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Star Earth Energy, LLC
Star Earth Energy, LLC
0
11/1/2010
A Hydropower Feasibility Study of Lake Junaluska Submitted by Randall Alley and Jeffrey Lyle of Star Earth Energy to The Lake Junaluska Assembly
Randall G. Alley, MSEE
Randall G. Alley, MSEE
Star Earth Energy, LLC 1
I. Introduction ..................................................................................................................................................... 3 II. Project Overview ............................................................................................................................................. 3 III. Power Generation Potential .......................................................................................................................... 4
A. Richland Creek Flow Data ........................................................................................................................ 4 B. Pigeon River Flow Data ............................................................................................................................ 5 C. Correlation of Richland to Pigeon Flow ................................................................................................... 6 D. Estimation of Available Water Pressure (Head) ..................................................................................... 7 E. Estimation of Potential Power Output ..................................................................................................... 9
IV. Evaluation of Existing Infrastructure ......................................................................................................... 10 A. Generator Room ....................................................................................................................................... 10 B. Intake Gates ............................................................................................................................................... 11 C. Trash Screen ............................................................................................................................................. 12
V. Evaluation of Turbine Technology Contents
12 A. Kaplan Turbine ........................................................................................................................................ 13 B. Cross-flow Turbine .................................................................................................................................. 14
VI. Regulatory Requirements ........................................................................................................................... 16 A. Federal Regulations ................................................................................................................................. 17
1. Public Utility Regulatory Policies Act of 1978 (PURPA) ...................................................................... 17
2. Federal Energy Regulatory Commission (FERC) ................................................................................ 17
B. State Regulations ..................................................................................................................................... 17 1. NC Department of Environmental and Natural Resources ................................................................. 17
2. NC Utilities Commission ....................................................................................................................... 17
3. Utilities ................................................................................................................................................... 18
4. NC GreenPower ...................................................................................................................................... 18
5. Renewable Energy and Efficiency Portfolio Standard ......................................................................... 18
6. Interconnection Standards .................................................................................................................... 19
7. Permitted Methods of Power Sale ......................................................................................................... 19
VII. Recommended System .............................................................................................................................. 20 VIII. Economic Analysis .................................................................................................................................... 21
A. Estimated System Costs ........................................................................................................................... 21 1. Ossberger/HTS-INC Quote.................................................................................................................... 21
2. Survey of Hydroelectric Costs ............................................................................................................... 21
B. Business Models ....................................................................................................................................... 22 1. Assembly Ownership .............................................................................................................................. 22
2. Power Developer Ownership ................................................................................................................. 22
3. Assembly Lease Arrangement ............................................................................................................... 22
4. Comparison of Business Model Scenarios ............................................................................................ 23
C. Return on Investment (ROI) ................................................................................................................... 23 1. Revenue Predictions ............................................................................................................................... 23
2. Profit and ROI Assumptions ................................................................................................................. 26
IX. Discussion .................................................................................................................................................... 34 A. Suitability of Lake Junaluska Site .......................................................................................................... 34 B. Regulatory Issues ..................................................................................................................................... 34 C. Business Model ......................................................................................................................................... 34 D. Power Sales .............................................................................................................................................. 35 E. Model Risks ............................................................................................................................................... 35 F. Profit and ROI Predictions ...................................................................................................................... 35 G. Conclusions ............................................................................................................................................... 36
X. List of Figures ................................................................................................................................................ 37 XI. List of Tables ................................................................................................................................................ 39 XII. List of Equations ........................................................................................................................................ 39 XIII. Profile of Star Earth Energy, LLC ............................................................................................................ 39
Randall G. Alley, MSEE
2 Star Earth Energy, LLC
XIV. Contact Information ................................................................................................................................ 40 XV. Appendix - Revenue Predictions - 3% Energy Inflation........................................................................... 41 XVI. Appendix - Revenue Projections - 5% Energy Inflation ......................................................................... 42 XVII. Profit and ROI - Non-profit, 3% Energy Inflation ................................................................................. 43 XVIII. Appendix - Profit & ROI - Non-profit, 5% Energy Inflation ................................................................ 45 XIX. Appendix - Ossberger Price Quote ........................................................................................................... 47
A. FERC Hydropower Project Comparison Chart .................................................................................... 48 B. FERC Matrix Comparison Licensing Processes .................................................................................... 49 C. FERC Project History for Lake Junaluska P-3474 ................................................................................ 50
Randall G. Alley, MSEE
Star Earth Energy, LLC 3
A Hydropower Feasibility Study of Lake Junaluska
Submitted by Randall Alley and Jeffrey Lyle of Star Earth Energy to The Lake Junaluska Assembly
I. Introduction
The current economic and environmental situation has motivated companies and non-profit entities to
consider new ways to save money, cut energy usage and become more energy efficient. This strategy
simultaneously makes good business sense and fulfills a civic duty to be a “good neighbor” by being a good
steward to the environment. Taking inventory of under-utilized or untapped energy resources and putting
them to work is an important part of this process. For the Lake Junaluska Assembly, the dam at Lake
Junaluska may represent such an opportunity.
Star Earth Energy (SEE) is pleased to submit this study of the feasibility of hydropower generation using
the Lake Junaluska dam. The study considers the engineering, economic and regulatory issues involved
with a potential hydropower project.
II. Project Overview
The Lake Junaluska dam, completed in 1914, is a concrete structure approximately 550 feet long and 35
feet high. The hydraulic high is approximately 29 feet.1 The reservoir has a drainage are of 39,680 acres, a
surface area of 195 acres and a storage capacity of approximately 4.1 million cubic yards of water. The lake
receives the entire discharge of Richland Creek, which has a flow averaging nearly 104 cubic feet per
second over the last 20 years. While the dam originally had a hydropower generation capability early in
the 20th century, significant power has not been generated there in nearly 100 years.
In the 1980’s, McBess Energy, Inc. lead a hydroelectric project at lake Junaluska. On July 15, 1983, the
FERC issued a 5 MW license exemption for the Lake Junaluska Project, FERC Order No. 3474, with an
authorized installed capacity of 539.5 kilowatts (kW). On March 22, 1991 FERC issued an order allowing
until 12/31/1991 to complete the project. On 5/10/1993 FERC approved a modification of the exemption
“to reflect the as-built installed capacity of 200 kW.” The order mentioned that only one 200kW turbine
had been installed, and it ran at about half capacity during the summer. Finally, on 7/29/1993 the
Assembly applied to surrender the exemption “because the project is no longer economically viable.” This
appeared to be primarily due to the prohibitive cost of the repairing the aging equipment. The surrender
request was granted by on 10/20/1995. In that order they stated that “jurisdiction of the project returns to
the State of North Carolina.” A complete listing of FERC related to the Lake Junaluska Dam can be found
in Appendix C.
Although the license exemption as been surrendered, considerable infrastructure remains, including new
steel slide gates to divert the dam flow through turbines, as well as a trash screen superstructure and a
out-building formerly used for auxiliary diesel power generation. The original generator room remain is
also usable. The existing facilities represent valuable assets in a power generation facility, as such is
important to ascertain their condition and usefulness in a potential hydropower generation project.
1 NC Department of Environmental and Natural Resources, http://www.dlr.enr.state.nc.us/pages/Dams%20-%20inventory%2020080604/NCDAMS20100811.xls.
Randall G. Alley, MSEE
4 Star Earth Energy, LLC
III. Power Generation Potential
The hydro-electric power generation potential2 is directly proportional to the water flow (Q) and pressure
(or head) where H is head in feet, and Q is the flow rate in cubic feet per second (ft3/s) (see Equation 1).
This calculation provides a maximum upper bound for potential power generation, and depends on
accurate values for Q and H.
The following sections demonstrate the process of estimating these parameters. Note that this equation
ignores practical effects that reduce efficiency, such as friction and turbulence. It is important to also
consider these effects and strategies to reduce their impact.
Equation 1
A. Richland Creek Flow Data Water flow data for creeks, rivers and streams of sufficient size is collected and maintained by the US
Geological Survey (USGS), and is available at www.usgs.gov/osw.3 A limited number of water flow
readings were taken in Richland Creek immediately above and below Lake Junaluska over the period
1988-2008. Figure 1 show a plot of flow versus the reading date. Plotted in this way, the data appears very
random and sporadic. A more interesting view is seen when the flow is plotted versus the day of the year,
which reveals the variation resulting from seasonal rainfall patterns. This is shown in Figure 2, which
includes the monthly average flow values.
Figure 1 - Richland Daily Flow Data
Figure 2 - Richland Flow vs. Day of Year
Table 1 summarizes the Richland Creek flow data. The yearly average is 82.7 ft3/s. The flow is quite
variable, ranging from a maximum of 132.0 in December, to a minimum of 43.4.
2 Harvey, Adam. Micro-Hydro Design Manual: A Guide to Small Scale Water Power Schemes, page 5. London: Intermediate
Technology Publications, London, 1993. 3 United State Geological Survey, USGS Surface Water Information, www.usgs.gov/osw.
0
50
100
150
200
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01-Jan-88 01-Jan-91 01-Jan-94 01-Jan-97 02-Jan-00 02-Jan-03 02-Jan-06 02-Jan-09
Flo
w (
ft3
/se
c)
Date of Flow Reading
Richland Creek Flow DataUSGS Data 1988 - 2008
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1 51 101 151 201 251 301 351
Flo
w (
ft3
/se
c)
Day Number
Richland Creek Flow DataUSGS data, 1988-2008
Daily Data
Monthly Average
Correlated Data
Randall G. Alley, MSEE
Star Earth Energy, LLC 5
It is apparent that with only 98 readings available over a twenty year period, the data is insufficient to
estimate the flow with confidence. For example, while the monthly averages show a seasonal
winter/spring flow increase, the large drop that occurs during December appears anomalous.
Yearly Average Flow (ft3/s)
Jan Flow
Feb Flow
Mar Flow
Apr Flow
May Flow
Jun Flow
Jul Flow
Aug Flow
Sep Flow
Oct Flow
Nov Flow
Dec Flow
82.7 132.0 125.4 97.9 117.7 97.5 82.2 50.6 57.1 43.4 53.5 91.3 43.8
Table 1 - Summary of Richland Flow Data
B. Pigeon River Flow Data Daily and monthly flow data measurements from the Pigeon River near Canton are available from 1933 to
the present. Figure 3 plots the flow data from 1933-2008, and is based on single readings taken on the 2nd
day of each month. This data was then averaged to find the monthly values. Figure 4 shows data from
1985-2008 taken each day at 15 minute intervals, from which was computed the daily and monthly
average values. This data contains readings on all of the same days as the Richland data set, making it
ideal for use in the correlation method. Both sets of data are in good agreement, and reveal the seasonal
flow pattern not clear in the Richland Creek Data.
Figure 3 - Pigeon Flow Sampled Monthly
Figure 4 - Pigeon Flow Daily Average
Table 2 summarizes the Pigeon River data. The yearly average is 312.8 ft3/s. The maximum flow of 488.0
occurs in December, while the minimum or 181.9 occurs in August. The ratio of the monthly flows to the
corresponding Richland values is approximately 3 except in March, September and December. Given the
relative proximity of the two streams, the prediction of a ratio of 5 - 7 may be erroneous. In this case the
discrepancy is likely due to the comparison of averages, rather than same day readings.
Yearly Average Flow (ft3/s)
Jan Flow
Feb Flow
Mar Flow
Apr Flow
May Flow
Jun Flow
Jul Flow
Aug Flow
Sep Flow
Oct Flow
Nov Flow
Dec Flow
312.8 429.4 421.8 488.0 393.8 323.8 262.0 185.1 181.9 277.3 202.8 260.0 328.2
Ratio to Richland flow 3.3 3.4 5.0 3.3 3.3 3.2 3.7 3.2 6.4 3.8 2.8 7.5
Table 2 - Summary of Pigeon Flow
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400
600
800
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1200
1 2 3 4 5 6 7 8 9 10 11 12
Flo
w (
ft3
/se
c)
Month
Pigeon River Flow USGS Data 1933 - 2008
Single Reading, sampled monthly
Average Value from 1933-2008
0
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400
600
800
1000
1200
1 31 61 91 121 151 181 211 241 271 301 331 361
Flo
w (
ft3
/se
c)
Day of the Year
Pigeon River Average Daily Flow DataUSGS Data 1985 - 2008
Daily Values
Monthly Average
Randall G. Alley, MSEE
6 Star Earth Energy, LLC
C. Correlation of Richland to Pigeon Flow A better correlation can be arrived at using flow readings taken on the same day. In Figure 5, the flow data
of Richland Creek is plotted versus the Pigeon River flow that occurred on the same day. It is assumed
that the flow in the two streams has a linear relationship since they are in close proximity and experience
similar rain events. The best fit was a line with slope = 0.33, indicating that Richland creek has
approximately 1/3 the flow of the Pigeon at their respective monitoring stations. This value is consistent
with 9 of 12 values derived by a simple ratio of average monthly flows. Figure 6 shows the predicted
monthly flow in Richland Creek using this correlation, along with the monthly averages from the limited
data set. The predicted data tracks the seasonal flow pattern of the Pigeon, and results in higher flows in
December and March, as one might expect during the rainy season.
Table 3 summarized the predicted flows, and compares them with the averages from the original limited
Richland data set. The predicted yearly average is 106.1 ft3/s. The maximum flow of 171.3 occurs in March,
while the minimum of 63.5 occurs in July. The predicted yearly flow is 28% higher than the limited actual
flow data indicated, suggesting that there may be an opportunity to increase size of the generation system
to take advantage of the higher winter and spring flows.
Figure 5 - Correlating Richland to Pigeon Flow
Figure 6 - Richland Creek Predicted Flow
Yearly Average
Flow (ft3/s)
Jan Flow
Feb Flow
Mar Flow
Apr Flow
May Flow
Jun Flow
Jul Flow
Aug Flow
Sep Flow
Oct Flow
Nov Flow
Dec Flow
Richland Data, ft3/s 82.7 132.0 125.4 97.9 117.7 97.5 82.2 50.6 57.1 43.4 53.5 91.3 43.8
Predicted Data, ft3/s 106.1 136.8 152.4 171.3 149.4 110. 86.1 63.5 64.8 72.9 71.8 86.8 107.1
% Change 28.3 3.6 21.5 74.9 27.0 12.8 4.7 25.5 13.6 67.9 34.3 -5.0 144.8
Table 3 - Summary of Richland Predicted vs. Measured Flow
Another useful representation of this data is the “flow duration curve” (FDC). The FDC plots the
percentage of time the river flow meets or exceeds a particular flow (see Figure 7). The data indicates a
flow of at least 50 cfs exist 100% of the time, and a flow of at least 150 cfs exists 20% of the time. The FDC
is a required document in federal hydroelectric permit process.
y = 0.3323xR² = 0.8252
0
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175
200
0 100 200 300 400 500 600
Ric
hla
nd
Cre
ek
Flo
w (
ft3
/s)
Pigeon River Flow (ft3/s)
Estimating Richland Flow from Pigeon FlowMethod: Linear Correlation of data from same day
Richland vs. Pigeon Data
Linear (Richland vs. Pigeon Data)
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60
80
100
120
140
160
180
1 51 101 151 201 251 301 351
Flo
w (
ft3
/se
c)
Day Number
Richland Creek Predicted FlowCorrelated to Pigeon River Flow using USGS data 1985-2008
Daily Data
Monthly Average
Correlated Data
Randall G. Alley, MSEE
Star Earth Energy, LLC 7
Figure 7 - Richland Creek Flow Duration Curve
D. Estimation of Available Water Pressure (Head) Figure 8 shows a representative cross-section of the Lake Junaluska dam generation room, including the
approximate locations of the intake gates, intake pipe or penstock, shut-off valve, turbine and discharge
pipe. The average lake level is about 29 feet above the level of Richland Creek below the dam, and about
20 feet above the generator location. Depending on the type of turbine employed, and its location, the
minimum available “head” water pressure, H, is approximately 20 feet. This value is the vertical height
measured from the lake surface level to the turbine intake. In practice, the potential head is the reduced
by real world loss effects, such as friction due to pipe roughness, valves, bends, pipe constrictions, and
turbulence. Each of these effects must be calculated to find the total loss. The available head is relatively
small for the Lake Junaluska site, as a consequence of this minimization of these losses is an important
goal in the design of a viable system.
Since the material, diameter and length of the penstock has In order to estimate the head loss due to pipe
wall roughness, it is necessary to estimate the friction factor (f), which is related to the flow, the penstock
diameter, and the pipe material. For stainless steel pipe with a diameter of 3 feet or greater, the relevant
friction factor f = 0.01 can be found using a Moody Chart for wall friction. 4 Using Equation 2, the impact
on the practical head available from the penstock pipe material, diameter and length can be calculated.
Figure 9 and Figure 10 show the results of these calculations. The effect of varying the pipe diameter and
length is considered for the case of a 20 ft long stainless steel penstock pipe and a peak flow of 150 ft3/s.
The graphs show the importance using a sufficiently large pipe diameter. In this case, use of a pipe with
diameter 3 ft leads to head losses of 2%. For smaller diameters, the percent loss quickly rises to
unacceptable levels.
Equation 2
The next head loss mechanism to be considered is turbulence. Turbulence is caused by impediments
flow such as entrances, exits, bends, contractions and valves. Table 4shows the loss coefficients
4 Harvey, p. 124.
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125
150
175
200
0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%
Ric
hla
nd
Cre
ek
Flo
w (
ft3
/s)
Flow Duration (% of year)
Richland Creek Flow Duration33% Correlation to Pigeon Data (1933-2009)
Randall G. Alley, MSEE
8 Star Earth Energy, LLC
representing piping features that may be required in this application.5 Equation 3 shows how these interact with the square of flow velocity to create a loss of head.
Figure 11 plots the head loss due to turbulence as a function of pipe diameter and flow. It is clear that
larger pipe diameters reduce the head loss effect. However, at a flow of 150 ft3/s, a pipe diameter of at
least 5.5 ft would be required to reduce the turbulence loss to less than 10%. Whether it would be
financially advantageous to increase the diameter to this extent must be weighed against the frequency of
high flow events and the potential power they would generate.
Figure 8 - Dam Cross-Section (not to scale)
Loss Coefficients
Total Entrance Contraction 45deg Bend Gate Valve
Ktot Kent Kcon Kbend Kvalve
1.2 0.4 0.4 0.3 0.1
Table 4 - Head Loss Coefficients
Equation 3
While a Potential Power number of 179 kW is very promising, this number will be reduced in practice by real world effects. These include the head losses from wall friction and turbulence, as well as operating efficiency losses in the turbine, generator and from system down time. The turbine and generator efficiency strongly depend on the system design and operation, but typical values can be used for an initial estimate. The system up time is assumed to be 50 weeks per year. Equation 4 shows the multiplication effect of these various loss mechanisms. Overall efficiency is estimated to be 77.9 %, not including the head losses discussed above.
5 Harvey, p. 127.
Generator Room
Turbine
Intake Slide Gates
Lake Level
PotentialHead = ~20 ft
Shutoff Valve
Intake Pipe (~20 ft)
Gravel Bed
Discharge
Lake Bottom
Roadway
Randall G. Alley, MSEE
Star Earth Energy, LLC 9
Figure 9 - Head Loss Due to Wall Effects (ft)
Figure 10 - Head Loss Due to Wall Effects (%)
Equation 4
The Potential Power Equation 1 can now be modified to include efficiency and head loss effects by adding
a multiplying term for efficiency (ζ) and using the net head value.
Equation 5
Figure 11 - Head Loss Due to Turbulence (ft)
Total Efficiency
Turbine Efficiency
Generator Efficiency
Utilization Efficiency
0.779 0.90 0.90 0.962
Table 5 - Estimate of Operating Efficiency
E. Estimation of Potential Power Output Figure 12 and Figure 13 show the instantaneous and monthly power generation estimates using the data
and values previously developed above for net head, historical flow, loss effects and efficiency.
0.0
1.0
2.0
3.0
4.0
2.0 2.5 3.0 3.5 4.0
He
ad L
oss
(ft
)
Penstock Pipe Diameter (ft)
Head Loss Due to Wall EffectsL = 20 ft, Q = 150 ft3/s
0
2
4
6
8
10
12
14
16
18
20
2.0 2.5 3.0 3.5 4.0
He
ad L
oss
(%
)
Penstock Pipe Diameter (ft)
Head Loss Due to Wall EffectsL = 20 ft, Q = 150 ft3/s
0.0
2.0
4.0
6.0
8.0
10.0
12.0
3.5 4.0 4.5 5.0 5.5 6.0
He
ad L
oss
(ft
)
Penstock Pipe Diameter (ft)
Head Loss Due to TurbulenceLoss Coefficient = 1.5
Q = 50 ft3/s
Q = 100 ft3/s
Q = 150 ft3/s
Randall G. Alley, MSEE
10 Star Earth Energy, LLC
Figure 12 - Monthly Power Prediction (kWH)
Figure 13 - Instantaneous Power (kW)
IV. Evaluation of Existing Infrastructure
The Lake Junaluska site has the advantage of a substantial existing infrastructure that will reduce the cost
of a new electrification effort. These include steel sliding intake gates necessary to divert the dam flow
through turbines, a trash screen superstructure and the original generator room. In addition, an out-
building formerly used for auxiliary diesel power generation is available. The existing facilities represent
valuable assets in a power generation facility, as such is important to ascertain their condition and
usefulness in a potential hydropower generation project.
Figure 14 - Generator Room
Figure 15 - Generator Room Proposed Layout (topview)
A. Generator Room The generation room is ~20x30 structure situated on the back of the dam (see Figure 8 and Figure 14). It
is readily accessible from the service road, and near the out-building previously used for diesel generation.
It has a two story ceiling amenable to a large crane or wench system, which would be when positioning the
0
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40,000
60,000
80,000
100,000
120,000
140,000
160,000
Jan Mar May Jul Sep Nov
Po
we
r (k
WH
)
Month
Monthly Power Prediction (kWH)
0
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150
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250
Jan Mar May Jul Sep Nov
Po
we
r (k
WH
)
Month
Instantaneous Power Prediction (kW)
Generator Room Top View(not to scale)
Generator Room
Turbine
Intake Slide Gates
Turbine Isolation Valve
Turbine Intake Pipe (~20 ft)
Turbine Discharge
Intake 2 Room
Intake 1 Room
By-Pass Discharge
By-Pass Valve
By-Pass Pipe (~20 ft)
Transition
Randall G. Alley, MSEE
Star Earth Energy, LLC 11
turbine and penstock piping. Metal doors bar access to the interior of the dam where the intake gates are
located. By opening the flow gates, the dam flow will be diverted in to the penstock pipe and hence to the
turbine, as was done in the past. The generator room would be house the turbine, generator, flow piping,
flow and electronic control systems and other electrical components.
B. Intake Gates The intake gates were installed during the modifications performed North Fork Electric, Inc. (NFEI) in
the 1990’s. They measure 8’x10’ and 8’x12’, and are shown in Figure 16, Figure 17, Figure 18 and Figure 19
below (courtesy NFEI 6). Only the left gate will be needed for generation, as the flow into Lake Junaluska
is too small to support the use of both gates. One of the goals of operation is to generate as much power as
possible without affecting the lake level. This can be accomplished by limiting the flow to the turbine to an
amount less than or equal to the incoming flow from Richland Creek. Should the incoming flow exceed
the turbine’s maximum flow capacity, the excess flow can be released over the dam or through other flow
gates. A feedback control can be used to maintain the target lake level while simultaneously maximizing
the power produced.
The various gates that allow flow diversion through the dam are showing signs of age and are only
operated with difficulty. It would be inconvenient to have to make constant manual adjustments to the
flow in order to control the turbine flow while maintaining the target lake level. The manual operation of
the older gates can be avoided by using the second of the new gates, and installing a bypass pipe with an
automated valve. To implement this scheme, automatic flow control would be implemented to satisfy all
of the various requirements, including: lake level control, excess flow diversion, optimization of flow for
power generation, power generation by pass and safety shutdown. This proposed layout is shown in
Figure 15. The intake gates have not been tested in many years. The viability of the system recommended
in this study critically depends on their reliable operation. A functional test of their operation should be
made prior to project approval.
Figure 16 - Intake Gates with Trash Screen Superstructure
Figure 17 - Intake Gate 2
6 North Fork Electric, Inc, http://www.nfei.com/LakeJun1.html.
Randall G. Alley, MSEE
12 Star Earth Energy, LLC
Figure 18 - Intake Gate 1 (interior left)
Figure 19 - Intake Gate 1 (interior right)
Figure 20 - Interior of Trash Screen with Gate Hydraulics Dry Wells
Figure 21 - Close-up of Trash Screen
C. Trash Screen An effective trash screen is necessary to ensure reliable operation by preventing debris from entering and
clogging the turbine. During the last hydro project, a substantial trash screen cage was constructed
surrounding the intake gates (see Figure 16, Figure 20 and Figure 21). During a recent inspection, the
screen cage appeared to be in reasonably good condition. It is possible that additional screening will be
required to remove the smaller items that are not caught by the trash screen’s fairly coarse cage. This
could be implemented in the generator room for convenient servicing.
V. Evaluation of Turbine Technology
The function of the turbine in the hydroelectric system is to convert the potential energy in the water to
mechanical rotational energy. Several types of turbine designs have been developed to accomplish this
task, each with differing strengths and weaknesses. In order to maximize efficiency, the turbine must be
selected carefully to match site conditions, including head, flow and the location.
Randall G. Alley, MSEE
Star Earth Energy, LLC 13
The two major types of turbines are the reaction and impulse turbines. Reaction turbines use the water
pressure to apply force on propeller-like blades, causing them to rotate. Examples of include the Francis
and Kaplan turbines. Impulse turbines work by converting the potential energy in the water into energy
to kinetic energy using high speed water jets. The jets are directed into surfaces or “buckets” mounted on
a circular runner, causing rotation.7 The main types to be considered are the Pelton, Turgo and Cross-
flow turbines. Cross-flow turbines are also known by their inventor’s names, Banki-Michell and
Ossberger turbines.
The operational ranges of these turbines, in terms of head and flow, are shown in Figure 22 8. The
operating point derived from the head and flow values of the Lake Junaluska dam (Head, H = 3.0 m and
Flow, Q = 3.0 m3/s) is marked on the chart, and falls within the Kaplan and Cross-flow operating regime.
Figure 23 is a similar chart9 produced by the Ossberger company in Germany, which similarly identifies
the Kaplan and Ossberger (cross-flow) turbines as possible candidates for the Lake Junaluska project.
Each chart predicts potential output power in the range of 150-200 kW.
A. Kaplan Turbine The Kaplan turbine is a reaction axial-flow device, where the flow though the runner is along the axis of
rotation. Kaplan turbines may be mounted horizontally or vertically. Figure 24 depicts a vertically
mounted Kaplan turbine. The water is ejected into a draft tube, the outlet of which must be submerged. As
a result, the Kaplan does not need to be positioned at the lowest position in order to maximize the
available head. This feature of the Kaplan design could be take full advantage of the available head of the
Lake Junaluska site. This is because the total head would be the height difference measured from the lake
surface level and the surface level of Richland Creek below the dam, rather than to the input of the turbine
located in the generator room. This could increase the head by up to 8 feet, boosting the potential power
output by 40%.
Figure 22 - Turbine Application Chart
Figure 23 - Ossberger Application Chart
7 Guide on How to Develop a Small Hydropower Plant, p. 175, 2004, The European Hydropower Association, http://www.esha.be. 8 Wikipedia - The Free Encyclopedia, Water Turbine, http://en.wikipedia.org/wiki/Water_turbine. 9 Ossberger GmbH & Co, http://www.ossberger.de/cms/en/hydro/kaplan-turbine/range-of-use/.
Randall G. Alley, MSEE
14 Star Earth Energy, LLC
The runner blade (Figure 25) and guide vanes angles can be adjustable, with is referred to as single or
double regulation. This feature allows the turbine to be dynamically tuned to maximize efficiency under
different head or flow conditions. Single regulation allows efficient operation between 30% and 100% of
maximum flow, while double regulation increases the operational flexibility allowing operation as low as
15% of maximum flow. This would also be advantageous, given the variability of flow at Lake Junaluska.
Figure 24 - Kaplan Turbine Cross-section.
Figure 25 - Kaplan Runner.10
B. Cross-flow Turbine The Cross-flow turbine utilizes a cylindrical water wheel or runner with many blades spanning the length
of the cylinder. These are supported by solid disks at each end. The water flow is directed through the
blades at the top of the rotor, and exit at the bottom, passing through the blades a second time. The blades
are designed to capture the energy from the water on each pass, before being ejected. Figure 26 and
Figure 27 illustrate the cross-flow concept. The axis of the runner is coupled to the generator. The cross-
flow turbine has a relative slow rotational speed, which makes it suitable for low head/high flow
applications. A speed increaser is required to boost the rotation to match the requirements of the
generator. Figure 28 shows the Ossberger implementation of the cross-flow runner.
Cross-flow turbines can be configured to act as multiple turbines sharing the same runner. A guide vane
system acts to distribute the incoming flow to 1/3, 2/3 or 3/3 of the full length of the turbine rotor. As the
flow varies, the distributor controls how much of the turbine is in use, allowing dynamic efficiency
optimization. The guide vanes can serve as valves between the penstock pipe and the turbine, and can
shut off the flow entirely if required. A fail-safe weight system can be installed to close the guide vanes in
the event of power loss.
While the peak efficiency of a cross-flow turbine is less than the Kaplan design, the ability to operate at
fraction of the total capacity as the flow varies creates a flat efficiency curve over most of the range of
operation. This is particularly desirable when operating in “run of the river” mode, where the flow to
turbine changes based on rainfall and lake level requirements. 11 Figure 29 shows efficiency data from
Ossberger as a function of flow and how the fractional control of the runner usage serves to optimize
10 Ibid, Guide on How to Develop a Small Hydropower Plant, p. 164. 11 Wikipedia - The Free Encyclopedia, Cross-flow Turbine, http://en.wikipedia.org/wiki/Banki_turbine.
Randall G. Alley, MSEE
Star Earth Energy, LLC 15
efficiency to near 86% across a wide range of operation.12 Finally, Figure 30 shows data from Ossberger
comparing their cross-flow turbine to a standard and double regulated Kaplan. The double regulated
Kaplan has about 5% greater peak efficiency, but the cross-flow is more effective in maintaining efficiency
at lower flows.
Figure 26 - Ossberger Turbine Section13
Figure 27 - Ossberger Cross-section14
Figure 28 - Ossberger Turbine Runner
Figure 29 - Ossberger Turbine Efficiency
12 Ossberger GmbH & Co, http://www.ossberger.de/cms/en/hydro/the-ossberger-turbine-for-asynchronous-and-synchronous-water-plants/. 13 Ibid, Cross-flow Turbine, http://en.wikipedia.org/wiki/Banki_turbine. 14 Ibid, Guide on How to Develop a Small Hydropower Plant, p. 160.
Randall G. Alley, MSEE
16 Star Earth Energy, LLC
Figure 30 - Ossberger Cross-flow vs. Kaplan Efficiency
VI. Regulatory Requirements
The following state and federal regulations govern development of hydropower projects in North
Carolina: 15
State
o Dam Safety Law ( Division of Land Resources )
o Water Use Act of 1967
§ 143-215.11 to 22F {noted as: Part 2. Regulation of Use of Water Resources};
§ 143-215.22G to 22L {noted as: Part 2A. Registration of Water Withdrawals and
Transfers; Regulation of Surface Water Transfers}
Environmental Management Commission
o Water quality certification under section 401 of the Clean Water Act ( Division of Water
Quality )
o State Environmental Policy Act and rules establishing criteria for an environmental
assessment, which may include studies to evaluate environmental impacts.
o Certificate of Public Convenience and Necessity ( N.C. Utilities Commission )
o NC Green Power
o 2007 Senate Bill 3 - Renewable Energy and Efficiency Portfolio Standard
Federal
o Permit subject to section 404 of the Clean Water Act ( U.S. Army Corps of Engineers )
o Federal Power Act ( Federal Energy Regulatory Commission )
15 NC Division of Water Resources, http://www.ncwater.org/About_DWR/Water_Projects_Section/Instream_Flow/introduction.htm
Randall G. Alley, MSEE
Star Earth Energy, LLC 17
A. Federal Regulations
1. Public Utility Regulatory Policies Act of 1978 (PURPA)
PURPA was passed by congress to help provide additional energy resources to the nation as a result of the
energy crisis in the 1970s. The act created the definition “qualifying small power producers”, from which
utilities are required to buy power.”16
2. Federal Energy Regulatory Commission (FERC)
The Division of Hydropower Administration (DHAC) within FERC issues licenses or license exemptions
for the operation of hydropower projects under the provisions of the Federal Power Act (FPA). FERC
licenses most nonfederal hydropower projects located on navigable waterways or federal lands, or
connected to the interstate electric grid (emphasis added).
FERC issues three types of development authorizations: conduit exemptions, 5-megawatt (MW)
exemptions, and licenses. The FERC website describes the process steps to obtain authorization to
construct and operate small/low-impact projects that would result in minor environmental effects (e.g.,
projects that involve little change to water flow and use and are unlikely to affect threatened and
endangered species).
Small project of 5 MW or less may be eligible for a 5-MW exemption. The applicant must propose to
install or add capacity to a project located at a non-federal, pre-2005 dam, or at a natural water feature.
The project can be located on federal lands but cannot be located at a federal dam. The applicant must
have all the real property interests or an option to obtain the interests in any non-federal lands.
Appendix A and B below summarize hydropower projects types and licensing requirements. The FERC
website contains the full details of this process: http://www.ferc.gov/industries/hydropower.asp.
B. State Regulations
1. NC Department of Environmental and Natural Resources
The NC Department of Environmental and Natural Resources (DENR), has been granted jurisdiction over
issues of dam safety as well as water flow and quality. The Division of Land Resources administers and
determines whether a permit to repair or alter a dam is required.17 In addition, the law has requirements
supervised by the Division of Water Resources regarding minimum stream flow. Operation in “run of the
river” mode should satisfy these requirements, but this must be verified with DENR.
2. NC Utilities Commission
A “Certificate of Public Convenience and Necessity” must be granted by the NC Utilities Commission
(NCUC) to qualify as a small power producer. This procedure is governed by NCUC Rule R8-64.18 Senate
Bill 3 passed in 2007, amended the law to create two exemptions for the convenience and necessity
certificate, for “self-generation” and for “nonutility owned renewable generation under 2 MW”. Self-
generation would allow a facility owner to consume the power, assuming it does not involve the utility
grid. The non-utility renewable generation under 2MW would allow a private owner to apply for a
certificate exemption.
16 FERC Website, http://www.ferc.gov/students/energyweregulate/fedacts.htm. 17 NC DENR Website, http://www.dlr.enr.state.nc.us/pages/damsafetyprogram.html. 18 NC Utilities Commission Website, http://www.ncuc.net/ncrules/Chapter08.pdf.
Randall G. Alley, MSEE
18 Star Earth Energy, LLC
NCUC is also charged with setting so-called “Avoided Cost” rates, which represents costs the utility avoids
when purchasing power from another generator. These would include power plant capital costs, fuel and
maintenance. The NCUC last set avoided cost rates in 2008, but hearings are underway to revise and
update them. A ruling on this matter is expected in 2011.
3. Utilities
In order to monetize the power produced by a hydroelectric facility, the power must either be sold or
consumed by the owner of the facility. NC law does not allow private companies to sell power to third
parties. However, PURPA does require the utility to purchase the power at the avoided cost rate, as set by
the NCUC.
The current Progress Energy (PEC) “Energy Credits” for hydroelectric facilities are shown in Table 6
below. These are the power prices PEC which are based avoided cost rates as approved by NCUC, and
apply to hydroelectric facilities using PEC’s transmission system.
Energy Credit Prices for Hydroelectric Facilities using PEC’s transmission system.
Variable
Credit
Fixed Long-Term Credits
5-Year 10-Year 15-Year
On-Peak kWH (cents/kWh) 5.368 5.501 5.730 5.737
Off-Peak kWH (cents/kWh) 4.224 4.291 4.410 4.402
Table 6 - PEC Capacity Credits for Hydroelectric Facilities19
4. NC GreenPower
NC GreenPower (NCGP) is a nonprofit organization established to promote renewable energy through
voluntary contributions. NCGP seeks to augment North Carolina’s existing power supply by incentivizing
renewable energy producers, and marketing the energy and renewable energy credits (RECs) which they
produce.
NCGP currently allows hydroelectric producers to bid on public solicitations or to participate in a
brokered bid process. An agreement to sell the power, or “Power Purchase Agreement” (PPA) must made
with the utility. Energy is sold to the utility, which pays standard avoided cost rates. In addition, NCGP
pays the producer an additional amount as specified in REC bidding process. Unfortunately, the incentive
is currently less than for solar systems, perhaps only in the 2 - 4 cent range per kWH. The power sale price
for hydroelectric power, including the avoided cost and the NCGP “green incentive” can be expected to be
in the 6.0 - 8.0 cent range, depending on the outcome of the bid process. The RECs produced are
transferred to the purchasing party through NCGP and cannot be marketed elsewhere. NCGP contracts
have a duration of 5 years, with an annual renewal option thereafter. It is important to note that as NCGP
depends on volunteer contributions, it does not guarantee contracts.20
5. Renewable Energy and Efficiency Portfolio Standard
In 2007, the NC Legislature enacted comprehensive energy legislation Session Law 2007-397, known as
“Senate Bill 3”. This bill established a Renewable Energy and Efficiency Portfolio Standard (REPS) for NC.
Under this standard, utilities operating in NC must supply 12.5% from renewable energy sources by 2020,
including hydroelectric power. Municipal utilities and electric cooperatives must meet a 10% threshold by
2018. The effect of this legislation is to create a market for Renewable Energy Credits (RECs), defined to
19 Progress Energy Website, http://progress-energy.com/aboutenergy/rates/NC-CSP.pdf. 20 NC GreenPower Website, http://www.ncgreenpower.org/index.php.
Randall G. Alley, MSEE
Star Earth Energy, LLC 19
be 1 MegaWatt Hour (MHh) of power generated from renewable sources. Producers of renewable energy
in NC may choose to sell their RECs to NC utilities or to NC GreenPower to assist in meeting the 2018
goals. 21
Pending “Cap and Trade” legislation in congress may create national REC markets in the future. While the
current market value of RECs is uncertain, they are currently marketed for about $1 - $5 in Texas, and for
considerably more in states like New Jersey. Another bill recently introduced in congress would establish
a national “Renewable Electric Standard” to set minimum national goals for renewable energy production.
A $21/MHh “Alternative Compliance Payment” would be required if energy providers don’t meet the
renewable energy targets. Should this bill come into law, it would effectively set the market ceiling for
RECs at $21. 22
To illustrate the future value of RECs, a 100 kW hydroelectric facility at Lake Junaluska could generate
over 800 RECs per year (800 MHh), with a revenue potential between $800 ($1/REC) and $16,000
($20/REC). Given the uncertainty surrounding future REC markets, an nominal value of $2 per REC is
assumed in the revenue projections below.
6. Interconnection Standards
The NCUC has established interconnection standards for small generators which govern interconnection
to utility transmission systems.
Systems between 10 kW and 2 MW follow the "fast-track” process.
Business generators are required to carry a minimum of $300,000 in comprehensive general
liability insurance.
Utilities are authorized to require an external disconnect switch, billable to the business.
Interconnection application fee apply:
o Generators between 20 kW and 100 kW: $100
o Generators larger than 100 kW but not larger than to 2 MW: $500
RECs remain the property of the system owner, except:
o In the case of net-metered systems, any RECs from net excess generation (NEG) are
granted to the utility once annually. 23
7. Permitted Methods of Power Sale
A business in NC may choose from several methods of selling any hydroelectric power it generates.
a) Sell All - Power Purchase Agreement
Hydroelectric power generators may elect to use a Power Purchase Agreements (PPA), as mandated by
PURPA. The rates are as discussed above, and shown in those shown in Table 6. The generator can sell to
the utility or to NC GreenPower.
b) Sell Excess - Grid Tied, Net Metered
Generators can also elect choose to “Net Meter” the hydroelectric power they generate. This method
allows eligible customers to connect to the grid with an existing metered interconnection. The meter spins
21 DSIRE Website, Database of State Incentives for Renewables and Efficiency, http://www.dsireusa.org/incentives/incentive.cfm?Incentive_Code=NC09R&re=1&ee=1. 22 US Senate Energy Committee Website, http://energy.senate.gov/public/index.cfm?FuseAction=PressReleases.detail&PressRelease_id=0c859aee-4287-4320-90ad-cdc38c3f7409. 23 DSIRE Website, http://www.dsireusa.org/incentives/incentive.cfm?Incentive_Code=NC04R&re=1&ee=1
Randall G. Alley, MSEE
20 Star Earth Energy, LLC
forward when electricity is consumed, and spins backward when power is flowing back to the grid. Net
metered systems are subject to the following requirements:
1 megawatt system capacity limit.
Customers may net meter under any available rate schedule.
Any “net” power generated is credited to the customer’s account, and is usable in the subsequent
months. Any credits remaining at the beginning of the summer rate period are surrendered to the
utility.
For customers using a time-of-use (TOU) demand tariff, on-peak generation is used to offset on-
peak consumption, and off-peak generation is used to offset off-peak consumption. Any
remaining on-peak generation is then used to offset off-peak consumption. Off-peak generation
may only be used to offset off-peak consumption. These rates are very similar to they avoided cost
rates.
Customers not using a TOU demand tariff must surrender all RECs to the utility.
Non-residential systems up to 100 kW, are not subject to any utility standby charges.
Systems larger than 100 kW are subject to utility standby charges consistent with approved rates
charged to customer owned generation system.
c) Sell None - Non-Grid Tied
A customer can generate power and use the power on-site without restriction if the system is not tied to
the utility grid. There are complications with this method, specifically during periods of excess and
insufficient power production. If the system is producing insufficient power to support the electrical load,
a backup source must be available. If the system is producing power in excess of the load requirement, the
additional power must be “dumped” or the system rapidly adjusted to match the load. The systems
necessary to deal with these conditions add cost and complexity to the project.
VII. Recommended System
Based on the above analysis and discussion, a hydroelectric system at the Lake Junaluska Dam would
require a minimum of the following components found in Table 7, or their equivalent.
Item Quantity Manufacturer Description Specification Note
Trashrack 1x - Debris screen - Existing equipment
Intake Gates 2x - Control flow into turbine & bypass
- Existing equipment
Intake Transition 2x custom Gate to penstock transition -
Penstock Piping 2x custom Direct flow to turbine & By-pass
5’ diameter, 40’ Length, Steel or equivalent strength material
-
Penstock Transition 1x Ossberger Transition to Turbine 5’ diameter
Draft Tube 1x Ossberger Outlet from turbine 5’ diameter
Gatevalve 2x Automate flow to turbine & By-pass
5’ Diameter, Automated Positive flow shut-off
Turbine 1x Ossberger Energy extraction from flow SH600 Double-Cell Cross-flow or equivalent Kaplan Turbine
125 kW Peak Output
Turbine Frame 1x Ossberger Turbine mounting
Turbine Control Panel
1x Ossberger Turbine control system
Water Level Regulator
1x Ossberger Head level controller Controls lake level & flow to turbine & by-pass
Speed Increaser 1x Flender Match turbine speed to optimum generator speed
Generator 1x Hitzinger Induction Generator 125 kW, 1200 RPM, 480V/3/60 RTD’s, Overspeed Capability
Electric Switchgear 1x Automatic Load Disconnect
Table 7 - Recommended Equipment
Randall G. Alley, MSEE
Star Earth Energy, LLC 21
VIII. Economic Analysis
A. Estimated System Costs
1. Ossberger/HTS-INC Quote
Ossberger GmbH & Co, a German turbine manufacturer has supplied a quote for a cross-flow turbine
through Hydropower Turbine Systems in Virginia (see Appendix A - Ossberger Price Quote). The quote
assumptions are shown in Table 8, and the scope of supply is listed in Table 9. Ossberger quoted 250,000
EUROs for their system, or $350,350 at current exchange rates. Installation and other required
equipment is not included. Adding an estimated $150,000 for installation and additional equipment
brings the total cost to approximately $500,000. Assuming the quoted peak output power of 114 kW, the
resulting cost per kilowatt is 4,386 $/kW.
2. Survey of Hydroelectric Costs
A comparison of cost surveys taken between 1993 and 2003 have been scaled to 2010 dollars and
compared to estimate for the Lake Junaluska project in Figure 31. The Lake project estimate of $4,386
Input value Unit
Head Level Controller yes -
Grid Parallel Operation yes -
Static Head 20.0 ft
Net Head 19.6 ft
Max. Flow 88 cfs
Min. Flow 9 cfs
Turbine Output 123 kW
Generator Output 114 kW
Turbine Nominal 153 rpm
Generator Nominal Speed 1220 rpm
Table 8 - Ossberger Quote Assumptions
Item Description
1 OSSBERGER Turbine (SH600 double cell)
2 Baseframe
3 OSSBERGER Water Level Regulator (automatic operation)
4 Turbine Control Panel
5 Transition Piece and Draft Tube
6 Service Valve
7 FLENDER Speed Increaser with Couplings
8 HITZINGER Induction Generator 125 kW,1200 RPM, 480V/3/60, RTD’s, overspeed capable
Price Estimate EUR 250,000
US $ $350,305 (exchange rate 10/21/2010)
Table 9 - Ossberger Scope of Supply
Ossberger Equipment 350,305
Additional Equipment 50,000
Installation 100,000
TOTAL $500,305
Cost per kW ($/kW) $4,389
Table 10 - Lake Junaluska Hydroelectric
Cost Estimate (114 kW output)
Figure 31 - Micro Hydro Development Costs (2010)
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
De
velo
pm
en
t C
ost
($
/kW
)
Micro Hydro Development Costs 2010 Dollars
Randall G. Alley, MSEE
22 Star Earth Energy, LLC
$/kW is in close agreement with these studies, which range from $3,000 to $7,000 $/kW with an of
$4,389 $/kW 24.
By way of comparison, typical commercial scale photovoltaic (PV) power systems costs approximately
$6000 per kW, and only operate for an average of 5 hours per day in our area. Thus given a 1 kW system
of each type, the hydroelectric system produces almost 5x greater power output per day, 24 kW/hr/day
compared to 5 kW/hr/day for PV.
B. Business Models The Lake Assembly has two distinct pathways available to develop the hydroelectric potential of the
Junaluska Dam. It can either own the generation equipment itself, or allow a private power developer to
lease the right to generate power at the dam, in which case the power developer owning the generation
equipment. Each model has important ramifications, which are discussed below.
1. Assembly Ownership
One option is for the Assembly to pay to develop the hydroelectric capability, and then own and operate
the system as a small power generator. Being a non-profit entity, no tax advantages such as renewable
energy tax credits, depreciation or other such business write-offs would be available. The Assembly can of
course seek grant monies that may be available to non-profits. As the system owner, the Assembly could
choose any of the three methods of power sale discussed above; “Sell All” using a power purchase
agreement (PPA), “Sell Excess” using Net-metering either through the utility or NC GreenPower, or “Sell
None” where all the power is consumed by on-site loads.
Under the “Sell All - PPA” arrangement, the power would either be sold to the utility at the avoided cost
rate or to NC GreenPower at the avoided cost plus their incentive (1 - 2 cents for hydro).
Under the “Sell Excess - Net Meter” arrangement, the excess power would be sold to the utility typically
for TOU rates as discussed above. In addition to the kil0watt-hour sales, the generation facility has the
possibility to reduce the peak demand charge. However, this requires that the facility have good “up time”
such that it is always producing power during peak periods. If the system is down for even 15 minutes
during a peak period, the demand charge will set accordingly. To successfully employ a peak demand
management strategy, the reliable system with high percent utilization is required. Planned outages would
need to be scheduled during low demand periods, and unplanned outages minimized.
2. Power Developer Ownership
The second option is to contract with a renewable energy developer to own and operate the hydroelectric
equipment, and allowing use of the dam under a lease agreement. The developer would be able to take
advantage of the substantial state and federal renewable energy tax credits, depreciation and other
standard business write-offs. In this case, the only power sale option permitted would be “Sell All.” The
developer would enter into a PPA with the utility, and be paid the standard “avoided cost” rates discussed
above. Alternatively, they could contract with NC GreenPower to receive the avoided cost plus their small
incentive.
3. Assembly Lease Arrangement
A variation of the “Power Developer Ownership” model would to solicit a power developer to build and
own the system, but to lease to the Assembly the right to use and operate the generation facility. For this
to be permissible under existing law, there would have to be a valid lease, in which a contract establishes
24 INEL Website, http://hydropower.inel.gov/resourceassessment/pdfs/project_report-final_with_disclaimer-3jul03.pdf.
Randall G. Alley, MSEE
Star Earth Energy, LLC 23
the lease duration and lease payment amount, as well as any conditions for termination of violation of
terms. Careful legal structuring of this arrangement would be necessary to avoid the appearance of a
power sale arrangement, which would attract the scrutiny of the NCUC. In this case, the power developer
could still take advantage of the tax opportunities mentioned above.
4. Comparison of Business Model Scenarios
Table 11 below lists characteristics of the major scenarios based on the business models discussed above.
The table lists the facility owner, facility operator, how the power is sold and at what price.
Business Model Scenario
Owns Facility
Tax Credits
<<<<
Power Seller >>>>
Power Sale Method
>>>> Power
Consumer
Power Sale Value
($/kW)
Peak Demand
Mitigation
REC
Owner Comment
Assembly Owns & Operates Facility
1 A - A Sell all w/ PPA Utility ~0.055 No A
2 A - A Sell all w/ PPA + NC Green
Utility ~0.075 No NC Green
3 A - A Sell excess w/ Net Meter
Assembly &Utility
~0.08 Yes
A
4 A - - Sell none Assembly ~0.11 Yes
A Must be off-grid, backup complications.
Power Developer Owns & Operates Facility
5 D
Yes (for D)
D Sell all w/ PPA
Utility ~0.055 (same $ as 1)
No D D leases dam from A. D earns tax credits.
6 D
Yes (for D)
D Sell all w/ PPA + NC Green
Utility ~0.075 (same $ as 2)
No NC Green
D leases dam from A. D earns tax credits.
Power Developer Owns & Leases Facility
7 D
Yes (for D)
A
Sell all w/ PPA Utility ~0.055 (same $ as 1)
No A D leases dam from A. D earns tax credits.
A leases facility from D.
8 D
Yes (for D)
A
Sell all w/ PPA + NC Green
Utility ~0.075 (same $ as 2)
No NC Green
D leases dam from A. D earns tax credits.
A leases system from D.
9 D
Yes (for D)
A
Sell excess w/ Net Meter
Assembly &Utility
~0.08 (same $ as 3)
No A
10 D
Yes (for D)
A
Sell none Assembly ~0.11 (same $ as 4)
Yes A Must be off-grid, backup complications.
Abbreviations: A = Assembly, D = Power Developer, PPA - Power Purchase Agreement, NC Green - NC GreenPower Note: Revenue projections are identical for cases with equal Power Sale Values.
Table 11 - Comparison of Business Models
C. Return on Investment (ROI) In order to make sound financial decisions on the merits of such an expensive and complicated project,
the return on investment (ROI) must be considered. Equation 6 shows the method of calculating ROI, and
the Annualized ROI is shown in Equation 7.
Equation 6 - Return on Investment (ROI)
Equation 7 - Annualized ROI
1. Revenue Predictions
A revenue prediction model was developed to predict earnings from power sales including energy
inflation. In this case, “revenue” refers to total earnings over the life of the project. The model input
assumptions were developed in previous sections and include the values for head, flow, friction, efficiency,
and the cost of power. These are shown Table 12, which lists the inputs common to all scenarios, and
Table 13, which list the inputs that vary. Each scenario has five variations (A - F) corresponding to the
differing turbine outputs. The cost of power assumptions correspond to the scenarios outlined above.
Scenarios 5 - 10 are not separately calculated, since their revenue values are identical scenarios 1 -4
Randall G. Alley, MSEE
24 Star Earth Energy, LLC
having the same cost of power value. This will not be so in the case of for-profit ownership of the facility.
Only the Kaplan turbine is simulated, since it has both higher efficiency and head as compared to the
cross-flow turbine. Finally, energy inflation (EI) values from 3% to 5% were evaluated to account for
future uncertainty.
Energy
Inflation (%)
Turbine Type
Gross Head (ft)
Flow (cfs)
Turbine Efficiency
(%)
Generator Efficiency
(%) Utilization
(%)
System Efficiency
(%)
3%, 4%, 5% Kaplan 28 106.1 0.900 0.950 0.962 0.822
Table 12 - Common Revenue Simulation Inputs
Scenario Degrade
REC Value ($)
System Size (kW)
Power Value
($/kWh) Scenario Degrade
REC Value ($)
System Size (kW)
Power Value
($/kWh)
1A 0.00 2.0 250 0.055 3A 0.0 2.0 250 0.08
1A 0.10 2.0 250 0.055 3B 0.0 2.0 225 0.08
1B 0.00 2.0 225 0.055 3C 0.0 2.0 200 0.08
1B 0.10 2.0 225 0.055 3D 0.0 2.0 175 0.08
1C 0.00 2.0 200 0.055 3E 0.0 2.0 150 0.08
1C 0.10 2.0 200 0.055 3F 0.0 2.0 125 0.08
1D 0.00 2.0 175 0.055 4A 0.0 2.0 250 0.11
1D 0.10 2.0 175 0.055 4B 0.0 2.0 225 0.11
1E 0.00 2.0 150 0.055 4C 0.0 2.0 200 0.11
1E 0.10 2.0 150 0.055 4D 0.0 2.0 175 0.11
1F 0.00 2.0 125 0.055 4E 0.0 2.0 150 0.11
1F 0.10 2.0 125 0.055 4F 0.0 2.0 125 0.11
2A 0.00 0.0 250 0.075
2B 0.00 0.0 225 0.075
2C 0.00 0.0 200 0.075
2D 0.00 0.0 175 0.075
2E 0.00 0.0 150 0.075
2F 0.00 0.0 125 0.075
Table 13 - Varying Revenue Simulation Inputs
The “Degrade” parameter is used to evaluate Scenario 1 for the sensitivity of the model to degraded input
values. This is not repeated for other scenarios as the percentage effect will be the same for each turbine
power rating. When the “Degrade input is set to “0.05”, each of the following parameters are increased or
decreased by 05%:
- Decreased: Head, flow, Penstock Diameter, turbine efficiency, generator efficiency, Utilization %, Power Value.
- Increased: Penstock Length, Roughness Factor, Friction Factor Turbulence Factor.
The overall effect negative effect on performance and revenue is significantly larger than .05%, resulting
from the fact that many factors multiply. What results is a “worst case” effect resulting from the
degradation of critical factors simultaneously. The revenue projections for the 4% energy inflation cases
are shown below. The 3% and 5% revenue cases are shown in Appendix XV and XVI.
Randall G. Alley, MSEE
Star Earth Energy, LLC 25
a) Revenue Projections - 4% Energy Inflation
Figure 32 - Revenue Prediction (125 kW, 4% EI)
Figure 33 - Revenue Prediction (150 kW, 4% EI)
Figure 34 - Revenue Prediction (175 kW, 4% EI)
Figure 35 - Revenue Prediction (200 kW, 4% EI)
Figure 36 - Revenue Prediction (225 kW, 4% EI)
Figure 37 - Revenue Prediction (250 kW, 4% EI)
0
1
2
3
4
5
6
7
8
9
0 5 10 15 20 25
Cu
mu
lati
ve R
eve
nu
e ($
M)
Years of Operation
Cumulative Hydroelectric Revenuc125kW Kaplan, 4% Energy Inflation
1_125kW
2_125kW
3_125kW
4_125kW
0
1
2
3
4
5
6
7
8
9
0 5 10 15 20 25
Cu
mu
lati
ve R
eve
nu
e ($
M)
Years of Operation
Cumulative Hydroelectric Revenuc150kW Kaplan, 4% Energy Inflation
1_150kW
2_150kW
3_150kW
4_150kW
0
1
2
3
4
5
6
7
8
9
0 5 10 15 20 25
Cu
mu
lati
ve R
eve
nu
e ($
M)
Years of Operation
Cumulative Hydroelectric Revenuc175kW Kaplan, 4% Energy Inflation
1_175kW
2_175kW
3_175kW
4_175kW
0
1
2
3
4
5
6
7
8
9
0 5 10 15 20 25
Cu
mu
lati
ve R
eve
nu
e ($
M)
Years of Operation
Cumulative Hydroelectric Revenuc200kW Kaplan, 4% Energy Inflation
1_200kW
2_200kW
3_200kW
4_200kW
0
1
2
3
4
5
6
7
8
9
0 5 10 15 20 25
Cu
mu
lati
ve R
eve
nu
e ($
M)
Years of Operation
Cumulative Hydroelectric Revenuc225kW Kaplan, 4% Energy Inflation
1_225kW
2_225kW
3_225kW
4_225kW
0
1
2
3
4
5
6
7
8
9
0 5 10 15 20 25
Cu
mu
lati
ve R
eve
nu
e ($
M)
Years of Operation
Cumulative Hydroelectric Revenuc250kW Kaplan, 4% Energy Inflation
1_250kW
2_250kW
3_250kW
4_250kW
Randall G. Alley, MSEE
26 Star Earth Energy, LLC
b) Degraded Input Revenue Projections - 4% Energy Inflation
Figure 38 - Degraded Inputs (125 kW, 4% EI)
Figure 39 - Degraded Inputs (150 kW, 4% EI)
2. Profit and ROI Assumptions
The profit and ROI predictions use the cost assumptions shown in Table 14. The system cost assumption
is $4,386 per kW of turbine capacity. The yearly maintenance cost is assumed to be 1% of the system cost.
Operating labor cost is assumed to be $12,000 in the first year. Both labor and maintenance are increased
by the inflation assumption of 2%. Profits earn an interest rate based on 20 year Treasury Bond earnings.
The model simulates either non-profit or for-profit ownership. The table shows the tax rate, tax credit and
depreciation values used in the case of for-profit ownership. The Profit and ROI predictions for the 4%
energy inflation, non-profit cases are shown below. The 3% and 5% non-profit cases are contained in
Appendix XVII.
System
Cost per kW ($/kW)
Operating Costs
($)
Maintenance Costs
(% of System)
Inflation Rate (%)
Interest Rate
20 yr T-Bill (%)
Federal Tax Rate
(%)
State Tax Rate
(%)
Federal Energy Credit
(%)
State Energy Credit
(%) Federal
Depreciation State
Depreciation
$4,386 $12,000 1% 2% 3.5% 34% 6.9% 30% 35% MACRS Straight Line
Table 14 - Profit and ROI Simulation Inputs
0
1
2
3
4
5
6
7
8
9
0 5 10 15 20 25
Cu
mu
lati
ve R
eve
nu
e ($
M)
Years of Operation
Cumulative Hydroelectric Revenuc125kW Kaplan, 4% Energy Inflation
1_125kW
2_125kW
3_125kW
4_125kW
0
1
2
3
4
5
6
7
8
9
0 5 10 15 20 25
Cu
mu
lati
ve R
eve
nu
e ($
M)
Years of Operation
Cumulative Hydroelectric Revenuc150kW Kaplan, 4% Energy Inflation
1_150kW
2_150kW
3_150kW
4_150kW
Randall G. Alley, MSEE
Star Earth Energy, LLC 27
a) ROI Predictions - Non-profit Ownership, 4% Energy Inflation
Figure 40 - ROI vs. Turbine (Non-profit, 4% EI)
Figure 41 - Profit vs. Turbine (Non-profit, 4% EI)
Figure 42 - Annualized ROI (Non-profit, 4% EI)
Figure 43 - Simple Payback (Non-profit, 4% EI)
Figure 44 - Profit (Non-profit, S1, 4% EI)
Figure 45 - Simple ROI (Non-profit, S1, 4% EI)
0%
50%
100%
150%
200%
250%
300%
350%
400%
450%
500%
125 150 175 200 225 250
Sim
ple
RO
I (%
)
Turbine Size (kW)
Simple ROI After 25 YearsKaplan Turbine, 4% Energy Inflation
Scenario 4
Scenario 3
Scenario 2
Scenario 1
0
1
2
3
4
5
6
7
8
9
10
125 150 175 200 225 250
Cu
mu
lati
ve 2
5 Y
ear
Pro
fit
($M
illio
ns)
Turbine Size (kW)
Cumulative Profit After 25 YearsKaplan Turbine, 4% Energy Inflation
Scenario 4
Scenario 3
Scenario 2
Scenario 1
0%
2%
4%
6%
8%
10%
12%
14%
16%
18%
20%
22%
24%
125 150 175 200 225 250
Sim
ple
RO
I (%
)
Turbine Size (kW)
Annualized ROI After 25 YearsKaplan Turbine, 4% Energy Inflation
Scenario 4
Scenario 3
Scenario 2
Scenario 1
0
2
4
6
8
10
12
14
250 225 200 175 150 125
Year
s to
Pay
bac
k
Turbine Size (kW)
Simple PaybackKaplan Turbine, 4% Energy Inflation
Scenario 4
Scenario 3
Scenario 2
Scenario 1
0.0
1.0
2.0
3.0
4.0
5.0
6.0
7.0
0 5 10 15 20 25
Cu
mu
lati
ve P
rofi
t ($
Mill
ion
s)
Years of Operation
Cumulative Profit - Scenario 1Kaplan Turbine, 4% Energy Inflation
250 kW
225 kW
200 kW
175 kW
150 kW
125 kW
0%
50%
100%
150%
200%
250%
300%
350%
400%
450%
500%
0 5 10 15 20 25
Sim
ple
RO
I (%
)
Years of Operation
Simple ROI - Scenario 1Kaplan Turbine, 4% Energy Inflation
250 kW
225 kW
200 kW
175 kW
150 kW
125 kW
Randall G. Alley, MSEE
28 Star Earth Energy, LLC
Figure 46 - Profit (Non-profit, S2, 4% EI)
Figure 47 - Simple ROI (Non-profit, S2, 4% EI)
Figure 48 - Profit (Non-profit, S3, 4% EI)
Figure 49 - Simple ROI (Non-profit, S3, 4% EI)
Figure 50 - Profit (Non-profit, S4, 4% EI)
Figure 51 - Simple ROI (Non-profit, S4, 4% EI)
0.0
1.0
2.0
3.0
4.0
5.0
6.0
7.0
0 5 10 15 20 25
Cu
mu
lati
ve P
rofi
t ($
Mill
ion
s)
Years of Operation
Cumulative Profit - Scenario 2Kaplan Turbine, 4% Energy Inflation
250 kW
225 kW
200 kW
175 kW
150 kW
125 kW
0%
50%
100%
150%
200%
250%
300%
350%
400%
450%
500%
0 5 10 15 20 25
Sim
ple
RO
I (%
)
Years of Operation
Simple ROI - Scenario 2Kaplan Turbine, 4% Energy Inflation
250 kW
225 kW
200 kW
175 kW
150 kW
125 kW
0.0
1.0
2.0
3.0
4.0
5.0
6.0
7.0
0 5 10 15 20 25
Cu
mu
lati
ve P
rofi
t ($
Mill
ion
s)
Years of Operation
Cumulative Profit - Scenario 3Kaplan Turbine, 4% Energy Inflation
250 kW
225 kW
200 kW
175 kW
150 kW
125 kW
0%
50%
100%
150%
200%
250%
300%
350%
400%
450%
500%
0 5 10 15 20 25
Sim
ple
RO
I (%
)
Years of Operation
Simple ROI - Scenario 3Kaplan Turbine, 4% Energy Inflation
250 kW
225 kW
200 kW
175 kW
150 kW
125 kW
0.0
1.0
2.0
3.0
4.0
5.0
6.0
7.0
8.0
0 5 10 15 20 25
Cu
mu
lati
ve P
rofi
t ($
Mill
ion
s)
Years of Operation
Cumulative Profit - Scenario 4Kaplan Turbine, 4% Energy Inflation
250 kW
225 kW
200 kW
175 kW
150 kW
125 kW
0%
50%
100%
150%
200%
250%
300%
350%
400%
450%
500%
0 5 10 15 20 25
Sim
ple
RO
I (%
)
Years of Operation
Simple ROI - Scenario 4Kaplan Turbine, 4% Energy Inflation
250 kW
225 kW
200 kW
175 kW
150 kW
125 kW
Randall G. Alley, MSEE
Star Earth Energy, LLC 29
b) Discussion of Non-Profit Ownership Results
The 4% energy inflation simulation results are graphed in the section above, and the 3% and 5% cases are
contained in Appendices XV through XVIII. Table 15 below summarizes the full data set for case of non-
profit ownership of the generation facility. Notable cases are high-lighted in green. Several significant
trends should be noted:
Profits:
o Increase with power value
o Increase with turbine size
o Increase with energy inflation.
25 Year ROI and Annual ROI :
o Increase with power value
o Increase with energy inflation
o Generally decreases for increasing turbine size
o Is optimal for 150 kW turbine size
Years to Simple Payback:
o Decreases with power value
o Decreases with energy inflation
o Decreases with smaller turbine size
(1) Scenario 1
Scenario 1 is the case where the assembly owns the facility and the RECs, and sells power to the utility
under a PPA for $0.055/kWh.
While profit is optimal for the largest turbine, there is not a significant increase in profit for turbines
above 175 kW. Paying more for a larger turbine will increase absolute profits, but will not increase ROI or
reduce time to payback. While higher energy inflation increases the project profit and ROI, it is an
uncontrolled factor and can’t be planned on. While many energy analysts predict future energy inflation
beyond 5%, it is possible that it could also trend lower. This is an important consideration when
evaluating the total project risk.
ROI is optimized by using the 15o kW turbine. For the nominal 4% energy inflation case, the model
predicts a profit of 2.24 $million, a 173% ROI and a payback of 11 years.
(2) Scenario 2
Scenario 2 is the case where the Assembly owns the facility and sells all the power and the RECs to NC
GreenPower under a PPA for an estimated $0.075/kWh.
The trends are consistent with the discussion above. ROI is again optimized by using the 15o kW turbine.
For the nominal 4% energy inflation case, the model predicts a profit of 3.59 $million, a 277% ROI and a
payback of 8 years.
(3) Scenario 3
Scenario 3 is the case where the Assembly owns the facility and uses power and sells the excess to the
utility using net-metering. The larger power value reflects the anticipated savings from reducing power
purchases from the utility, and reducing the peak demand charges.
The trends are as above. ROI is optimized by using the 15o kW turbine. For the nominal 4% energy
inflation case, the model predicts a profit of 4.13 $million, a 318% ROI and a payback of 7 years.
Randall G. Alley, MSEE
30 Star Earth Energy, LLC
(4) Scenario 4
Scenario 4 is the case where the Assembly owns the facility and uses power independently from the utility.
The larger power value reflects the anticipated savings from eliminating utility power purchases and peak
demand charges. There is increased risk in this case of system down time. Backup power generation must
be provided for at additional expense. This is not included in the model, but could add as much as $100k
to $200k to the total cost.
The trends are consistent with the discussion above. ROI is again optimized by using the 15o kW turbine.
For the nominal 4% energy inflation case, the model predicts a profit of 6.44 $million, a 497% ROI and a
payback of 5 years.
Scenario
Power Value
(cents/kW)
Turbine Size (kW)
Estimated Cost ($M)
3% Energy Inflation 4% Energy Inflation 5% Energy Inflation
25 Year Profit ($M)
25 Year ROI (%)
Years to Simple
Payback
25 Year Profit ($M)
25 Year ROI (%)
Years to Simple
Payback
25 Year Profit ($M)
25 Year ROI (%)
Years to Simple
Payback
1 5.5 250 1.097 2.00 106% 13 2.63 139% 12 3.36 177% 12
1 5.5 225 0.987 2.02 115% 13 2.62 150% 12 3.32 190% 11
1 5.5 200 0.877 2.00 125% 12 2.57 161% 11 3.24 203% 11
1 5.5 175 0.768 1.91 132% 11 2.45 169% 11 3.07 212% 10
1 5.5 150 0.658 1.76 135% 11 2.24 173% 11 2.80 216% 10
1 5.5 125 0.548 1.50 131% 11 1.92 167% 10 2.41 210% 10
2 7.5 250 1.097 3.53 186% 10 4.37 231% 10 5.35 282% 9
2 7.5 225 0.987 3.49 200% 9 4.30 246% 9 5.23 300% 9
2 7.5 200 0.877 3.41 214% 9 4.17 262% 9 5.06 317% 8
2 7.5 175 0.768 3.23 223% 9 3.94 272% 8 4.76 329% 8
2 7.5 150 0.658 2.95 228% 8 3.59 277% 8 4.34 335% 8
2 7.5 125 0.548 2.54 221% 8 3.09 270% 8 3.74 326% 8
3 8.0 250 1.097 4.15 219% 9 5.07 267% 9 6.14 324% 9
3 8.0 225 0.987 4.08 234% 9 4.96 284% 8 5.99 343% 8
3 8.0 200 0.877 3.97 249% 8 4.81 301% 8 5.78 362% 8
3 8.0 175 0.768 3.75 259% 8 4.53 313% 8 5.43 375% 7
3 8.0 150 0.658 3.42 264% 8 4.13 318% 7 4.95 381% 7
3 8.0 125 0.548 2.95 257% 7 3.56 310% 7 4.27 372% 7
4 11.0 250 1.097 6.81 359% 7 8.07 426% 7 9.54 503% 6
4 11.0 225 0.987 6.64 380% 6 7.85 449% 6 9.26 530% 6
4 11.0 200 0.877 6.41 401% 6 7.55 473% 6 8.88 557% 6
4 11.0 175 0.768 6.01 416% 6 7.08 489% 6 8.31 575% 6
4 11.0 150 0.658 5.48 422% 6 6.44 497% 5 7.56 583% 5
4 11.0 125 0.548 4.73 412% 5 5.57 485% 5 6.54 570% 5
Table 15 - Summary of Results (Non-profit, Kaplan)
Randall G. Alley, MSEE
Star Earth Energy, LLC 31
c) Profit & ROI Predictions - For-profit Ownership, 4% Energy Inflation
Figure 52 - ROI vs. Turbine (For-profit, 4% EI)
Figure 53 - Profit vs. Turbine (For-profit, 4% EI)
Figure 54 - Annualized ROI (For-profit, 4% EI)
Figure 55 - Simple Payback (For-profit, 4% EI)
Figure 56 - Profit (For-profit, S5, 4% EI)
Figure 57 - ROI (For-profit, S5, 4% EI)
0%
50%
100%
150%
200%
250%
300%
350%
400%
450%
500%
550%
600%
650%
125 150 175 200 225 250
Sim
ple
RO
I (%
)
Turbine Size (kW)
Simple ROI After 25 YearsKaplan Turbine, 4% Energy Inflation
Scenario 4
Scenario 3
Scenario 2
Scenario 1
0
2
4
6
8
10
12
125 150 175 200 225 250
Cu
mu
lati
ve 2
5 Y
ear
Pro
fit
($M
illio
ns)
Turbine Size (kW)
Cumulative Profit After 25 YearsKaplan Turbine, 4% Energy Inflation
Scenario 4
Scenario 3
Scenario 2
Scenario 1
0%
2%
4%
6%
8%
10%
12%
14%
16%
18%
20%
22%
24%
125 150 175 200 225 250
Sim
ple
RO
I (%
)
Turbine Size (kW)
Annualized ROI After 25 YearsKaplan Turbine, 4% Energy Inflation
Scenario 4
Scenario 3
Scenario 2
Scenario 1
0
1
2
3
4
5
250 225 200 175 150 125
Year
s to
Pay
bac
k
Turbine Size (kW)
Simple PaybackKaplan Turbine, 4% Energy Inflation
Scenario 4
Scenario 3
Scenario 2
Scenario 1
0.0
1.0
2.0
3.0
4.0
5.0
6.0
7.0
0 5 10 15 20 25
Cu
mu
lati
ve P
rofi
t ($
Mill
ion
s)
Years of Operation
Cumulative Profit - Scenario 1Kaplan Turbine, 4% Energy Inflation
250 kW
225 kW
200 kW
175 kW
150 kW
125 kW
0%
50%
100%
150%
200%
250%
300%
350%
400%
450%
500%
0 5 10 15 20 25
Sim
ple
RO
I (%
)
Years of Operation
Simple ROI - Scenario 1Kaplan Turbine, 4% Energy Inflation
250 kW
225 kW
200 kW
175 kW
150 kW
125 kW
Randall G. Alley, MSEE
32 Star Earth Energy, LLC
Figure 58 - Profit (For-profit, S6, 4% EI)
Figure 59 - Simple ROI (For-profit, S6, 4% EI)
Figure 60 - Profit (For-profit, S9, 4% EI)
Figure 61 - Simple ROI (For-profit, S9, 4% EI)
Figure 62 - Profit (For-profit, S10, 4% EI)
Figure 63 - Simple ROI (For-profit, S10, 4% EI)
0.0
1.0
2.0
3.0
4.0
5.0
6.0
7.0
0 5 10 15 20 25
Cu
mu
lati
ve P
rofi
t ($
Mill
ion
s)
Years of Operation
Cumulative Profit - Scenario 2Kaplan Turbine, 4% Energy Inflation
250 kW
225 kW
200 kW
175 kW
150 kW
125 kW
0%
50%
100%
150%
200%
250%
300%
350%
400%
450%
500%
0 5 10 15 20 25
Sim
ple
RO
I (%
)
Years of Operation
Simple ROI - Scenario 2Kaplan Turbine, 4% Energy Inflation
250 kW
225 kW
200 kW
175 kW
150 kW
125 kW
0.0
1.0
2.0
3.0
4.0
5.0
6.0
7.0
0 5 10 15 20 25
Cu
mu
lati
ve P
rofi
t ($
Mill
ion
s)
Years of Operation
Cumulative Profit - Scenario 3Kaplan Turbine, 4% Energy Inflation
250 kW
225 kW
200 kW
175 kW
150 kW
125 kW
0%
50%
100%
150%
200%
250%
300%
350%
400%
450%
500%
0 5 10 15 20 25
Sim
ple
RO
I (%
)
Years of Operation
Simple ROI - Scenario 3Kaplan Turbine, 4% Energy Inflation
250 kW
225 kW
200 kW
175 kW
150 kW
125 kW
0.0
1.0
2.0
3.0
4.0
5.0
6.0
7.0
8.0
9.0
10.0
0 5 10 15 20 25
Cu
mu
lati
ve P
rofi
t ($
Mill
ion
s)
Years of Operation
Cumulative Profit - Scenario 4Kaplan Turbine, 4% Energy Inflation
250 kW
225 kW
200 kW
175 kW
150 kW
125 kW
0%
50%
100%
150%
200%
250%
300%
350%
400%
450%
500%
550%
600%
0 5 10 15 20 25
Sim
ple
RO
I (%
)
Years of Operation
Simple ROI - Scenario 4Kaplan Turbine, 4% Energy Inflation
250 kW
225 kW
200 kW
175 kW
150 kW
125 kW
Randall G. Alley, MSEE
Star Earth Energy, LLC 33
d) Discussion of For-Profit Ownership Results
The scenario codes in the graphs in the previous section above should be interpreted as the equivalent
scenarios assuming “power developer” owner ship, i.e. Scenario 1 = Scenario 5, Scenario 2 = 6, Scenario 3
= 9, and Scenario 4 = 10.
The for-profit ownership, 4% energy inflation simulation results are graphed in the section above. Table
16 summarizes the full data set for the case of for-profit ownership of the generation facility. Notable cases
are high-lighted in green. The trends are the same as previously discussed in the non-profit ownership
case. The main difference is the impact of tax credits and depreciation, which dramatically accelerate the
payback and increase the ROI and profit.
Scenario
Power Value
(cents/kW)
Turbine Size (kW)
Estimated Cost ($M)
3% Energy Inflation 4% Energy Inflation 5% Energy Inflation
25 Year Profit ($M)
25 Year ROI (%)
Years to Simple
Payback
25 Year Profit ($M)
25 Year ROI (%)
Years to Simple
Payback
25 Year Profit ($M)
25 Year ROI (%)
Years to Simple
Payback
1 5.5 250 1.097 3.75 184% 4 4.39 216% 4 5.14 253% 4
1 5.5 225 0.987 3.61 193% 4 4.22 226% 4 4.94 264% 4
1 5.5 200 0.877 3.43 201% 4 4.02 236% 4 4.70 275% 4
1 5.5 175 0.768 3.18 206% 4 3.72 241% 4 4.35 282% 4
1 5.5 150 0.658 2.85 207% 4 3.34 242% 4 3.91 284% 4
1 5.5 125 0.548 2.41 198% 4 2.84 233% 4 3.33 274% 4
2 7.5 250 1.097 5.39 265% 4 6.24 307% 4 7.22 356% 4
2 7.5 225 0.987 5.18 277% 4 5.99 321% 4 6.93 371% 4
2 7.5 200 0.877 4.92 289% 4 5.69 334% 4 6.59 386% 3
2 7.5 175 0.768 4.56 296% 3 5.27 342% 3 6.10 396% 3
2 7.5 150 0.658 4.10 298% 3 4.75 344% 3 5.50 399% 3
2 7.5 125 0.548 3.50 288% 3 4.06 334% 3 4.71 388% 3
3 8.0 250 1.097 6.03 297% 4 6.96 343% 4 8.04 396% 4
3 8.0 225 0.987 5.79 310% 3 6.68 358% 3 7.71 413% 3
3 8.0 200 0.877 5.50 323% 3 6.35 372% 3 7.32 430% 3
3 8.0 175 0.768 5.10 331% 3 5.88 382% 3 6.79 440% 3
3 8.0 150 0.658 4.59 333% 3 5.30 384% 3 6.12 444% 3
3 8.0 125 0.548 3.92 323% 3 4.53 373% 3 5.25 432% 3
4 11.0 250 1.097 8.78 432% 3 10.05 495% 3 11.52 567% 3
4 11.0 225 0.987 8.42 451% 3 9.64 516% 3 11.04 591% 3
4 11.0 200 0.877 8.00 469% 3 9.15 537% 3 10.48 615% 3
4 11.0 175 0.768 7.41 481% 3 8.48 550% 3 9.72 631% 3
4 11.0 150 0.658 6.68 485% 3 7.65 555% 3 8.77 636% 3
4 11.0 125 0.548 5.74 472% 3 6.58 541% 3 7.55 621% 3
Table 16 - Summary of Results (For-profit, Kaplan)
(1) Scenario 5 (coded 1 in graphs)
In Scenario 1 is the case where the for-profit company owns the facility, the ROI is again optimized by
using the 15o kW turbine. For the 4% energy inflation case, the model predicts a profit of 3.34 $million, a
49% increase over the non-profit case. The ROI and payback are similarly improved, with values 242%
and 4 years respectively.
(2) Scenario 6 (coded 2 in graphs)
The trends are as above. ROI is again optimized by using the 15o kW turbine. With the inclusion of tax
credits and deductions, the profit prediction improves to 4.75 $million, an increase of 32%. ROI and
payback improved to 344% 3 years, respectively.
Randall G. Alley, MSEE
34 Star Earth Energy, LLC
(3) Scenario 9 (coded 3 in graphs)
The trends are as above. The profit prediction increases to 5.3 $million, ROI to 384%, and payback to 3
years.
(4) Scenario 10 (coded 4 in graphs)
The trends are as above. The profit prediction increases to 6.44 $million, ROI to 497% and payback to 5
years.
IX. Discussion
A. Suitability of Lake Junaluska Site The Lake Junaluska site has the advantage of existing infrastructure in the form of an existing dam, trash
screens, flow gates and an existing power house. The dam has recently undergone substantial repairs and
reinforcement.
Additional equipment in the form of large diameter penstock pipe, automated gate valves to control flow,
and potentially a flow diversion penstock will be needed to support a generation system. Additionally, if a
cross-flow turbine is selected, a 25% increase in head can be achieved by creating a mounting area below
the existing generator room. This would increase the output by a corresponding amount. If a Kaplan
turbine is chosen, the head will be naturally maximized at approximately 28 feet.
While the water pressure, or “feet of head” is considered in the low range, a reasonably healthy, if
somewhat variable, flow helps to compensate for that deficiency. The resulting power output has the
potential to exceed 200 kW (kilowatt), the equivalent of a 1 MW (megawatt) photovoltaic system costing
considerably more. A turbine designed for low head and variable flow should be used to help optimize the
system efficiency, which directly impacts profitability and ROI. Cross-flow and Kaplan turbines can be
designed to meet these criteria.
B. Regulatory Issues No regulatory obstacles have been uncovered. If the project moves forward, a standard permitting process
involving the Federal Energy Resource Commission (FERC), the NC Dept. of Environment and Natural
Resources (DENR) and NC Utilities Commission will be required.
C. Business Model Several different business modes and power sale schemes have been discussed. The Lake Junaluska
Assembly must decide which of these options fits with their needs and expectations. Hydroelectric
systems are capital intensive, and this project is not an exception. Unfortunately, as a non-profit entity,
the Assembly cannot take advantage of federal and state tax credits. The reasonably healthy profit
projections may mitigate this disadvantage somewhat. Any grants that could be secured to help defray the
initial system cost would obviously improve the profit projections.
There is the possibility of allowing a private power developer to capitalize the project, and either operate
the facility with a site lease from the Assembly, or lease the facility to the Assembly to operate. This
arrangement would require careful legal construction, as the NCUC would prohibit the “sale of power”
from a developer to the Assembly. Alternatively, it should be possible for the Assembly to lease the
generation facility, and use or sell any power it produces.
Randall G. Alley, MSEE
Star Earth Energy, LLC 35
D. Power Sales The regulatory climate in NC for sale of hydroelectric power is quite complex, and to a great extent,
dependent on the utility and the NCUC. While the utility is required by PURPA to purchase power from
“qualified facilities”, the avoided costs it must pay are quite modest. The utility will also seek to apply
demand and standby charges to recover additional revenue from hydroelectric producers. This study has
considered several different approaches to increasing the power sale price, including selling to NC
GreenPower, allowing a power developer to sell the power, or consuming the facility output partially or
entirely. The Assembly will have to decide which approach best meets its requirements should it decide to
move forward with the project.
E. Model Risks The power output, revenue and profit models depend on input assumptions about head, flow, system
efficiency, value of power and energy inflation. Accordingly, the accuracy predictions of power and profit
are subject to the potential risk of compounded error associated with the input assumptions. Any
decisions using this data should be made with those risks in mind. The goal of study has been to maximize
the power output and profitability, while attempting to be accurate and conservative with predictions. To
mitigate this risk, the cases resulting in lower output and profit predictions should be considered possible
outcomes.
F. Profit and ROI Predictions A number of cases were simulated in the study. The model input variations included power sale value,
energy inflation, turbine size, and profit and non-profit ownership. Several important observations were
made on the output data.
The optimal system output is in the range of 150 to 175 kW. Larger systems will increase the initial costs
and decrease the return on investment, and increase the payback period. The increased cost is does not
result in substantial increases in total profit, either.
Larger energy inflation increases the power value, and in turn, profit and ROI. However, this is an
uncontrolled input. If energy power inflation is less than expected, it would adversely affect future profits.
With the middle range input assumptions listed below, the model produced the following promising
results:
Input Assumptions
o 150 kW turbine
o $658,000 system cost
o Power sale value of $0.075/kWh
o 4% Energy inflation Value
o 2% Inflation
o 3.5% 20-Year Treasury Interest
Results for Non-profit Ownership Case
o Profit = $3.59 million
o 25 Year ROI = 277%
o Payback = 8 years
Results for For-profit Ownership Case
o Profit = $4.75 million
o 25 Year ROI = 344%
o Payback = 3 years
Randall G. Alley, MSEE
36 Star Earth Energy, LLC
G. Conclusions A hydroelectric project at the Lake Junaluska dam appears both technically and economically feasible.
There is a non-trivial amount of capital investment required. A viable project plan should seek to mitigate
the capital cost through of grants or tax credits, and to maximize the power sale value through an
appropriate business model. A successful project will employ sound design principles and system
engineering to maximize the system performance and profitability. A clear view of the potential risks
should be maintained to help guide the project. Model predictions should be used with care, with the
understanding the high profit predictions carry a corresponding greater risk.
Star Earth Energy will be happy to assist the Lake Junaluska Assembly in any way it can, as it moves
through its decision making process regarding the dam hydroelectric project.
Randall G. Alley, MSEE
Star Earth Energy, LLC 37
X. List of Figures
Figure 1 - Richland Daily Flow Data ...................................................................................... 4 Figure 2 - Richland Flow vs. Day of Year .............................................................................. 4 Figure 3 - Pigeon Flow Sampled Monthly ............................................................................. 5 Figure 4 - Pigeon Flow Daily Average ................................................................................... 5 Figure 5 - Correlating Richland to Pigeon Flow .................................................................... 6 Figure 6 - Richland Creek Predicted Flow ............................................................................ 6 Figure 7 - Richland Creek Flow Duration Curve ................................................................... 7 Figure 8 - Dam Cross-Section (not to scale).......................................................................... 8 Figure 9 - Head Loss Due to Wall Effects (ft) ........................................................................ 9 Figure 10 - Head Loss Due to Wall Effects (%) ...................................................................... 9 Figure 11 - Head Loss Due to Turbulence (ft) ........................................................................ 9 Figure 12 - Monthly Power Prediction (kWH) .................................................................... 10 Figure 13 - Instantaneous Power (kW) ............................................................................... 10 Figure 14 - Generator Room ............................................................................................... 10 Figure 15 - Generator Room Proposed Layout (topview) .................................................... 10 Figure 16 - Intake Gates with Trash Screen Superstructure ................................................ 11 Figure 17 - Intake Gate 2 ...................................................................................................... 11 Figure 18 - Intake Gate 1 (interior left) ................................................................................ 12 Figure 19 - Intake Gate 1 (interior right) .............................................................................. 12 Figure 20 - Interior of Trash Screen with Gate Hydraulics Dry Wells ................................. 12 Figure 21 - Close-up of Trash Screen ................................................................................... 12 Figure 22 - Turbine Application Chart ................................................................................. 13 Figure 23 - Ossberger Application Chart ............................................................................. 13 Figure 24 - Kaplan Turbine Cross-section. ..........................................................................14 Figure 25 - Kaplan Runner. .................................................................................................14 Figure 26 - Ossberger Turbine Section ................................................................................ 15 Figure 27 - Ossberger Cross-section .................................................................................... 15 Figure 28 - Ossberger Turbine Runner ................................................................................ 15 Figure 29 - Ossberger Turbine Efficiency ............................................................................ 15 Figure 30 - Ossberger Cross-flow vs. Kaplan Efficiency ......................................................16 Figure 31 - Micro Hydro Development Costs (2010) ............................................................ 21 Figure 32 - Revenue Prediction (125 kW, 4% EI) ................................................................ 25 Figure 33 - Revenue Prediction (150 kW, 4% EI) ................................................................ 25 Figure 34 - Revenue Prediction (175 kW, 4% EI) ................................................................ 25 Figure 35 - Revenue Prediction (200 kW, 4% EI) ............................................................... 25 Figure 36 - Revenue Prediction (225 kW, 4% EI) ................................................................ 25 Figure 37 - Revenue Prediction (250 kW, 4% EI) ................................................................ 25 Figure 38 - Degraded Inputs (125 kW, 4% EI) ..................................................................... 26 Figure 39 - Degraded Inputs (150 kW, 4% EI) ..................................................................... 26 Figure 40 - ROI vs. Turbine (Non-profit, 4% EI) ................................................................. 27 Figure 41 - Profit vs. Turbine (Non-profit, 4% EI) .............................................................. 27 Figure 42 - Annualized ROI (Non-profit, 4% EI) ................................................................. 27 Figure 43 - Simple Payback (Non-profit, 4% EI) ................................................................. 27 Figure 44 - Profit (Non-profit, S1, 4% EI) ........................................................................... 27 Figure 45 - Simple ROI (Non-profit, S1, 4% EI)................................................................... 27 Figure 46 - Profit (Non-profit, S2, 4% EI) ........................................................................... 28 Figure 47 - Simple ROI (Non-profit, S2, 4% EI) .................................................................. 28
Randall G. Alley, MSEE
38 Star Earth Energy, LLC
Figure 48 - Profit (Non-profit, S3, 4% EI) ........................................................................... 28 Figure 49 - Simple ROI (Non-profit, S3, 4% EI) .................................................................. 28 Figure 50 - Profit (Non-profit, S4, 4% EI) ........................................................................... 28 Figure 51 - Simple ROI (Non-profit, S4, 4% EI) ................................................................... 28 Figure 52 - ROI vs. Turbine (For-profit, 4% EI) ................................................................... 31 Figure 53 - Profit vs. Turbine (For-profit, 4% EI) ................................................................ 31 Figure 54 - Annualized ROI (For-profit, 4% EI) ................................................................... 31 Figure 55 - Simple Payback (For-profit, 4% EI) ................................................................... 31 Figure 56 - Profit (For-profit, S5, 4% EI) ............................................................................. 31 Figure 57 - ROI (For-profit, S5, 4% EI) ................................................................................ 31 Figure 58 - Profit (For-profit, S6, 4% EI) ............................................................................ 32 Figure 59 - Simple ROI (For-profit, S6, 4% EI) ................................................................... 32 Figure 60 - Profit (For-profit, S9, 4% EI) ............................................................................ 32 Figure 61 - Simple ROI (For-profit, S9, 4% EI) ................................................................... 32 Figure 62 - Profit (For-profit, S10, 4% EI) .......................................................................... 32 Figure 63 - Simple ROI (For-profit, S10, 4% EI) ................................................................. 32 Figure 64 - Revenue Prediction (125kW, 3% EI) ..................................................................41 Figure 65 - Revenue Prediction (150 kW, 3% EI) .................................................................41 Figure 66 - Revenue Prediction (175 kW, 3% EI)..................................................................41 Figure 67 - Revenue Prediction (200 kW, 3% EI) .................................................................41 Figure 68 - Revenue Prediction (225 kW, 3% EI) .................................................................41 Figure 69 - Revenue Prediction (250 kW, 3% EI) .................................................................41 Figure 70 - Revenue Prediction (125 kW, 5% EI) ................................................................ 42 Figure 71 - Revenue Prediction (150 kW, 5% EI) ................................................................. 42 Figure 72 - Revenue Prediction (175 kW, 5% EI) ................................................................. 42 Figure 73 - Revenue Prediction (200 kW, 5% EI) ................................................................ 42 Figure 74 - Revenue Prediction (225 kW, 5% EI) ................................................................ 42 Figure 75 - Revenue Prediction (250 kW, 5% EI) ................................................................ 42 Figure 76 - Simple ROI vs. Turbine Size (3% EI) ................................................................. 43 Figure 77 - Cumulative Profit vs. Turbine (3% EI) .............................................................. 43 Figure 78 - Annualized ROI vs Turbine Size (3% EI) ........................................................... 43 Figure 79 - Simple ROI (Scenario 1, 3% EI) ......................................................................... 43 Figure 80 - Cumulative Profit (Scenario 1, 3% EI) .............................................................. 43 Figure 81 - Simple ROI (Scenario 1, 3% EI) ......................................................................... 43 Figure 82 - Cumulative Profit (Scenario 2, 3% EI) .............................................................. 44 Figure 83 - Simple ROI (Scenario 2, 3% EI) ........................................................................ 44 Figure 84 - Cumulative Profit (Scenario 3, 3% EI) .............................................................. 44 Figure 85 - Simple ROI (Scenario 3, 3% EI) ........................................................................ 44 Figure 86 - Cumulative Profit (Scenario 4, 3% EI) .............................................................. 44 Figure 87 - Simple ROI (Scenario 4, 3% EI) ........................................................................ 44 Figure 88 - Simple ROI vs. Turbine (5% EI) ........................................................................ 45 Figure 89 - Cumulative Profit vs. Turbine (5% EI) .............................................................. 45 Figure 90 - Annualized ROI vs. Turbine Size (5% EI) ......................................................... 45 Figure 91 - Years to Payback vs. Turbine (5% EI) ................................................................ 45 Figure 92 - Cumulative Profit (Scenario 1, 5% EI) ............................................................... 45 Figure 93 - Simple ROI (Scenario 1, 5% EI) ......................................................................... 45 Figure 94 - Cumulative Profit (Scenario 2, 5% EI) .............................................................. 46 Figure 95 - Simple ROI (Scenario 2, 5% EI) ........................................................................ 46 Figure 96 - Cumulative Profit (Scenario 3, 5% EI) .............................................................. 46
Randall G. Alley, MSEE
Star Earth Energy, LLC 39
Figure 97 - Simple ROI (Scenario 3, 5% EI) ........................................................................ 46 Figure 98 - Cumulative Profit (Scenario 4, 5% EI) .............................................................. 46 Figure 99 - Simple ROI (Scenario 4, 5% EI) ........................................................................ 46
XI. List of Tables
Table 1 - Summary of Richland Flow Data ............................................................................ 5 Table 2 - Summary of Pigeon Flow ....................................................................................... 5 Table 3 - Summary of Richland Predicted vs. Measured Flow .............................................. 6 Table 4 - Head Loss Coefficients ........................................................................................... 8 Table 5 - Estimate of Operating Efficiency ............................................................................ 9 Table 6 - PEC Capacity Credits for Hydroelectric Facilities ................................................ 18 Table 7 - Recommended Equipment ................................................................................... 20 Table 8 - Ossberger Quote Assumptions .............................................................................. 21 Table 9 - Ossberger Scope of Supply .................................................................................... 21 Table 10 - Lake Junaluska Hydroelectric Cost Estimate (114 kW output) ............................ 21 Table 11 - Comparison of Business Models ......................................................................... 23 Table 12 - Common Revenue Simulation Inputs ................................................................. 24 Table 13 - Varying Revenue Simulation Inputs ................................................................... 24 Table 14 - Profit and ROI Simulation Inputs ....................................................................... 26 Table 15 - Summary of Results (Non-profit, Kaplan) .......................................................... 30 Table 16 - Summary of Results (For-profit, Kaplan) ........................................................... 33
XII. List of Equations
Equation 1 ..................................................................... 4
Equation 2 .......................................................... 7
Equation 3 ........... 8
Equation 4 .................................................................................... 9
Equation 5 .......................................................................... 9 Equation 6 - Return on Investment (ROI) .......................................................................... 23 Equation 7 - Annualized ROI .............................................................................................. 23
XIII. Profile of Star Earth Energy, LLC
Star Earth Energy, LLC (SEE), is a North Carolina company based in Haywood and Wake
counties. Its mission is to help customers evaluate and acquire green and renewable energy technologies
that make sense from an economic and technical point of view. SEE was founded in 2009 by Randall
Alley, MSEE and Jeffrey Lyle, owner of StarTek Electric, Inc. This partnership combines decades of
expertise in electrical engineering, research, technology development and renewable energy technologies
with an extensive track record of demonstrated excellence in commercial, industrial and residential
electrical contracting. Together we offer customers a range of services including consulting, design and
Randall G. Alley, MSEE
40 Star Earth Energy, LLC
installation of renewable energy systems, including photovoltaic, solar thermal, wind and hydroelectric.
SEE maintains a strategic alliance with StarTek Electric that gives SEE access to StarTek’s extensive
electrical contracting capabilities.
Mr. Alley received a BA in Physics from East Carolina University in 1982 and an MS degree from
North Carolina State University in Electrical Engineering in 1991. From 1982 to 1985 he worked in the
Energy Division of the NC Department of Commerce as a Weatherization Specialist in the Low-Income
Weatherization Assistance Program. From 1988 to 1998 he worked for RTI International working in the
area of thin-film semiconductor research and development. In 1998 he started a consulting firm offering
programming and system design services in the area of scientific measurement, data collection and
system automation. In 2001 he returned to RTI to work on the commercialization of an advanced
renewable energy technology based on thin-film thermoelectric materials. In 2004 he joined the spin-off
company Nextreme Thermal Solutions, Inc. working to commercialize that technology and worked on
applications in electronics cooling and power generation from waste heat. In 2009, Mr. Alley completed
the Renewable Energy and Green Building certification program run by the NC Solar Center at NC State.
Mr. Lyle Jeffrey Lyle founded StarTek Electric, Inc. in 1995, a self-funded small business startup
focused on full service electrical contracting. Mr. Lyle has 30 years combined experience in industrial,
commercial and residential electrical and carries a North Carolina unlimited electrical license. He is a
graduate of Southwestern Technical College with A.A.S. in Electronics Engineering. Prior to starting
StarTek Electric, Mr. Lyle worked 13 years for Jackson Paper in Sylva, NC as Electrical & Instrumentation
Superintendent. Previously he worked for Ivey Electric Co. in Spartanburg, Sc and Scientific Electric, Inc.
in Asheville for a total of 6 years. In 2000, Mr. Lyle completed the Photovoltaics for Electrical Contractors
program at the NC Solar Center at NC State.
XIV. Contact Information
Randall G. Alley
919-623-7549
Jeffrey Lyle
828-506-0690
Star Earth Energy, LLC
2817 Claremont Road
Raleigh, NC 27608
Randall G. Alley, MSEE
Star Earth Energy, LLC 41
XV. Appendix - Revenue Predictions - 3% Energy Inflation
Figure 64 - Revenue Prediction (125kW, 3% EI)
Figure 65 - Revenue Prediction (150 kW, 3% EI)
Figure 66 - Revenue Prediction (175 kW, 3% EI)
Figure 67 - Revenue Prediction (200 kW, 3% EI)
Figure 68 - Revenue Prediction (225 kW, 3% EI)
Figure 69 - Revenue Prediction (250 kW, 3% EI)
0
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4
5
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9
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Cumulative Hydroelectric Revenuc125kW Kaplan, 3% Energy Inflation
1_125kW
2_125kW
3_125kW
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Cumulative Hydroelectric Revenuc150kW Kaplan, 3% Energy Inflation
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Cumulative Hydroelectric Revenuc175kW Kaplan, 3% Energy Inflation
1_175kW
2_175kW
3_175kW
4_175kW
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Cumulative Hydroelectric Revenuc200kW Kaplan, 3% Energy Inflation
1_200kW
2_200kW
3_200kW
4_200kW
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Cumulative Hydroelectric Revenuc225kWKaplan, 3% Energy Inflation
1_225kW
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3_225kW
4_225kW
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Years of Operation
Cumulative Hydroelectric Revenuc250kWKaplan, 3% Energy Inflation
1_250kW
2_250kW
3_250kW
4_250kW
Randall G. Alley, MSEE
42 Star Earth Energy, LLC
XVI. Appendix - Revenue Projections - 5% Energy Inflation
Figure 70 - Revenue Prediction (125 kW, 5% EI)
Figure 71 - Revenue Prediction (150 kW, 5% EI)
Figure 72 - Revenue Prediction (175 kW, 5% EI)
Figure 73 - Revenue Prediction (200 kW, 5% EI)
Figure 74 - Revenue Prediction (225 kW, 5% EI)
Figure 75 - Revenue Prediction (250 kW, 5% EI)
0
1
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7
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9
0 5 10 15 20 25
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Years of Operation
Cumulative Hydroelectric Revenuc125kW Kaplan, 5% Energy Inflation
1_125kW
2_125kW
3_125kW
4_125kW
0
1
2
3
4
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6
7
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9
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Years of Operation
Cumulative Hydroelectric Revenuc150kW Kaplan, 5% Energy Inflation
1_150kW
2_150kW
3_150kW
4_150kW
0
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9
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Years of Operation
Cumulative Hydroelectric Revenuc175kW Kaplan, 5% Energy Inflation
1_175kW
2_175kW
3_175kW
4_175kW
0
1
2
3
4
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Cumulative Hydroelectric Revenuc200kW Kaplan, 5% Energy Inflation
1_200kW
2_200kW
3_200kW
4_200kW
0
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Cumulative Hydroelectric Revenuc225kW Kaplan, 5% Energy Inflation
1_225kW
2_225kW
3_225kW
4_225kW
0
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Cumulative Hydroelectric Revenuc250kW Kaplan, 5% Energy Inflation
1_250kW
2_250kW
3_250kW
4_250kW
Randall G. Alley, MSEE
Star Earth Energy, LLC 43
XVII. Profit and ROI - Non-profit, 3% Energy Inflation
Figure 76 - Simple ROI vs. Turbine Size (3% EI)
Figure 77 - Cumulative Profit vs. Turbine (3% EI)
Figure 78 - Annualized ROI vs Turbine Size (3% EI)
Figure 79 - Simple ROI (Scenario 1, 3% EI)
Figure 80 - Cumulative Profit (Scenario 1, 3% EI)
Figure 81 - Simple ROI (Scenario 1, 3% EI)
0%
50%
100%
150%
200%
250%
300%
350%
400%
450%
125 150 175 200 225 250
Sim
ple
RO
I (%
)
Turbine Size (kW)
Simple ROI After 25 YearsKaplan Turbine, 3% Energy Inflation
Scenario 4
Scenario 3
Scenario 2
Scenario 1
0
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125 150 175 200 225 250
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($M
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Turbine Size (kW)
Cumulative Profit After 25 YearsKaplan Turbine, 3% Energy Inflation
Scenario 4
Scenario 3
Scenario 2
Scenario 1
0%
2%
4%
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14%
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18%
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24%
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Sim
ple
RO
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Turbine Size (kW)
Annualized ROI After 25 YearsKaplan Turbine, 3% Energy Inflation
Scenario 4
Scenario 3
Scenario 2
Scenario 1
0
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12
14
250 225 200 175 150 125
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s to
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Turbine Size (kW)
Simple PaybackKaplan Turbine, 3% Energy Inflation
Scenario 4
Scenario 3
Scenario 2
Scenario 1
0.0
1.0
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Years of Operation
Cumulative Profit - Scenario 1Kaplan Turbine, 3% Energy Inflation
250 kW
225 kW
200 kW
175 kW
150 kW
125 kW
0%
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450%
0 5 10 15 20 25
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Simple ROI - Scenario 1Kaplan Turbine, 3% Energy Inflation
250 kW
225 kW
200 kW
175 kW
150 kW
125 kW
Randall G. Alley, MSEE
44 Star Earth Energy, LLC
Figure 82 - Cumulative Profit (Scenario 2, 3% EI)
Figure 83 - Simple ROI (Scenario 2, 3% EI)
Figure 84 - Cumulative Profit (Scenario 3, 3% EI)
Figure 85 - Simple ROI (Scenario 3, 3% EI)
Figure 86 - Cumulative Profit (Scenario 4, 3% EI)
Figure 87 - Simple ROI (Scenario 4, 3% EI)
0.0
1.0
2.0
3.0
4.0
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7.0
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Cu
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s)
Years of Operation
Cumulative Profit - Scenario 2Kaplan Turbine, 3% Energy Inflation
250 kW
225 kW
200 kW
175 kW
150 kW
125 kW
0%
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450%
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I (%
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Simple ROI - Scenario 2Kaplan Turbine, 3% Energy Inflation
250 kW
225 kW
200 kW
175 kW
150 kW
125 kW
0.0
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Years of Operation
Cumulative Profit - Scenario 3Kaplan Turbine, 3% Energy Inflation
250 kW
225 kW
200 kW
175 kW
150 kW
125 kW
0%
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0 5 10 15 20 25
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ple
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I (%
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Simple ROI - Scenario 3Kaplan Turbine, 3% Energy Inflation
250 kW
225 kW
200 kW
175 kW
150 kW
125 kW
0.0
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Cumulative Profit - Scenario 4Kaplan Turbine, 3% Energy Inflation
250 kW
225 kW
200 kW
175 kW
150 kW
125 kW
0%
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Simple ROI - Scenario 4Kaplan Turbine, 3% Energy Inflation
250 kW
225 kW
200 kW
175 kW
150 kW
125 kW
Randall G. Alley, MSEE
Star Earth Energy, LLC 45
XVIII. Appendix - Profit & ROI - Non-profit, 5% Energy Inflation
Figure 88 - Simple ROI vs. Turbine (5% EI)
Figure 89 - Cumulative Profit vs. Turbine (5% EI)
Figure 90 - Annualized ROI vs. Turbine Size (5% EI)
Figure 91 - Years to Payback vs. Turbine (5% EI)
Figure 92 - Cumulative Profit (Scenario 1, 5% EI)
Figure 93 - Simple ROI (Scenario 1, 5% EI)
0%
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600%
125 150 175 200 225 250
Sim
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Simple ROI After 25 YearsKaplan Turbine, 5% Energy Inflation
Scenario 4
Scenario 3
Scenario 2
Scenario 1
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Cumulative Profit After 25 YearsKaplan Turbine, 5% Energy Inflation
Scenario 4
Scenario 3
Scenario 2
Scenario 1
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Scenario 4
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Simple PaybackKaplan Turbine, 5% Energy Inflation
Scenario 4
Scenario 3
Scenario 2
Scenario 1
0.0
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Cumulative Profit - Scenario 1Kaplan Turbine, 5% Energy Inflation
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Simple ROI - Scenario 1Kaplan Turbine, 5% Energy Inflation
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125 kW
Randall G. Alley, MSEE
46 Star Earth Energy, LLC
Figure 94 - Cumulative Profit (Scenario 2, 5% EI)
Figure 95 - Simple ROI (Scenario 2, 5% EI)
Figure 96 - Cumulative Profit (Scenario 3, 5% EI)
Figure 97 - Simple ROI (Scenario 3, 5% EI)
Figure 98 - Cumulative Profit (Scenario 4, 5% EI)
Figure 99 - Simple ROI (Scenario 4, 5% EI)
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Cumulative Profit - Scenario 2Kaplan Turbine, 5% Energy Inflation
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Simple ROI - Scenario 2Kaplan Turbine, 5% Energy Inflation
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Cumulative Profit - Scenario 3Kaplan Turbine, 5% Energy Inflation
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Simple ROI - Scenario 3Kaplan Turbine, 5% Energy Inflation
250 kW
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Cumulative Profit - Scenario 4Kaplan Turbine, 5% Energy Inflation
250 kW
225 kW
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I (%
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Years of Operation
Simple ROI - Scenario 4Kaplan Turbine, 5% Energy Inflation
250 kW
225 kW
200 kW
175 kW
150 kW
125 kW
Randall G. Alley, MSEE
Star Earth Energy, LLC 47
XIX. Appendix - Ossberger Price Quote
Randall G. Alley, MSEE
48 Star Earth Energy, LLC
A. FERC Hydropower Project Comparison Chart25
Conduit Exemption 5-MW Exemption License
Installed Capacity
Limitations
15 MW or less (for non-municipality)
40 MW or less (for a municipality)
5 MW or less Unlimited
Location Limitations in
Addition to Off-Limits
Sites
Must be located on a conduit used for
agricultural, municipal, or industrial
consumption
Cannot be located on federal lands
Cannot be located at an impoundment
Must be located at an existing dam or natural water feature
Cannot be located at a dam owned or operated by the
federal government
Ownership Limitations Must have all real property rights
necessary to develop and operate the
project or an option to obtain such
interests
Proof of ownership required at time of
filing the application
If located on private lands, must have all real property rights
necessary to develop and operate the project or an option
to obtain such interests
Proof of ownership required at time of filing the application
Proof of ownership not required at time of filing the
application; power of eminent domain may be conferred
by section 21 of the FPA, 16 U.S.C. § 814
Term Limitations Issued in perpetuity Issued in perpetuity Up to 50 years for license
May be Subject to the
Following Mandatory
Conditions
Federal and state fish and wildlife
conditions under section 30(c) of the FPA,
16 U.S.C. § 823a(c)
Federal and state fish and wildlife conditions under section
30(c) of the FPA, 16 U.S.C. § 823a(c)
Federal reservation conditions under section 4(e) of the
FPA, 16 U.S.C. § 797(e)
Fishway prescriptions under section 18 of the FPA, 16
U.S.C. § 811
Consultation
Requirements
3-stage consultation required under 18
C.F.R. § 4.38
With concurrence from all resource
agencies, the applicant may seek waiver of
the consultation requirements under 18
C.F.R. § 4.38(e)
3-stage consultation required under 18 C.F.R. § 4.38
With concurrence from all resource agencies, the applicant
may seek waiver of the consultation requirements under 18
C.F.R. § 4.38(e)
Integrated Licensing Process (ILP) required under 18 C.F.R
§ 5
If waiver of ILP regulations was sought under 18 C.F.R. §
5.1(f), and granted, then 3-stage consultation required
under 18 C.F.R. § 4.34(i) for the Alternative Licensing
Process or 18 C.F.R. § 4.38 for the Traditional Licensing
Process
With concurrence from all resource agencies, the
applicant may seek waiver of the consultation
requirements under 18 C.F.R. § 4.38(e)
Preparation of
Environmental
Document
Categorically exempt from preparing an
environmental document under 18 C.F.R. §
380.4(a)(14) unless determined necessary
Prepared consistent with NEPA Prepared consistent with NEPA
Project Boundary Includes powerhouse and connection to
conduit (excludes the transmission line and
the conduit itself).
Includes all associated lands and facilities, such as the
powerhouse, dam, impoundment, transmission line, and any
lands that fulfill a project purpose (e.g. , recreation,
resource protection, and access roads).
Includes all associated lands and facilities, such as the
powerhouse, dam, impoundment, transmission line, and
any lands that fulfill a project purpose (e.g. , recreation,
resource protection, and access roads).
Filing Fees None None None
Annual Charges Currently projects up to 1.5 MW not
charged
Currently projects up to 1.5 MW not charged Currently projects up to 1.5 MW not charged
Implementing Statutes FPA section 30(c). 16 U.S.C. § 823a Public Utility Regulatory Policies Act (PURPA) sections 405
and 408.
16 U.S.C. §§ 2705 and 2708
FPA sections 4 thru 27 16 U.S.C. §§ 797-821
Application Regulations 18 C.F.R. §§ 4.90-4.96 18 C.F.R. §§ 4.101-4.108 18 C.F.R. § 5 (Integrated Licensing Process)
18 C.F.R. §§ 4.30-4.61(Traditional Licensing Process)
18 C.F.R. § 4.34(i) (Alternative Licensing Process)
25 FERC Website, http://www.ferc.gov/industries/hydropower/gen-info/licensing/small-low-impact/get-started/exemp-licens/project-comparison.asp.
Randall G. Alley, MSEE
Star Earth Energy, LLC 49
B. FERC Matrix Comparison Licensing Processes26
Integrated Licensing Process (ILP) Traditional Licensing Process (TLP) Alternative Licensing Process (ALP)
Consultation w/ Resource Agencies and Indian Tribes
- Integrated - Paper-driven - Collaborative
FERC Staff Involvement - Pre-filing [beginning at filing of Notice of Intent (NOI)] - Early and throughout process
- Post filing (after the application has been filed) - Available for education and guidance
- Pre-filing (beginning at filing the NOI) - Early involvement for National Environmental Policy Act (NEPA) scoping as requested
Deadlines - Defined deadlines for all participants (including FERC) throughout the process
- Pre-filing: some deadlines for participants - Post-filing: defined deadlines for participants
- Pre-filing: deadlines defined by collaborative group - Post-filing: defined deadlines for participants
Study Plan Development - Developed through study plan meetings with all stakeholders - Plan approved by FERC
- Developed by applicant based on early stakeholder recommendations - No FERC involvement
- Developed by collaborative group - FERC staff assist as resources allow
Study Dispute Resolution - Informal dispute resolution available to all participants - Formal dispute resolution available to agencies with mandatory conditioning authority - Three-member panel provides technical recommendation on study dispute - OEP Director opinion binding on applicant
- FERC study dispute resolution available upon request to agencies and affected tribes - Office of Energy Projects (OEP) Director issues advisory opinion
- FERC study dispute resolution available upon request to agencies and affected tribes - OEP Director issues advisory opinion
Application - Preliminary licensing proposal or draft application and final application include Exhibit E (environmental report) with form and contents of an EA
- Draft and final application include Exhibit E
- Draft and final application with applicant-prepared environmental assessment or third-party environmental impact statement
Additional Information Requests
- Available to participants before application filing - No additional information requests after application filing
- Available to participants after filing of application
- Available to participants primarily before application filing - Post-filing requests available but should be limited due to collaborative approach
Timing of Resource Agency Terms and Conditions
- Preliminary terms and conditions filed 60 days after Ready for Environmental Analysis (REA) notice - Modified terms and conditions filed 60 days after comments on draft NEPA document
- Preliminary terms and conditions filed 60 days after REA notice - Schedule for final terms and conditions
- Preliminary terms and conditions filed 60 days after REA notice - Schedule for final terms and conditions
26 FERC Website, http://www.ferc.gov/industries/hydropower/gen-info/licensing/matrix.asp.
Randall G. Alley, MSEE
50 Star Earth Energy, LLC
C. FERC Project History for Lake Junaluska P-3474 Lake Junaluska FERC History
Filed Date Docket Number Description Type
01/16/96 P-3474-013 NC Dept of Cultural Resources comments on EA for Lake Junaluska Proj under P-3474. Comments/Protest /
01/23/96 Availability: Public Untyped During RIMS II Conversion
11/24/95 P-3474-000 Jurisdiction of Lake Junaluska Assembly,Lake Junaluska hydroelec devel returns to State of NC by issuance of 951020 order accepting surrender of lic under P-3474.
FERC Correspondence With Government Agencies /
11/29/95 Availability: Public FERC Correspondence With Government Agencies
10/20/95 P-3474-013 Order accepting surrender of exemption by Lake Junaluska Assembly's Lake Junaluska Hydroelec Proj (P-3474).
Order/Opinion /
10/20/95 Availability: Public Delegated Order
10/18/95 P-3474-000 Lake Junaluska. NOTICE OF AVAILABILITY OF ENVIRONMENTAL ASSESSMENT Order/Opinion /
10/18/95 Availability: Public Untyped during conversion
10/16/95 P-3474-013 Notice of availability of environmental assessment re Lake Junaluska Proj-3474.Availability: Public Notice /
10/16/95 Formal Notice
10/16/95 P-3474-013 Environmental assessment re Lake Junaluska Proj-3474. Dtd October 1995.Availability: Public FERC Report/Study /
10/16/95 Untyped During RIMS II Conversion
04/25/95 P-3474-000 United Methodist Church responds to 950323 ltr indicating that they are to proceed w/drilling program for Lake Junaluska P-3474.Availability: Public
Applicant Correspondence /
05/03/95 Untyped During RIMS II Conversion
03/15/95 P-3474-000 Lake Junaluska Council of United Methodist Church fwds proposal for professional servs re Lake Junaluska Proj under P-3474.Availability: Public
Applicant Correspondence /
03/20/95 Untyped During RIMS II Conversion
02/17/95 P-3474-000 NC Dept of Environment,Health & Natural Resources submits copies of 750512 et al correspondence,each Dam Safety Law of 1967 etc re Lake Junaluska Dam under P-3474.Availability: Public
Other Submittal /
03/03/95 Government Agency Submittal
02/17/95 P-3474-000 Expresses appreciation for assistance,cooperation/profess- ional courtesy re 950214 meeting re Lake Junaluska Proj-3474.
FERC Correspondence With Government Agencies /
02/17/95 Availability: Public FERC Correspondence With Government Agencies
01/20/95 P-3474-013 Ltr notice requesting Lake Junaluska Assembly to submit w/in 30 days,plan/sched for remedial dam safety measures as outlined in 921223 ltr re Lake Junaluska P-3474.Availability: Public
Notice /
01/20/95 Formal Notice
11/30/94 P-3474-000 Lake Junaluska Assembly's response to 941104 ltr and request for extension of time for certain items re Lake Junaluska Proj (P-3474).
Applicant Correspondence /
12/14/94 Availability: Public Request for Delay of Action/Extension of Time
11/16/94 P-3474-000 Ltr notice directing United Methodist Church to make certain revisions to EAP for Lake Junaluska Proj under P-3474 w/in 30 days.Availability: Public
Notice /
11/30/94 Formal Notice
11/04/94 P-3474-000 Ltr notice to Lake Junaluska Assembly confirming recommendations made as result of annual operation inspec- tion of Lake Junaluska Proj (P-3474).Plan/sched due:30 days.
Notice /
11/10/94 Availability: Public Formal Notice
10/05/94 P-3474-013 Ltr notice requesting Lake Junaluska Assembly to immediately comply w/ARO requires to ensure safety re Lake Junaluska Proj-3474.Availability: Public
Notice /
10/05/94 Formal Notice
12/08/93 P-3474-000 Ltr notice requesting United Methodist Church Southeastern Jurisdictional Admin Council to submit sched for exercise for Lake Junaluska Proj under P-3474.Due w/in 10 days.Availability: Public
Notice /
12/08/93 Formal Notice
08/05/93 P-3474-013 Notice of Lake Junaluska Assembly 930729 filed appl for surrend of exemption for Lake Junaluska P-3474,NC. Comment date:930924.
Notice /
08/05/93 Availability: Public Formal Notice
07/26/93 P-3474-013 Lake Junaluska Assembly informs FERC of breakdown of hydro equipment at Lake Junaluska under P-3474.
Applicant Correspondence /
07/29/93 Availability: Public Untyped During RIMS II Conversion
05/24/93 P-3474-000 Ltr order granting United Methodist Church Southeastern Jurisdictional Admin Council time extension for conducting design/remedial work for Lake Junaluska Proj-3474.
Order/Opinion /
05/24/93 Availability: Public Delegated Order
05/10/93 P-3474-012 Order amend Lake Junaluska Assembly exemption for Lake Junaluska Proj under P-3474. Order/Opinion /
05/10/93 Availability: Public Delegated Order
05/07/93 P-3474-011 Ltr to Lake Junaluska Assembly re request to amend exemption for Lake Junaluska Proj (P-3474).Availability: Public
FERC Correspondence With Applicant /
05/07/93 Untyped During RIMS II Conversion
03/19/93 P-3474-000 Lake Junaluska Assembly requesting that SEJAC be granting exemption by FERC to operate one 200 kw hydro-power unit in Lake Junaluska Dam Proj-3474.
Applicant Correspondence /
04/19/93 Availability: Public Untyped During RIMS II Conversion
03/30/93 P-3474-000 Ltr notice directing Lake Junaluska Assembly to file explanation of discrepancy re installation capacity at Lake Junaluska Proj w/in 30 days under P-3474.
Notice /
03/30/93 Availability: Public Formal Notice
12/08/92 P-3474-000 Lake Junaluska Assembly submits EAP for Lake Junaluska Hydroelec Proj (P-3474). Report/Form /
01/22/93 Availability: CEII Emergency Action Plan
10/12/92 P-3474-000 Rep CH Taylor submits correspondence from MG Martin re Lake Junaluska Hydro P-3474. Other Submittal /
10/16/92 Availability: Public Congressional Submittal
09/16/92 P-3474-000 Ltr order denying Lake Junaluska Assembly request for extension of time to submit plan & schedule for violation of Art 6,Part 12 re Lake Junaluska Project under P-3474. PART 12
Order/Opinion /
09/17/92 Availability: Public Delegated Order
09/01/92 P-3474-000 Lake Junaluska Assembly files request for extension of time to submit plan & schedule per Art 6 Part 12 re Lake Junaluska Project under P-3474. PART 12
Report/Form /
Randall G. Alley, MSEE
Star Earth Energy, LLC 51
09/17/92 Availability: CEII Part 12 Consultant Safety Inspection Reports
P-3474-000 Ltr notice advising Lake Junaluska Assembly of violation of Art 6 of exemption/to immediately submit plan/sched re Lake Junaluska P-3474. PART 12
Notice /
08/18/92 Availability: Public Formal Notice
06/24/92 P-3474-000 Ltr notice directing Lake Junaluska Assembly to submit addl suppl to 2nd consultant Part 12 safety insp rept for Lake Junaluska Proj #3474.Plan & schedule due:30 days. PART 12Availability: Public
Notice /
06/24/92 Formal Notice
06/03/92 P-3474-000 Ltr notice requesting Lake Junaluska Division of United Methodist Church to submit plan/sched,w/in 30 days re consultants recommendations for Lake Junaluska P-3474.Availability: Public
Notice /
06/03/92 Formal Notice
12/18/91 P-3474-000 Ltr notice to Lake Junaluska Assembly to submit overdue data on Lake Junalaska Proj #3474 for Natl Inventory of Dams.Due immediately.
Notice /
12/18/91 Availability: Public Formal Notice
12/12/91 P-3474-000 Ltr order accepting United Methodist Church public safety plan as satisfactory re Lake Junaluska Project under P-3474.Availability: Public
Order/Opinion /
12/11/91 Delegated Order
08/27/91 P-3474-000 Ltr notice ack cooperation extended for const insp & submitting recommendations re Lake Junaluska Proj under P-3474.Plan & sched due within 30-days.Availability: Public
Notice /
08/27/91 Formal Notice
06/07/91 P-3474-000 Ltr order granting Lake Junaluska Assembly extension of time to submit plan & sched re Lake Junaluska Proj by 910901 under P-3474.Availability: Public
Order/Opinion /
06/07/91 Delegated Order
04/19/91 P-3474-000 Ltr notice requesting Lake Junaluska Assembly to submit plan for remote surveillance per rev to EAP re Lake Junaluska Proj w/in 30-days under P-3474. PART 12Availability: Public
Notice /
04/19/91 Formal Notice
03/22/91 P-3474-008 Order granting Lake Junaluska Assembly extension of time re Lake Junaluska Hydro Proj,NC under P-3474.
Order/Opinion /
03/22/91 Availability: Public Delegated Order
03/07/91 P-3474-000 Lake Junaluska Assembly of UMC submits addl info to 910205 request for extension of time to complete Lake Junaluska Assembly Hydropwr Proj under P-3474.Availability: Public
Applicant Correspondence /
03/11/91 Request for Delay of Action/Extension of Time
01/31/91 P-3474-000 Ltr notice requesting Southeastern Jurisdictional Admin Council to submit plan & sched etc re Lake Junaluska Proj immediately under P-3474.Availability: Public
Notice /
01/31/91 Formal Notice
01/31/91 P-3474-000 Ltr notice to Southern Jurisdictional Admin Council to conduct EAP test & submit test critique etc re Lake Junaluska Proj w/in 30 days under P-3474. PART 12Availability: Public
Notice /
01/31/91 Formal Notice
11/30/90 P-3474-007 Ltr notice to SE Jurisdictional Adminiatrativre Council advising of failure to comply w/Exemption Art 6 re Lake Junaluska Hydro Proj under P-3474-007.Availability: Public
Notice /
11/30/90 Formal Notice
11/15/90 P-3474-000 Ltr order accepting Lake Junaluska Assembly plan & sched re oprn insp of Lake Junaluska Proj under P-3474.Availability: Public
Order/Opinion /
11/20/90 Delegated Order
11/15/90 P-3474-000 FERC acks receipt of Lake Junaluska Assembly 901106 ltr re respone to reccomendation #4 per recent operation insp at Proj-3474.Availability: Public
Notice /
11/15/90 Formal Notice
10/02/90 P-3474-000 Lake Junaluska,NC submits rept of FERC 5-Yr independent insp rept for Proj-3474. PART 12Availability: CEII
Report/Form /
11/09/90 Part 12 Consultant Safety Inspection Reports
11/06/90 P-3474-000 Lake Junaluska Assembly submits response to FERC's 901025 ltr re implementation of instrumentation program at Proj-3474.Availability: Public
Applicant Correspondence /
11/08/90 Untyped During RIMS II Conversion
10/25/90 P-3474-000 Ltr order accepting plan & sched for responding to recommen- dations 1-3 in recent operation insp of Lake Junaluska Proj-3474.Availability: Public
Order/Opinion /
10/25/90 Delegated Order
10/02/90 P-3474-000 Fwds 2nd 5-yr independent consultant insp rept of Lake Junaluska Assembly re Lake Junaluska Dam Proj,NC under P-3474.W/o encl. PART 12Availability: CEII
Report/Form /
10/11/90 Part 12 Consultant Safety Inspection Reports
06/01/90 P-3474-000 Southeastern Jurisdictional Admin Council responds to FERC inquiry re exempt for dam & hydro facil at Lake Junaluska,NC under P-3474.Availability: Public
Applicant Correspondence /
06/04/90 Untyped During RIMS II Conversion
06/01/90 P-3474-000 Southeastern Jurisdictional Admin Council responds to FERC requirements re exempt for dam & hydro facil at Lake Junaluska,NC under P-3474.Availability: Public
Applicant Correspondence /
06/04/90 Untyped During RIMS II Conversion
04/03/90 P-3474-000 Response to Lake Junaluska Assembly 900326 ltr requesting copy of exemption under P-3474. PART 12Availability: Public
FERC Correspondence With Applicant /
04/03/90 Untyped During RIMS II Conversion
02/23/90 P-3474-000 Ltr notice to Lake Junaluska Assembly to submit addl suppl to initial consultants safety insp rept w/in 15 days for Lake Junaluska Project under P-3474.Availability: Public
Notice /
03/23/90 Formal Notice
03/12/90 P-3474-000 ARO informs Lake Junaluska Assembly of require of Part 12 safety insp every 5 yrs re Lake Junaluska Project under P-3474. PART 12Availability: Public
FERC Correspondence With Applicant /
03/12/90 Untyped During RIMS II Conversion
02/09/90 P-3474-006 Order granting extension of time re Lake Junaluska Assembly under P-3474-006. Order/Opinion /
02/09/90 Availability: Public Delegated Order
01/10/90 P-3474-006 Comments of United Methodist Chruch re Lake Junaluska hydro- power Proj under P-3474.Availability: Public
Applicant Correspondence /
01/18/90 Untyped During RIMS II Conversion
Randall G. Alley, MSEE
52 Star Earth Energy, LLC
10/25/89 P-3474-000 Ltr notice requesting Lake Junaluska Assembly to provide notification flowchart summarizing who is to be notified re EAP under P-3474 w/in 45 days.Availability: Public
Notice /
10/25/89 Formal Notice
09/27/89 P-3474-005 United Methodist Church requests addl time for completion of Lake Junaluska Assembly Hydro Power Proj.Availability: Public
Applicant Correspondence /
09/29/89 Untyped During RIMS II Conversion
01/30/89 P-3474-000 EAP of Lake Junaluska Assembly Inc for Lake Junaluska Hydro Proj under P-3474.Availability: CEII Report/Form /
07/19/89 Emergency Action Plan
05/03/89 P-3474-004 Order granting Lake Junaluska Assembly extension of time for completion of proj construction. Order/Opinion /
05/03/89 Availability: Public Delegated Order
03/27/89 P-3474-000 Lake Junaluska Assembly fwds exact name,title,address & phone # of corp president,or vice president etc responsible for proj as lic(ee)/exemptee in P-3474.Availability: Public
Other Submittal /
03/27/89 Other External Submittal
01/09/89 P-3474-000 Ltr order granting Lake Junaluska Assembly extension of time until 890131 for filing rev EAP re Lake Junaluska Proj.Availability: Public
Order/Opinion /
01/12/89 Delegated Order
02/09/88 P-3474-000 Ltr notice directing Lake Junaluska Assembly to submit review,test & update of EAP w/in 30-days.Availability: Public
Notice /
02/09/88 Formal Notice
02/08/88 P-3474-000 Lake Junaluska Assembly 1st consultant safety insp rept for Lake Junaluska Proj on 880115 by CE Sams.Availability: Public
FERC Report/Study /
02/08/88 Untyped During RIMS II Conversion
10/13/87 P-3474-000 Ltr order granting Lake Junaluska Assembly an extension of time to submit addl info re Part 12 rept for P-3474. 871013Availability: Public
Order/Opinion /
10/13/87 Delegated Order
09/30/87 P-3474-000 Lake Junaluska Assembly request an extension of time to com- plete Part 12 rept for Lake Junaluska Dam Proj.Availability: Public
Applicant Correspondence /
10/05/87 Untyped During RIMS II Conversion
08/13/87 P-3474-000 Requests Lake Junaluska to submit inspection rept by 871012 for Lake Junaluska Proj.Availability: Public
FERC Correspondence With Applicant /
08/13/87 Untyped During RIMS II Conversion
06/18/87 P-3474-003 Order granting extension of time to complete proj const to 890115 for Lake Junaluska Proj. 870618Availability: Public
Order/Opinion /
06/18/87 Delegated Order
06/08/87 P-3474-003 Lake Junaluska Assembly request extension of time to com- plete const for lic re Lake Junaluska Hydropower Proj.Availability: Public
Application/Petition/Request /
06/09/87 Exemption From License - Conduit/5MW
06/15/86 P-3474-000 Discusses Lake Junaluska Assembly requirements re exemption for Lake Junaluska Hydropower Proj.Availability: Public
Applicant Correspondence /
06/09/87 Untyped During RIMS II Conversion
03/12/87 P-3474-000 Lake Junaluska Assembly informs FERC that BL Williams will assume liaison duties for Lake Junaluska Proj.Availability: Public
Applicant Correspondence /
03/13/87 Untyped During RIMS II Conversion
10/31/85 P-3474-000 Ltr order approving R Hunt as consultant for initial insp of Lake Junaluska Proj. 851031Availability: Public
Order/Opinion /
10/31/85 Delegated Order
09/12/85 P-3474-000 Acks receipt of Lake Junaluska Assembly revised EAP & addl info re Lake Junaluska Proj.Availability: Public
FERC Correspondence With Applicant /
09/19/85 Untyped During RIMS II Conversion
09/17/85 P-3474-000 Ltr order denying request of ELI Corp for exemption of Lake Junaluska Hydro Proj. 850917Availability: Public
Order/Opinion /
09/17/85 Delegated Order
08/30/85 P-3474-000 Submits request for exemption of safety insp for Lake Junaluska Hydro Proj.Availability: CEII Report/Form /
09/05/85 Part 12 Consultant Safety Inspection Reports
07/26/83 P-3474-002 Forwards agency ltrs commenting on Lake Junaluska Assembly's appl for exemption of Lake Junaluska Project.W/o encl.Availability: Public
FERC Correspondence With Applicant /
07/26/83 Untyped During RIMS II Conversion
07/15/83 P-3474-002 Order granting exemption from licensing of small hydro proj 5 MW or less in the matter of Lake Junaluska Assembly.Availability: Public
Order/Opinion /
07/15/83 Delegated Order
05/14/83 P-3474-000 Comments on notice of case specific exemption appl for Lake Junaluska Assembly Hydro Proj,Haywood County,NC.Availability: Public
Comments/Protest /
05/17/83 Untyped During RIMS II Conversion
05/09/83 P-3474-002 Submits exhibits to Lake Junaluska Assembly appl for lic re P-3474-002.Availability: Public Application/Petition/Request /
05/17/83 Untyped During RIMS II Conversion
05/03/83 P-3474-002 Notice of case specific exemption appl of Lake Junaluska Assembly for Lake Junaluska Proj.Availability: Public
Notice /
05/03/83 Formal Notice
04/14/83 P-3474-002 Ltr order accepting 830121 exemption appl of Lake Juanalus- ka Assembly,NC for Lake Junaluska Proj.W/encl. 830414Availability: Public
Order/Opinion /
04/14/83 Delegated Order
03/14/83 P-3474-002 Suppl to appl of Lake Junaluska Assembly for lic exemption. Submits deeds showing site ownership.Availability: Public
Application/Petition/Request /
03/18/83 Exemption From License - Conduit/5MW
02/28/83 P-3474-002 Ltr notice extending 45 days to correct deficiencies in appl for exemption of Lake Junaluska Hydro Proj.Availability: Public
Notice /
02/28/83 Formal Notice
01/19/83 P-3474-002 Fwds appl for Lake Junaluska Assembly appl for exemption re Lake Junaluska Dam Proj.Availability: Public
Applicant Correspondence /
01/21/83 Untyped During RIMS II Conversion
Randall G. Alley, MSEE
Star Earth Energy, LLC 53
01/19/83 P-3474-002 Appl for exemption from licensing by Lake Junaluska Assembly re Lake Junaluska Hydro Proj.Availability: Public
Application/Petition/Request /
01/21/83 Exemption From License - Conduit/5MW