HomeMy WebLinkAboutTanaa River Hydropower Scheme Reconnaissance Study 2009Knight Piesold
CONSULTING
Rev. No.
Rev A
RevB
RevC
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Golden Valley Electric Association
Tanana River Hydropower Scheme
Tanacross, Alaska
Reconnaissance Study
Date
Final Report
January 7, 2009
Prepared for
Golden Valley Electric Association
P.O. Box 71249
Fairbanks, Alaska 99207
Telephone: (907) 452-1151
Telefax: (907) 451-5657
Prepared by
Knight Ph!sold 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
December 8, 2008 Issued for Internal Review John Dwver
December 18, 2008 Issued for Review/Approval John Dwver
December 22, 2008 Issued for Review/Approval John Dwver
Januarv 7, 2009 Issued as Final John Dwver
Client
Paul Park
Paul Park
Paul Park
Paul Park
Knight Piesold
CONSULTlNG
Golden Valley Electric Association
Tanana River Hydropower Scheme
Tanacross, Alaska
Reconnaissance Study
Final Report
Table of Contents
List of Figures ................................................................................................................................ iv
List of Appendices .......................................................................................................................... v
Executive Summary ........................................................................................................................ I
1.0 Introduction ............................................................................................................................ 1-1
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-l
2.3 Climate ....................................................................................................................... 2-1
2.4 Geology ...................................................................................................................... 2-2
2.4.1 Little Gerstle River Site .............................................................................. 2-2
2.4.2 Cathedral Rapids Site .................................................................................. 2-2
3.0 llydrology and Hydraulics ..................................................................................................... 3-l
3.1 Hydrologic Analysis .................................................................................................. 3-1
4.0 Project Arrangement and Alternatives ................................................................................... 4-l
4.1 Little Gerstle River Alternative ................................................................................. 4-1
4.2 Cathedral Rapids Alternative ..................................................................................... 4-2
4.2.1 Weir ............................................................................................................. 4-2
4.2.2 Powerhouse Structure ................................................................................. 4-3
4.2.3 Turbine Types ............................................................................................. 4-3
4.2.4 Transmission Line ....................................................................................... 4-3
4.2.5 Electrical Equipment ................................................................................... 4-4
4.2.5.1 Single Line Diagram .................................................................... 4-4
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4.2.5.2 Electrical System Layout ............................................................. 4-5
4.2.6 Other Design Considerations ...................................................................... 4-5
5.0 Energy Generation Potential .................................................................................................. 5-I
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 -I
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 ...................................................................................................... 9-1
I 0.0 Certification ....................................................................................................................... I 0-1
11.0 References .......................................................................................................................... Il-l
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List of Figures
Figure Title
2.1 Project Location
3.1 Tanana River near Tanacross -Mean Monthly Streamflow
3.2 Tanana River near Tanacross -Flow Duration Curve
4.1 Little Gerstle River Site Conceptual Layout
4.2 Cathedral Rapids Site-Conceptual Layout
4.3 Tanana River Hydropower Project-Weir and Powerhouse Conceptual Layout
Plan
4.4 Tanana River Hydropower Project -Weir and Powerhouse Conceptual Layout-
Sections
4.5 Tanana River Hydropower Project Single-Line Diagram
5.1 Average Monthly Power Output
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List of Appendices
Appendix Title
A Cost Estimate
B Economic Analysis
C Photos
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Golden Valley Electric Association
Tanana River Hydropower Scheme
Tanacross, Alaska
Reconnaissance Study
Final Report
Executive Summary
This report presents a reconnaissance-level investigation of two alternative sites for the
construction of a small run-of-river hydropower facility on the Tanana River between Fairbanks
and the Canadian border. The two sites are: (I) the Little Gerstle River site, located about
33 miles southeast of Delta Junction; and (2) the Cathedral Rapids site, which is about 50 miles
southeast of the first site. The report includes a description of the physical characteristics of the
two sites and an analysis of the two alternatives. A I so included are a conceptual project layout,
an estimate of power generation, the estimated conceptual costs, and an economic analysis of the
preferred alternative.
The first phase of the study included 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 proposed project sites,
evaluation of flow and head available for power generation and estimation of the potential
turbine and generator capacity. The fatal flaw analysis did not identify technical fatal flaws that
would preclude development of hydropower at either location; however, a hydropower facility at
the Little Gerstle River site would be costly to permit and construct, and would have potentially
significant environmental issues. The Cathedral Rapids site appears to be more suitable for a
hydropower facility; however, this site also has economic issues, as well as environmental
concerns that could be raised during the permitting and public review process. Results of the
fatal flaw analysis were summarized in a memo issued by Knight Piesold in November 2008
(Knight Piesold, 2008).
The Little Gerstle River alternative consists of a 40-to 50-foot high dam and powerhouse on the
Tanana River about 2 miles downstream from the confluence of the Tanana and Little Gerstle
Rivers. Development of a hydropower facility at this site does not appear to be economically or
environmentally feasible due to the site conditions and potential environmental impacts.
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The Cathedral Rapids alternative is a low-head weir and integrated powerhouse located just
upstream from the Cathedral Rapids area on the Tanana River, about 11 miles west of the town
of Tanacross. The mean monthly flow at this location varies from 2,270 cfs (cubic feet per
second) in March to 22,233 cfs in July. The powerhouse would include four pit turbines and
generators, each having a design flow of 3,750 cfs (106m3/sec), a design head of 15 feet (4.57
meters [m]), and an installed capacity of 4,200 kilowatt-hours (kWh), for a total installed
capacity of 16,800 kilowatts (kW). Using 37 years of daily flow data from a nearby USGS
gaging station, the average annual energy production for this facility is estimated to be 52.5
gigawatt-hours (GWh). Based on the 37-year period of record, energy could be produced on 321
days during an average year at this facility. The period with the lowest average flows (and
therefore most likely to be non-producing) is from mid-February through the end of March.
The estimated cost of the Cathedral Rapids alternative is 133 million dollars, considered accurate
to within plus or minus 30 percent. The project would provide emissions-free power with
relatively low operation and maintenance requirements. Assuming an installed capacity of 16.8
megawatts (MW), an avoided cost 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 cash flow
for the first 20 years after startup, a cost benefit ratio of 0.86, and a present net worth of benefits
of minus $19,590,000. Thus, the project is not economically feasible under these assumptions.
The economic feasibility of hydropower at this site depends on the weir height, turbine design
flow, and required transmission line length, as well as on the value of the energy produced and
the bond discount rate. The project might be economically feasible if the weir height and
installed capacity were increased and the energy was sold to the Alaska Power and Telephone
Company for use in the surrounding area, which would reduce the transmission line cost.
Further investigation would be required to evaluate the economics ofthese options.
If GVEA decides to further investigate a hydropower project at the Cathedral Rapids site,
recommendations include the following:
• Conduct further studies to determine if the economics can be improved by increasing
the weir height and/or the design flow
• Contact Alaska Power and Telephone Company to evaluate their interest in
purchasing power from a potential hydropower facility at Cathedral Rapids so that
transmission costs could be reduced
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• 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, seismic
and geologic conditions at the site, and availability of construction materials in the
vicinity ofthe site
• Conduct an investigation of fisheries resources to determine the requirements for
bypass flows
• Investigate the potential effects of sediment loading on the weir, the impoundment
and the turbines
• Identify the specific requirements for permlttmg 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
Tanana River Hydropower Scheme
Tanacross, 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 run-of-river hydropower facility at two
alternative sites on the Tanana River southeast of Fairbanks, Alaska. The two sites were the
Little Gerstle River site and the Cathedral Rapids site.
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 any significant impediments to the project. This phase involved a site
visit, conceptual geologic and geotechnical assessment of the proposed project site, evaluation of
flow and head available for power generation and estimation of the potential turbine and
generator capacity. The fatal flaw analysis did not identify technical fatal flaws that would
preclude development of hydropower at either of the two possible locations; however, the
Cathedral Rapids site appears to be a more suitable location based on preliminary considerations
of construction costs, permitting costs, and potential environmental issues. Results of the fatal
flaw analysis were summarized in a memo issued by Knight Piesold in November 2008 (Knight
Piesold, 2008).
The second phase, presented in this report, includes a more detailed description of the two sites
based on available information and an analysis of the 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 economic analysis.
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 initial site identified by GVEA for the proposed hydropower project on the Tanana River is
located about two miles downstream of its confluence with the Little Gerstle River. In the grant
application, GVEA proposed a 50-foot high dam and power plant at this location. Subsequently,
GVEA proposed an alternate site on the Tanana River near Cathedral Rapids, which is about
50 miles further southeast from the original site, and about II miles west of Tanacross. The
locations of the two alternative sites are shown on Figure 2.1.
2.2 Basin Description
The Tanana River is a tributary of the Yukon River. Its drainage basin area above the gaging
station near Tanacross is 8,550 square miles and includes a portion of the northern slopes and
foothills of the Wrangell Mountains. Its headwaters are located at the confluence of the Chisana
and Nabesna Rivers just north of Northway in eastern Alaska. It flows northwest from near the
border with the Yukon Territory in a wide valley north of the Alaska Range, roughly paralleled
by the Alaska Highway (State Highway 2). In central Alaska, it emerges into a lowland marsh
region known as the Tanana Valley and passes to the south of the city of Fairbanks. It is the
largest populated watershed in interior Alaska.
In the marsh regions it is joined by several large tributaries, including the Nenana River (near the
city of Nenana) and the Kantishna River. It empties into the Yukon approximately 70 miles
downriver from the village of Manley Hot Springs, near the town of Tanana.
Historically, the date when the ice broke on the Tanana River marked the beginning of spring, as
well as the transportation season in Alaska, before the advent of paved roads, trains, and planes.
This event is still celebrated at the Nenana Ice Classic, a game held each year in Nenana to guess
the date when the ice will break. During the history of the Ice Classic, the earliest calendar date
when the ice broke was April 20 in both 1940 and 1998; the latest date was May 20, 1964.
2.3 Climate
The average annual precipitation in the Tanana River watershed ranges from over 50 inches in
the high mountains of the Alaska Range, to 11.05 inches at Tanacross, which has an average
annual snowfall of 33 inches. The climate of Tanacross is typical of interior Alaska, with
seasonal temperature extremes that can range from -70°F in mid-winter to as high as +96°F in
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the summer. Average January temperatures range from -26°F to -5°F. Average July
temperatures range from +44°F to +72°F.
2.4 Geology
The geology of the proposed hydropower sites is characterized by high glaciated terrain in the
Alaska Range and gentle rolling hills to the north. The northwest flowing Tanana River
meanders on the north side of the Alaska Highway between granitic outcrops and glacial
moraines. Within the site region, several peaks rise to more then 5,400 feet asl (above sea level).
The proposed sites were heavily glaciated during the Pleistocene, and deposits of this age are
recognized in the area. Generally, glacial deposits are represented as terminal moraines at the
end of valleys and form broad hummocky zones of low relief. Bedrock in the area consists
mainly of fine-grained biotite and biotite-hornblende granodiorite of Mesozoic age. Surficial
deposits between the granodiorite outcrops consist of alluvial and colluvial deposits up to
approximately 60 feet thick. Permafrost is common in the surficial alluvial and colluvial
deposits in the site area. However, permafrost is most common in the finer-grained sediment
deposits.
2.4.1 Little Gerstle River Site
The general feeling during the site reconnaissance was that constructing a 40 to 50-foot high dam
at this location would not be practical, since it would back up water for a considerable distance
(including flooding over the Alaska Highway), interrupt boating, and likely require a fish
migration facility.
At this proposed hydropower site, the Tanana River flows as a braided stream through a 3i4-mile
wide reach bounded by prominent rock ridges. The east and west boundaries are marked by
granodiorite rock outcrops. Surficial deposits consist of glacial fluvial and floodplain gravelly
alluvial materials. The river deposits are likely tens of feet thick, which would require extensive
and costly excavation and foundation treatment for seepage reduction and control.
2.4.2 Cathedral Rapids Site
This appeared to be a more technically desirable hydropower site than the original site selected
by GVEA. The most viable location for a hydropower facility at this site appears to be near the
bend in the river (at the east end of Cathedral Rapids) where it flows around an "island" during
high discharges. The "island" appears to have been formed by a shift in the river channel,
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leaving an old oxbow-like channel around the south side of the island with the main channel to
the north side. The island is likely a granodiorite knob.
The soils exposed on the south river bank are predominately silts. Further to the south the
topography rises at a moderate slope that is characteristic of a series of coalescing alluvial fans
developed by the streams carrying materials from the mountains, which form the south ridge of
the stream valley. Coalescing fans are deposited mainly by flowing water and debris flows. The
unit consists of unsaturated, poorly stratified, poorly to well-sorted, clast-supported pebbly
cobbles within a silty sand matrix. These materials are likely highly permeable, and thus
seepage through them would need to be considered if a dam is proposed at the site.
The north side of the proposed Cathedral Rapids site is marked by granodiorite rock outcrops,
colluvium, and flood plain alluvium. Surficial deposits at the south side of the site are formed by
coalescing fans and glacial till deposits. The maximum thickness of these deposits is estimated
at 60 to 90 feet. Colluvium units on the north side of the river form steep slopes that may
contain bouldery debris flow deposits. The unit generally consists of poorly stratified, poorly
sorted, clast-supported, cobbly boulder gravels, deposited mainly by mass-wasting processes.
Exposed thickness is approximately 15 feet with an estimated maximum thickness of 60 feet.
This unit is potentially subject to numerous geologic hazards, including rock avalanches, debris
flows, and unstable talus slopes. A recent report released by the Alaska Division of Geological
and Geophysical Surveys (Carver, Bemis et al, 2008) indicates that there is an active fault zone
between Dot Lake and Delta Junction, about 18 miles northwest of the Cathedral Rapids site.
The implications of this fault zone for a proposed facility at Cathedral Rapids should be
addressed during future studies.
A few rock outcrops appear along the north side of the river in the area called Cathedral Bluffs.
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 to the alternative proposed project site is located on the Tanana
River, between Cathedral Rapids Creek No. 1 and No. 2. The United States Geological Survey
(USGS) monitored the flows at this station (No. 15476000) from February 17, 1953 through
September 30, 1990. 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 13,565 cfs. The
mean monthly flow varies from a low of 2,270 cfs in March to a high of 22,233 cfs in July. The
peak recorded flow for the period of record was 49,100 cfs, which occurred on July 25, 1988.
The flow pattern is typical for interior Alaska, with high flows from May through October, and
low flows from November through April. The 8,550 square mile drainage area includes a
number of glaciers in the Wrangell Mountains, 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.
Tanana River Station No. 15476000
Mean Monthly Flow, cfs
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Avg 2,468 2,337 2,270 2,714 8,296 14,780 22,233 20,744 10,428 4,903 3,095 2,628
Max 3,200 3,100 3,100 16,200 21,000 38,600 47,400 35,500 27,000 11,200 5,380 3,800
Min 1,700 1,600 1,400 1,800 2,000 5,940 10,200 6,700 4,850 2,100 2,100 1,800
Mean daily flow records for the Tanana River gaging station 155476000 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 during the months 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. Analysis of
mean daily flows for the period of record (1953-1990) indicates that in an average year, power
could be generated during 321 days. The typical period of non-production due to low flow
conditions is from February 15 to March 31.
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As a starting point, normal flows in the 25-percent exceedance range are typically selected for
analysis of the project installed capacity and energy output. For the flow-duration curve shown
on Figure 3.2, the 25-percent exceedance flow is about 20,000 cfs. Initially, GVEA assumed
design flows varying from 2,500 to 15,000 cfs for the Alternative Energy Grant Proposal for this
project. This design flow would leave significant flow in the river. The flow records indicate
that it might be possible to increase the design flow to about 20,000 cfs. 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 boating and fish. Further studies would be
required to confirm the final design flow for the hydropower facility.
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
summarized in the table below. The I 00-year peak flow estimate ( 45,890 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.
Tanana River near Tanacross, Alaska
Peak Flows for Selected Return Periods
Return 2-yr 5-yr 10-yr 50-yr 100-yr 500-yr Period
Peak
Flow 30,502 34,621 37,349 43,352 45,890 51,754
(cfs)
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4.0 Project Arrangement and Alternatives
Based on the flow data available from the USGS and survey information provided by GVEA on
the river gradient, it appears that viable alternatives for hydropower generation on the Tanana
River are limited. PDC Engineers (PDC Engineers, 2008) surveyed two points along the Tanana
River near Cathedral Rapids. Over a surveyed distance of 2.1 miles, the elevation difference was
6.13 feet, which gives a gradient of 0.06 percent. This very flat gradient makes it impractical to
develop a run-of-river hydro facility with a diversion weir and penstock on this stretch of the
river. Therefore, two alternatives using a dam or weir with an integrated powerhouse were
considered in this study and are described in the following sections. Their locations are shown
on Figure 2.1.
4. 1 Little Gerstle River Alternative
The initial alternative proposed by GVEA is located on the Tanana River about 2 miles
downstream from its confluence with the Little Gerstle River (see Figure 4.1 ). This alternative
consists of a storage dam and a 50 MW hydropower facility. GVEA's estimate of power
generation was based on a minimum head of 50 feet and flow rate from 2,500 to 15,000 cfs. The
annual power output was estimated to be 193,982 megawatt-hours (MWh) based on 8 months at
8.3 MW and 4 months at 50 MW output. This estimate implies that the dam would be at least 50
feet high. As shown on the USGS Mt. Hayes (D-2) Quadrangle, the proposed dam site would be
located in Section 34, T 12 S, R 15 E (see Figure 4.1 ). The contour interval on the available
topographic map is I 00 feet, which makes it difficult to estimate the area that would be
inundated by a 50 foot high dam at this site. As indicated by available mapping, the reservoir
would likely inundate a very large area extending several miles upstream, including the Alaska
Highway, Black Lake, Lake George and Moosehead Lake.
Another significant issue is the large amount of sediment carried by the Tanana River at this site.
It appears that the primary source of sediment is the Johnson River, which enters the Tanana
River about 9 miles upstream of the site. Sediment would likely accumulate rapidly in the
reservoir and cause excessive wear on the turbine runners.
Obtaining a permit to construct a dam at this site would be time consuming and very costly.
Construction of the dam also would be very expensive due to its size and the extensive
foundation excavation and treatment that would likely be required. For these reasons, plus the
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environmental concerns associated with fish habitat, this does not appear to be a very practical or
economical site for construction of a dam and hydropower facility.
4.2 Cathedral Rapids Alternative
The second alternative is located just upstream from Cathedral Rapids on the Tanana River,
about 11 miles west of Tanacross (see Figure 4.2). A hydropower facility at this site would
consist of a low-head concrete weir across the Tanana River with the hydropower facility
integrated into the weir. The key components of this alternative are described in the following
sections.
4.2.1 Weir
The weir would experience a relatively large head range and a very large potential flow
variation. Based on estimates of the channel cross-section at this location, the weir would need
to be a minimum of 25.0 feet above the river bed at its deepest point to maintain a head
differential of about 15.0 feet on the turbines at a design flow of 15,000 cfs.
The flow and head characteristics at the site indicate the use of bulb, "pit'' or S-type turbines
incorporated into the weir. For a design flow of about 15,000 cfs (as assumed by GVEA) and a
net head of about 15 feet, the installed capacity would be about 16.8 MW. The hydropower
facility would consist of four 4.2 MW turbine and generator units. As an alternative, a net head
of 15 feet and a design flow of 20,000 cfs would provide a total installed capacity of about
22.4 MW. A third possible alternative would have a design flow of 20,000 cfs, a net head of
about 25 feet, and a higher weir, for a potential installed capacity of about 36.0 MW. Evaluation
of the last two alternatives would require more detailed study to determine their technical and
economic feasibility.
The maximum weir height is uncertain due to the lack of adequate topographic mapping of the
area. The existing USGS Tanacross (B-6) Quadrangle, dated 1949, has a contour interval of
I 00 feet, with some 50 foot contours. Based on this coarse topography, it appears the weir
height would need to be less than about 50 feet to avoid inundating the Alaska Highway. More
detailed topographic data would be needed to establish the maximum potential height of the weir
at this site. The weir might need to include a portage or bypass channel for boats, and a fish
ladder may be required for fish migration. The weir and hydropower facility would be located at
or just upstream of the island as shown in Figure 4.2.
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4.2.2 Powerhouse Structure
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 shutdown 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 debris from
entering the waterway and damaging the turbines. The conceptual plan view and cross-sections
of the weir and powerhouse are shown in Figures 4.3 and 4.4.
4.2.3 Turbine Types
This site is 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 site on the Tanana 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 this site has three elements in 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
An issue associated with a hydropower facility at this site is the cost to construct 85 miles of
transmission line to connect to GVEA's existing high voltage transmission system in Delta
Junction. As indicated by GVEA in the grant application, the small nearby communities of Dot
Lake, Healy Lake, Tanacross, Tok and other connected villages could be served through a power
purchase agreement between GVEA and Alaska Power and Telephone. This later alternative for
power transmission and usage would likely be the most economical approach for this project.
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4.2.5 Electrical Equipment
The electrical system would be designed to connect the four generators to the GVEA 138
kilovolt (kV) distribution line. 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.
• Switch yard contains a 13.8 to 138kV step-up transformer and 138k V 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 on Figure 4.5.
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 an 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-551 C 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 480 volt (V) station service equipment would be located in a dedicated
electrical room in the powerhouse. 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 reduce cable lengths.
4.2.6 Other Design Considerations
Hydropower facilities in cold climates sometimes include design features to prevent ice
formation on 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 intakes; and log booms can be installed upstream
of the weir trap floating ice. Specific design features to prevent ice formation and to withstand
ice-out should be included in the Feasibility Study and Preliminary Design.
The effects of sediment loading on impoundment storage capacity and on the turbine runners at
the Cathedral Rapids site should be addressed in future studies. A sampling program to
characterize suspended sediment and bedload in the river may be required. A detailed analysis
ofthe effects of sediment loading is beyond the scope ofthis 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 east of Cathedral Rapids upstream of an island in the river. The powerhouse would
include four pit turbines and generators, each having a design flow of 3,750 cfs, a design head of
15 feet, and an installed capacity of 4,200 k W, for a total installed capacity of 16,800 k W.
The mean daily flow data for the entire period of record (1953-1990) was used in the energy
generation calculations. River flows from 20 to 110 percent ofthe design flow (16,500 cfs) were
used to calculate the average annual energy production, which is estimated to be 52.5 GWh.
According to data from the Alaska Department of Fish and Game, anadromous fish species
(coho and chum salmon) are present in the vicinity of Cathedral Rapids, and therefore ten
percent of the design flow ( 1,500 cfs) was subtracted from all mean daily flows to allow for
diversion from the turbine intakes for a fish bypass facility. This value was estimated based on
experience with other projects. Determination of the required flow values for a fish bypass
facility is beyond the scope of this study. It is possible that a flow value greater than I ,500 cfs
would be required, which could adversely effect potential energy production. A more accurate
flow value would need to be determined during future studies in consultation with the Alaska
Department of Fish and Game and other appropriate stakeholders.
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 II 0 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. The efficiency of the generator is about
98 percent at full design flow, but drops to around 94.5 percent at 20 percent of full load. The
combined efficiency is estimated to be 89.3 percent from 60 percent to I 00 percent of design
flow. At 20 percent flow the combined efficiency is estimated to be 78.2 percent. Based on
these values, an overall average efficiency of 86 percent was assumed for the energy generation
calculations.
A constant head of 15 feet was assumed since topographic data were 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. In addition, a
design head of 15 feet and a design flow of 20,000 cfs, and a design head of 25 feet and a design
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flow of 20,000 cfs, were analyzed to investigate the annual energy production for potentially
larger installed capacities. The results of the annual energy production analyses are summarized
in the table below, and the average monthly power output is shown in Figure 5.1.
Design Head
(ft)
15
15
25
Notes:
Tanana River Hydropower Study
Cathedral Rapids Site
Annual Energy Production Summary(!)
Design Flow Installed lnstream Reserve
(cfs) Capacity Flow (cfs)
(MW)
15,000 16.8 1,500
20,000 22.4 1,500
20,000 36.0 1,500
Annual Energy
Production
(GWh)
52.5
57.1
94.4
I) The average annual energy production period is 321 days, based on the period of record from 1953 to 1990. The
most likely period for non-production due to low flow conditions is from February 15 to March 31.
2) Energy production is based on mean daily flows for the period of record, minus I ,500 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 the Cathedral Rapids Alternative was developed for the
proposed hydropower installation 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 shown 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 ofthe following project components:
Mobilization and demobilization
• Access roads
Powerhouse and ancillary facilities
• Weir, 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. Preliminary dimensions and potential site conditions were estimated
from available topographic and geotechnical information. The foundation of the weir was
assumed to extend about 15 feet into the river bed. Costs for the turbines, generators, hydraulic
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pressure units (HPUs), controls and switchgear are based on a budgetary quote from Andritz VA
Tech Hydro Canada, Inc. Switchyard electrical costs were based on a budgetary 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.
The overall project cost was established by adding engineering, permitting, and legal fees. These
fees were estimated to be:
• Engineering at 15 percent of total construction cost with contingency
• Permitting at 4 percent oftotal construction cost with contingency
• Legal at 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 $133,259,000, 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 the Cathedral Rapids Alternative, 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 15,000 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.
Fixed operation and maintenance costs were estimated to be $0.0035/kWh [INEEL, 2003], or
$183,750 for the first year of operation. 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. This study assumes that Golden Valley Electric Association (GVEA) would
operate and maintain the hydropower facilities, and that maintenance would occur during the off-
season.
7.3 Cost-Benefit Evaluation
An economic analysis was completed for the selected alternative assuming a 30-year project life,
a discount rate of 6 percent, and a bond repayment term of 30 years. Energy production was
assumed to begin in 20 I I. Project permitting, planning, engineering and construction were
assumed to consume about two years from early 2009 through 20 I 0. 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 16.8 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
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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.
7.4 Economic Analysis Results
The table below summarizes the results of the economic analysis. 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 9
years after startup is acceptable. The cash flow for the project is positive during the first year if
the avoided cost rate is $0.188 per kWh. Details of the economic analysis are included in
Appendix B.
Tanana River Hydropower Study
Cathedral Rapids Site
Economic Analysis Results for 30 Years of Operation
Installed Average Initial Discount Benefit Present Cash
Capacity Annual Avoided Rate Cost Worth of Net Flow Years of
(MW) Energy Cost (%) Ratio Benefits Negative
(GWh) ($/kWh) ($) Cash Flow
16.8 52.5 0.13 6 0.86 -19,590,000 Negative 20
16.8 52.5 0.13 4 1.10 13,354,000 Negative 8
16.8 52.5 0.188 6 1.24 32,439,000 Positive 0
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8.0 Critical Issues
The following critical issues for the Cathedral Rapids alternative were identified during this
study. These issues could have a significant impact on the design and/or the economic feasibility
ofthe project.
• The economic feasibility of hydropower at this site depends on the weir height,
turbine design flow, and required transmission line length, as well as on the value of
the energy produced and the bond discount rate. The project might be economically
feasible if the weir height and installed capacity were increased and the energy was
sold to the Alaska Power and Telephone Company for use in the surrounding area,
which would reduce the transmission line cost. Further investigation would be
required to evaluate the economics of these options.
• 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, design of the river diversion, seismic and
geologic conditions at the site, and the availability of construction materials in the
vicinity.
• An accurate determination of fish bypass flow requirements is required since
anadromous fish species (coho and chum salmon) 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 Cathedral Rapids site should be addressed. This issue affects the
turbine design as well as possible requirements for flushing or otherwise removing
sediment from the impoundment.
• Specific requirements for permitting and licensing of the 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 proposed Little Gerstle River
site does not appear to be economically or environmentally feasible due to the site
conditions and potential environmental impacts. Construction of a 50-foot high dam
at this site would be technically challenging and costly due to the depth of sediments
likely in the river channel. The large amount of coarse sediment in the river water
would probably make operation of the turbines problematic and costly. The area
inundated by construction of a 50-foot high dam at this location would be relatively
large.
• Development of a hydropower facility at the alternative Cathedral Rapids site appears
to be technically feasible. The estimated cost of the project is $133,259,000,
considered accurate to within plus or minus 30 percent. Assuming an installed
capacity of 16.8 MW, an avoided cost rate of $0.13/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 negative net cash flow for the first 20 years after startup, and a cost benefit
ratio of 0.86. The present worth of net benefits would be -$19,590,000. Thus, the
project would not be economically feasible under these assumptions.
• The economic feasibility of hydropower at the Cathedral Rapids site depends on the
weir height, turbine design flow and required transmission line length, as well as on
the value of the energy produced and the bond discount rate. The project might be
economically feasible if the weir height and installed capacity were increased and the
energy was sold to the Alaska Power and Telephone Company for use in the
surrounding area, which would reduce the transmission line cost. Further
investigation would be required to evaluate the economics of these options.
A more accurate determination of fish bypass flow requirements would be required
for either alternative, since anadromous fish species (coho and chum salmon) are
present in the river at both sites.
• Small hydropower projects are currently eligible for federal Production Tax Credits
(PTCs) of $0.01/kWh during the first ten years of operation. Further investigation
would be required to determine how this could affect the economics of the project.
9.2 Recommendations
If GVEA decides to further investigate a hydropower project at this site, recommendations
include the following:
DV1 03.00209.01 9-1 January 7, 2009
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• Conduct further studies to determine if the economics can be improved by increasing
the weir height and/or the design flow.
• Contact the Alaska Power and Telephone Company to evaluate their interest in
purchasing power from a potential hydropower facility at Cathedral Rapids so that
transmission costs could be reduced.
• Investigate the possible effects 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
we1r.
• 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.
• Determine the federal and state permitting and licensing requirements and contact the
appropriate regulatory agencies and community stakeholders to identify and address
any potential environmental concerns.
• Investigate the potential effects of price volatility of material costs, fuel costs and
electricity prices on the economic feasibility of the project.
DV103.00209.01 9-2 January 7, 2009
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10.0 Certification
This report entitled "Golden Valley Electric Association, Tanana River Hydropower Scheme,
Tanacross, Alaska, Reconnaissance Study, Final Report" was prepared lor 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 that a third party makes of this report, or any reliance on or
decisions made based on it, arc the full responsibility of such third parties. Knight Picsold and
Co. and Golden Valley Electric Association accept no responsibility tor damages, if any,
suffered by any third party as a result of decisions made or actions taken based on this repot1.
This numbered report is a controlled document. Any reproductions of this report are
uncontrolled and may not be the most recent revision.
This report was completed by Knight Piesold and Co. under the coordination of Gilbcrto
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
I
I
Gi).berto Dominguez, P.E.
Pfncipal
DV103.00209.01
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Charles C. Hutton, P.E.
Senior Consultant
January 6. 2009
Knight Piesold
CONSULTING
11.0 References
Carver, G.A., Bemis, S.P., et al, 2008. "Active and Potentially Active Faults in or Near the
Alaska Highway Corridor, Delta Junction to Dot Lake, Alaska." Alaska Department of
Natural Resources, Division of Geological and Geophysical Surveys. Preliminary
Interpretative Report 2008-3d. December, 2008.
Idaho National Engineering and Environmental Laboratory (INEEL), June 2003. "Estimation of
Economic Parameters of US. Hydropower Resources. "
Knight Piesold, October 2008. "Tanana River Hydropower Reconnaissance Study -Technical
~Fatal Flaw Analysis." Memorandum to Golden Valley Electric Association.
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.
USBR, 2002. "Hydropower Construction Cost Trends'', U.S. Bureau of Reclamation,
http://usbr.gov/power/index.html, October 2002.
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.
DV1 03.00209.01 11-1 January 7, 2009
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Figures
TANANA RIVER HYDROPOWER PROJECT
8 0 8 16 JojiL(S
PROJECT LOCATION
Knigl!! f.i!~l!l4
REVISION
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CONSULTING
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20 ,000 -~ 15,000 -;:
..9 10,000
LL
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DV1 03.00209.01
Tanana River Mean Monthly Flow
1953-1990 Sta. 154 76000
Jan Feb Mar Ap r May Jun Ju l Aug Sep Oct Nov Dec
Figure 3.1 -Tanana River Mean Monthly Flows
January 6, 2009
REV 0-Tanana Hydropower Recon-Figure 3.1
Knight Piesold
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50,000
40,000 -Ill .....
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DV103.00209.01
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Tanana River Near Tanacross
Flow Duration Curve (May-October)
----+-------
30 % 40% 50 % 60% 70%
Percent of Excedence
~U SGS 154 76000
80%
Figure 3.2 -Tanana River (Cathedral Rapids) Flow Duration Curve
REV 0-Tanana Hydropower Recon -Figure 3.2
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January 6, 2009
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GOLDEN VALLEY ELECTRIC ASSOCIATION
TANANA RIVER HYDROPOWER PROJECT
SINGLE LINE DIAGRAM
Kni IJt Pibold ~CONSULTING
DESIGNED BY i
DRAWN BY
Rl!\'1S!ON
A
Knight Piesold
CONSULTING
18
16 -~ 14 ;
12 ns en
I--
Cl)
:::!: 10 --;:,
8 Q. -;:,
0 6 ... ; 4 0
D..
2
0 n r::::J
Tanana River Hydropower Scheme
Average Monthly Power Output
.---
-:-----
..-I
~ 1--i----I
' ~ 1--'---
f--
I
f-----
i r--
~ I '
r--
t--H----i ~ ;
i-:-+
!
1-'-----1---~ ~
'
1--1--f--1--
r-1 n
'
.---
f---n
JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV
Month
Figure 5.1 -Average Monthly Power Output
Notes: 1) Based on mean daily flows for the period of record (1953-1990), minus 1,500 cfs for fisheries requirements .
2) Transformer efficiency is assumed to be 99.5 %.
3) Unscheduled outages are assumed to be 3 %.
DV1 03.00209.01
REV 0 -Tanana Hydropower Recon -Figure 5 .1
1
I
i
l
I
I o l
DEC
January 6, 2009
Appendix A
Cost Estimate
Knight Piesold
CONSULTING
APPENDIX A
RECONNAISSANCE LEVEL OPINION OF PROBABLE CONSTRCTION COSTS
Tanana River Hydroelectric Project
(4 Pit Turbines@ 4.2 MW = 16.8 MW Installed Capacity)
ITEM UNIT= QUANTITY I UNIT RATE
($)
PRELIMINARY & GENERAL
Mobilization and Demobilization L.S. 1 3,147,000
SITE DEVELOPMENT
Access Roads miles 1.00 425,000
POWERHOUSE and ANCILLARY SERVICES
Dewatering L.S. 1 1,517,000
Excavation L.S. 1 650,000
Foundation Treatment LS. 1 290,000
Civil Works and Structure L.S. 1 14,520,000
Intake Gate LS. 1 800,000
WEIR
Diversion and Care of Water L.S. 1 474,000
Excavation cyd 25,000 25
Roller Compacted Concrete cyd 16,000 150
Concrete (weir and abutments) cyd 4,500 1,000
Foundation Treatment L.S. 1 376,000
POWER GENERATION (Water to Wire Package) LS. 1.0 17,175,000
Installation & commissioning L.S. 1 4,293,750
SWITCHYARD AND TRANSMISSION LINE
Switchyard L.S. 1 2,154,000
Transmission Line (138 kV) to Della Junction miles 85.0 335,000
ENVIRONMENTAL COMPONENTS
Fish Passage L.S. 1 4,850,000
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
Print 1rl/09 14:58
AMOUNT=
($)
3,147,000
425,000
'"':ml 650,0
290,
14,520,
800,000
474,00(
625,00!
2,400,00(
4,500,00(
376,00(
17,175:~~~
4,294,0
2,154,000
28,475,000
4,850,000
$ 86,672,000
$ 21,668,000
$ 108,340,000
$ 16,251,000
$ 4,334,000
$ 4,334,000
$ 24,919,000
$ 133,259,000
Appendix B
Economic Analyses
Project: Tanana River Cathedral Rapids Hydropower Recon Study
Feature: Economic Analysis using a Discount Rate of 6 \
Detail:
Pile:
Alt Mo ... 16 .8 MW Installed Capacity
Initial Cost (2008 prices)
Construction cost • $108,340,000
Other cost = S24 I 919 I 000
Total Project cost
First Year Ann Costs c
Input from Power Analysis :
Average Annual Energy ..
Average Mo Capacity
2008
2009
2010
Year
Year
No
2011 4
2012 5
2013
2014
2015
2016
2017 10
2018 11
2019 12
2020 13
2021 14
2022 15
2023 16
2024 17
2025 18
2026 19
2027 20
2028 21
2029 22
2030 23
2031 24
2032 25
2033 26
2034 27
2035 28
2036 29
203 7 30
2038 31
2039 32
Ann Debt
Service
($)
9,681,121
9,681,121
9,681,121
9,681,121
9,681,121
9,681,121
9. 681,121
9,681,121
9,681,121
9,681,121
9' 681,121
9' 681, 121
9,681,121
9,681,121
9,681,121
9. 681,121
9. 681,121
9 ,681,121
9,681,121
9,681,121
9,681,121
9,681,121
9' 681,121
9,681,121
9,681,121
9,681,121
9,681,121
9,681,121
9' 681,121
9,681,121
Net Present value
Benefit Cost Ratio
Costs
Annual
OEcM Cost
($)
1831750
187,425
191,174
194' 997
1981897
202' 875
206,932
211,071
215' 292
219,598
223.990
228,470
233.039
2371700
2421454
247,303
252,249
257 ,294
262.440
267,689
273,043
278,504
284' 074
289,755
295' 550
301,461
307,491
313,640
319,913
326,311
Present Worth of Net Benefits, $
Notes:
1. Avoided Cost • $0 .13/kllh
2 . Discowtt and Interest Rate •
3 . 0 & M Escalation Rate = 2 '
4. Avoided Cost Escalation Rate -= 2'
$133' 259' 000
$183,750
52' 500' 000 kWh
0 kll
Total
Cost
($)
9,864,871
9, 868 ,546
9,872,295
9,876,118
9,880,018
9,883,996
9,888,054
9,892,192
9, 896,414
9,900,720
9, 905, 112
9 ,909,591
9,914,161
9,918,822
9,923,576
91928,425
9,933,371
9,938,416
9,943,562
91948,810
9. 954,164
9,959,625
9,965,195
9 ,970,877
9,976,672
9, 982,583
9,988,612
9,994,762
10,001,034
10,007,433
$136,403,990
Energy
Revenue
($)
6,825,000
6,961,500
7, 100. 730
7,242,745
7,387,599
7,535 ,351
7,686,059
71839,780
7,996, 575
8,156,507
8,319,637
8,486,030
8,655, 750
8,828 1865
9' 005.443
9, 185,551
9,369,262
9,556,648
9,747,781
91 9421 736
10,141,591
10,344,423
10,551,311
10, 762,337
10,977' 584
11,1971136
11,421,079
11,649,500
11,882,490
12,120,140
0.86
(19,590,000 )
Salvage Value:
Hydro val= $0
Picel val"" $0
TOtal SV= $0
Revenues
Capacity
Revenue
($)
0
0
Job No:
By: CCII
Chkd.By:
Yearly Total
Revenue
($)
6,825,000
6, 961,500
7,100,730
7,242,745
7,387,599
7' 535,351
7,686,059
7,839,780
7,996,575
8' 156' 507
8,319,637
8,486,030
8,655, 750
8, 828,865
9,005,443
9, 185,551
9,369, 262
9,556,648
9,747,781
9,942,736
10,141,591
10,344,423
10,551,311
10,762,337
10,977,584
11,197,136
11,421,079
11' 649, 500
11' 882 '490
12 ,120,140
$116' 813' 901
Sheet #:
Date: 12/18/08
Date:
Capacity value mult .
Yea:rJ,y Capacity value =
Economic Parameters:
0. 00,
Loan Repayment Period = 3 0 y rs
Energy Value = 0 .1300 0 /kWh
Capacity Value = $0.00 /k.W-rno
Energy Value Escalation =
0 &: M Cost Escalation =
Canst . Cost Bscalat ion
Discount Rate =
2 '
2 ' 0'
6 '
Cash Flow
Net
Cash Flow
($)
(3. 039.871
(2,907,046)
(2,771,565)
(2,633,374)
(2,492,419)
(2,348,645)
(2,201,995)
(2,052,413:
(1,899,838)
(1,744,213)
(1,585,475)
(1,423,562)
(1,258,410)
(1,089,956)
(918,133)
(742' 873)
(564,108)
381' 768
195,781
(6' 074)
187,427
384,798
5861 116
791,461
1, 000,913
1,214, 553
1,432,467
1,654,739
1,881,456
2,112,707
Accum Net
Cash Flow
($)
(3,039,871
(5,946,918)
(8,718,482)
(11, 351, 856)
(13,844,275)
(16,192, 919)
118,394,915)
120,447,327)
(22,347,166)
(24,091,378)
(25,676,853)
(27,100,415)
.28, 358, 825)
(29, 448, 781)
(30,366,914)
(31,109, 788)
(31, 673, 896)
(32, 055, 664)
(32,251,445)
(32, 257. 519)
(32,070,092)
(31,685,294)
(31,099,178)
(30, 307' 717)
(29,306, 804)
(28,092,251)
(26,659, 784)
(25. 005. 046)
(23 ,123' 590)
(21, 010,883
5. The average annual energy production period is 321 days, based on average values for the period of record from 1953 to 1990. The most probable non-production period due to low-flow
conditions is from February 15 to March 31 .
Tanana Cathedral Rapids Econ Anal.xls 12/18/2006
Project: Tanana River Cathedral Rapids Hydropower Recon Study
Feature : Economic Analysis Using a Discount Rate of 4 \
Detail:
Pile:
Alt No . ., 16 .8 MW Installed Capacity
Initial Cost (2008 prices)
Construction cost = $108,340,000
Other cost = S24. 919, 000
Total Project Cost
First Year Ann Costs
Input from Power Analysis:
Average Annual Energy
Average Mo Capacity
Year
Year
No
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017 10
2018 11
2019 12
2020 13
2021 14
2022 15
2023 16
2024 17
2025 18
2026 19
2027 20
2028 21
2029 22
2030 23
2031 24
2032 25
2033 26
2034 27
2035 28
2036 29
2037 30
2038 31
2039 32
Ann Debt
Service
($)
7,706,381
7,706,381
7, 706,381
7,706,381
7' 706,381
7, 706,381
7' 706,381
7' 706,381
7' 706,381
7, 706,381
7,706,381
7' 706,381
7,706,381
7' 706,381
7' 706,381
7, 706,381
7' 706,381
7, 706,381
7' 706,381
7,706,381
7' 706,381
7, 706,381
7, 706,381
7' 706,381
7, 706,381
7,706, 381
7,706,381
7' 706,381
7, 706,381
7,706,381
Net Present Value
Benefit Cost Ratio
costs
Annual
O&M cost
($)
183' 750
187,425
191' 174
194' 997
198' 897
202,875
206' 932
211,071
215,292
219,598
223' 990
228,470
233' 039
237' 700
242,454
247,303
252,249
257,294
262 '440
267,689
273' 043
278,504
284' 074
289,755
295' 550
301,461
307,491
313' 640
319,913
326' 311
Present Worth of Net Benefits, $
Notes:
1. Avoided cost = $0 .13/kWh
2. Discount and Interest Rate = 4
3. 0 & M Escalation Rate = 2 \'
4. Avoided Cost Escalation Rate = 2\
$133' 259' 000
$183,750
52,500,000 kWh
0 kW
Total
Cost
($)
7' 890' 131
7,893,806
7,897,555
7,901,378
7,905,278
7,909,256
7,913,314
7,917,452
7, 921,674
7,925,979
7,930,371
7,934,851
7, 939,421
7,944,081
7' 948,835
7, 953,684
7' 958,631
7' 963' 676
7, 968,821
7, 974,070
7, 979,424
7,984,885
7,990,455
7, 996,136
8, 001,932
8, 007,843
8,013,872
8, 020' 022
8,026,294
8,032,693
$137,315,496
Energy
Revenue
($)
6, 825,000
6, 961,500
7' 100' 730
7,242,745
7,387,599
7,535,351
7' 686,059
7,839,780
7,996,575
8,156' 507
8,319,637
8,486,030
8,655,750
8,828,865
9' 005' 443
9, 185,551
9,369,262
9,556,648
9, 747' 781
9, 942,736
10,141,591
10,344,423
10,551,311
10,762,337
10,977,584
11,197' 136
11,421,079
11,649,500
11,882,490
12,120,140
1.10
13,354,000
Salvage Value:
Hydro val• $0
Pioel val= $0
Total sv-$0
Revenues
Capacity
Revenue
($)
Job NO:
By, CCH
Chkd.By'
Yearly Total
Revenue
($)
6,825,000
6, 961,500
7,100,730
7,242,745
7,387,599
7' 535,351
7' 686,059
7' 839' 780
7, 996,575
8,156, 507
8,319,637
8,486, 030
8,655,750
8,828,865
9,005,443
9,185,551
9,369,262
9,556,648
9, 747' 781
9' 942' 736
10,141,591
10,344,423
10,551,311
10,762,337
10,977' 584
11,197' 136
11,421,079
11,649,500
11,882,490
12,120,140
$150,669,863
Sheet #'
Date:
Date:
12/18/08
Capacity value mult.
Yearlv Caoacitv value =
Economic Parameters:
o. oot
Loan Repayment Period = 3 0 yrs
Energy Value = 0.13000 /kWh
Capacity value = $0.00 /kW-mo
Energy Value Escalation =
0 & M Cost Escalation =
Const. Cost Escalation =
Discount Rate =
2 t
2 t
0 t
4 t
Cash Flow
Net
Cash Flow
($)
(1 ,065,131 )
1932,306 I
(796,8251
(658, 634 I
(517,6791
(373,905 1
(227,2551
(77,672 1
74,902
230,527
389' 266
551,178
716,330
884,784
1,056,607
1,231,867
1' 410' 632
1,592,972
1,778,959
1,968,666
2' 162' 167
2,359,538
2,560,856
2,766,201
2,975,653
3,189,293
3,407,207
3,629,479
3,856,196
4,087,447
Accum Net
cash Flow
($)
(1, 065,1311
(1,997,4371
(2,794,2621
(3,452,8961
(3,970,5741
(4,344,4791
(4,571,7341
(4,649,4061
(4,574,5051
(4 '343' 9771
(3' 954, 712)
(3,403,5331
(2,687,2041
(1,802,420)
(745, 8131
486,054
1,896,686
3,489, 658
5,268, 618
7,237,284
9,399,451
11,758,988
14,319,845
17' 086,046
20,061,699
23,250,992
26,658,199
30,287,677
34,143,873
38,231,321
5. The average annual energy production period is 321 days, based on average values for the period of record from 1953 to 1990. The most probahle non-production period due to low-flow
conditions is from February 15 to March 31.
Tanana Cathedral Rapids Econ Anal.xls 12118/2008
Project: Tanana River Cathedral Rapids Hydropower Recon Study
Feature: Economic Analysis to Calculate Avoided Cost for Positive cash Flow in First Y
Detail:
File:
Alt No. = 16.8 MW Installed. Capacity
Inl.tial cost
Construction cost
Other cost
Total Project cost
First Year Ann Costs
Input from Power Analysis:
2008
2009
2010
2011
2012
2013
2014
Year
Year
No
2015
2016 9
2017 10
2 018 11
2019 12
2020
2021 14
2 022 15
2023 16
2 024 17
2025 18
2026 19
2027 20
2028 21
2029 22
2030 23
2031 24
2012 2S
2033 2&
2034 27
2035 28
2036 29
2037 30
2038
2039 32
Net Present Value
Average Annual Energy
Average Mo Capac~ty
Ann Debt
Service
($)
9,681.121
9,681,121
9,681,121
9.681,121
9,681,121
9,681,121
9,681,121
9,681,121
9,681,121
9 '681, 121
9.691,121
:9,681,121
9,681,121
9,681,121
9,681,121
9,681,121
9,681,121
9' 681' 121
9,681' 121
9,681,121
9,681,:!.21
9,681,121
9,681,121
9.681,121
9,681,121
9,681,121
9' 681, 121
9,681,12.1
9,681,121
9,681,121
Costs
Annual
O&M Cost
($)
1133' 750
187,425
191,174
194,997
198' 897
202,875
206,932
211,071
215,492
2191598
223' 990
228,470
233,039
237' 700
242,454
247'
252,249
257,294
262,440
267,689
273,043
278,504
284' 074
289,755
295' 550
301,461
307,491
313' 640
319,913
326,311
Benefit Cost: Rat:t.o
(2008
000
$133,259,000
$183,750
52,500, 000 kWh
0 ):W
Total
Cost
($}
9,864,871
9,8GR,S46
9,872,295
Sf' 876, 118
9, 880,018
9' 883' 996
9, 888,054
9,892,192
9,896,414
9,900,720
90S, 112
9,909,591
9,914,161
9. 918,822
9, 923,576
9,928,425
9,933,371
9,938,416
9' 943.562
9,948,810
9, 95•C 164
9,959,625
9,965,195
9,970,877
9,976,672
9,982,583
9,988,612
9,994,762
10,001,034
10,007,433
$136,403,990
Present worth of Net. Benefits, $
Notes:
1. Avoided Cost = $0 .184/kWh
Discount and Interest Rate = 6 %
3. o & M Escalation Rate 2 t
4 Avoided cost Escalation Rate = 2%
Energy
Revenue
1$1
9,864,871
10,062,169
10,263,412
10,468,680
10,678,054
891, 61!3
11,109,447
11, 331,6]6
11,558,:269
11,789,434
12,025,223
12,265.728
12,511,042
12,761,263
13,016,488
13.276,818
13,542,354
13,813,201
14,089,465
14,371,255
14,658,680
l4, 951,853
15,250,890
15,555,908
15,867,026
16,184,367
16, ?08, 054
16,838,215
17,174,980
17,518,479
1. 24
32,439,000
Salvage Value:
val• $0
val= $0
Total SV= $0
Revenues
Capacity
Revenue
l$1
Job No:
BT CCH
Chkd. Eyo
Yearly Total
Revenue
1$1
9,864,871
10,06:2,169
10,263,412
10,468,680
10,678,054
10,891,615
11,109,447
11,331,636
11,558,269
11,789,434
12,025,223
12,265,728
12,511,042
12,"161,263
13' 016' 488
13,276,818
13,542,354
13,813,201
14,089,465
14' 371' 255
14' 658' 680
14,951,853
250,890
15,555,908
15,867,026
16,1.84,367
16,508,054
1G.B38,215
17,174,980
518,479
$168,843,092
Sheet #:
Date: 12/18/08
Da,te:
Capacity value rnult.
Yearly Capacity value
Economic Parameters:
Loan Repayment Period
Energy Value
Capacity Value
Energy Value Escalat on •
o & M cost Escalat on
Const. Cost Escalat on
Discount Rate
Cash Flow
Net
Cash Flow
1$1
193.622
391,117
592,562
798,036
1, 007 I 619
1,221,394
1,439,444
1,661,855
1,888,715
2,1.20,112
2,356,136
2,596,881
2,842,441
3,092,913
348,393
3,608,984
3,874,786
4,145,904
4,42.1L444
4,704,516
4,992,228
5,285,695
5,585,032
5,890,)55
6,201,784
6,519,442
6,843,454
7,173,945
7,511,047
Accum Net
Cash r'low
{$}
1931 622
584, 740
1,177,302
1,975,338
2, 982,956
4,204,350
5,643,734
7,305,649
9,194.164
11,314,476
13,670,612
16,267,49)
19,109,935
22,202,847
25.551,241
29,160,224
33,035,010
37' 180,914
41,603,359
46,307,874
51,300,102
56,585,798
62,170,
68,061,184
74. 2G2, 969
80,782,411
87,625,865
94,799,810
102, 857
0. 00%
30 yrs
0.18790 /kWh
$0. oo /kW-mo
2 ~
2 %
0 %
6 %
The average annual energy production period is 321 days, based on average values for the period of record from 1953 to 1990. The most probable non-production period due to low-flow
conditions is from February 15 to March 3L
Tanana Cathedral Rapids Econ Anal.xls 12/1812008
Appendix C
Photos
Tanana-Little Gerstle Rivers Dam and Hydropower Site
Tanana River Cathedral Rapids Site