807,348
4,685,278
5,660,944
6,736,302
7,91:~,34::!
9' 194,
10,580,661
12,075,:!.28
13,679,661
15,196,462
17,227,778
19,175,399
21124J,160
945
25,714,683
28,183,855
30,751,988
33,451,662
)6,295,508
39,256,2:09
42,366,502
S. The average annual energy production pe:ricd is 167 days, from May r.hrough 24th, and based on average values for the period of record fro!~ 1951 to 1978,
NEW~Nenana Economic Analysis. xis 12118/2008
Appendix C
Photos
Nenana River Diversion Site
Nenana River Instream Site