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Star Earth Energy, LLC


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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


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


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



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.



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.

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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

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c)

Date of Flow Reading

Richland Creek Flow DataUSGS Data 1988 - 2008

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1 51 101 151 201 251 301 351

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Richland Creek Flow DataUSGS data, 1988-2008

Daily Data

Monthly Average

Correlated Data

http://www.usgs.gov/osw



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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1 2 3 4 5 6 7 8 9 10 11 12

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Pigeon River Flow USGS Data 1933 - 2008

Single Reading, sampled monthly

Average Value from 1933-2008

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1 31 61 91 121 151 181 211 241 271 301 331 361

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Pigeon River Average Daily Flow DataUSGS Data 1985 - 2008

Daily Values

Monthly Average



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

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hla

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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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Richland Creek Predicted FlowCorrelated to Pigeon River Flow using USGS data 1985-2008

Daily Data

Monthly Average

Correlated Data



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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0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

Ric

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Flow Duration (% of year)

Richland Creek Flow Duration33% Correlation to Pigeon Data (1933-2009)



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



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

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2.0 2.5 3.0 3.5 4.0

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Head Loss Due to Wall EffectsL = 20 ft, Q = 150 ft3/s

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2.0 2.5 3.0 3.5 4.0

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Head Loss Due to Wall EffectsL = 20 ft, Q = 150 ft3/s

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Head Loss Due to TurbulenceLoss Coefficient = 1.5

Q = 50 ft3/s

Q = 100 ft3/s

Q = 150 ft3/s



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

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Monthly Power Prediction (kWH)

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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



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.



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.



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/.



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.



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.



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



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.

http://www.ferc.gov/industries/hydropower.asp



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.



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



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



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



$/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.

http://hydropower.inel.gov/resourceassessment/pdfs/project_report-final_with_disclaimer-3jul03.pdf



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


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


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



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.



a) Revenue Projections - 4% Energy Inflation

Figure 32 - Revenue Prediction (125 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


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


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


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


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


1_250kW

2_250kW

3_250kW

4_250kW



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

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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)

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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.



(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)



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)

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Figure 59 - Simple ROI (For-profit, S6, 4% EI)





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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.


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.




The trends are as above. The profit prediction increases to 5.3 $million, ROI to 384%, and payback to 3

years.


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.



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



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.



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



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



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



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

[email protected]

Jeffrey Lyle

828-506-0690

[email protected]


2817 Claremont Road

Raleigh, NC 27608

mailto:[email protected]

mailto:[email protected]



XV. Appendix - Revenue Predictions - 3% Energy Inflation

Figure 64 - Revenue Prediction (125kW, 3% EI)






0

1

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3

4

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Cumulative Hydroelectric Revenuc225kWKaplan, 3% Energy Inflation

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Cumulative Hydroelectric Revenuc250kWKaplan, 3% Energy Inflation

1_250kW

2_250kW

3_250kW

4_250kW



XVI. Appendix - Revenue Projections - 5% Energy Inflation







0

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4_250kW



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)


0%

50%

100%

150%

200%

250%

300%

350%

400%

450%

125 150 175 200 225 250

Sim

ple

RO

I (%

)

Turbine Size (kW)


Scenario 4

Scenario 3

Scenario 2

Scenario 1

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Turbine Size (kW)


Scenario 4

Scenario 3

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Turbine Size (kW)


Scenario 4

Scenario 3

Scenario 2

Scenario 1

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12

14

250 225 200 175 150 125

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s to

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bac

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Turbine Size (kW)


Scenario 4

Scenario 3

Scenario 2

Scenario 1

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ple

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250 kW

225 kW

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150 kW

125 kW









0.0

1.0

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225 kW

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125 kW

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ple

RO

I (%

)

Years of Operation


250 kW

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225 kW

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ple

RO

I (%

)

Years of Operation


250 kW

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ple

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225 kW

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125 kW



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)



0%

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Scenario 4

Scenario 3

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Scenario 1

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Scenario 2

Scenario 1

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Scenario 4

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Scenario 1

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s to

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Turbine Size (kW)


Scenario 4

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Scenario 2

Scenario 1

0.0

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Years of Operation


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225 kW

200 kW

175 kW

150 kW

125 kW

0%

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600%

0 5 10 15 20 25

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ple

RO

I (%

)

Years of Operation


250 kW

225 kW

200 kW

175 kW

150 kW

125 kW









0.0

1.0

2.0

3.0

4.0

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ve P

rofi

t ($

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ion

s)

Years of Operation


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


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

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mu

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ve P

rofi

t ($

Mill

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s)

Years of Operation


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


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

0 5 10 15 20 25

Cu

mu

lati

ve P

rofi

t ($

Mill

ion

s)

Years of Operation


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


250 kW

225 kW

200 kW

175 kW

150 kW

125 kW



XIX. Appendix - Ossberger Price Quote



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.

http://www.law.cornell.edu/uscode/html/uscode16/usc_sec_16_00000814----000-.html

http://www.law.cornell.edu/uscode/html/uscode16/usc_sec_16_00000823---a000-.html


http://www.law.cornell.edu/uscode/html/uscode16/usc_sec_16_00000797----000-.html

http://ecfr.gpoaccess.gov/cgi/t/text/text-idx?c=ecfr&sid=e390824e7233bb5e80958d9f81976c90&rgn=div8&view=text&node=18:1.0.1.2.9.4.20.9&idno=18
















http://www.law.cornell.edu/uscode/html/uscode42/usc_sup_01_42_10_55.html

http://www.law.cornell.edu/uscode/html/uscode42/usc_sup_01_42_10_55.html


http://www.law.cornell.edu/uscode/search/display.html?terms=2705&url=/uscode/html/uscode16/usc_sec_16_00002705----000-.html

http://www.law.cornell.edu/uscode/search/display.html?terms=2708&url=/uscode/html/uscode16/usc_sec_16_00002708----000-.html

http://www.law.cornell.edu/uscode/html/uscode16/usc_sup_01_16_10_12_20_I.html

http://ecfr.gpoaccess.gov/cgi/t/text/text-idx?c=ecfr&sid=08ee13547ec90ddd699ab0484a623fd0&rgn=div6&view=text&node=18:1.0.1.2.9.10&idno=18

http://ecfr.gpoaccess.gov/cgi/t/text/text-idx?c=ecfr&sid=08ee13547ec90ddd699ab0484a623fd0&rgn=div6&view=text&node=18:1.0.1.2.9.11&idno=18

http://ecfr.gpoaccess.gov/cgi/t/text/text-idx?c=ecfr&sid=e390824e7233bb5e80958d9f81976c90&tpl=/ecfrbrowse/Title18/18cfr5_main_02.tpl

http://ecfr.gpoaccess.gov/cgi/t/text/text-idx?c=ecfr&sid=08ee13547ec90ddd699ab0484a623fd0&tpl=/ecfrbrowse/Title18/18cfr4_main_02.tpl




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.



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 /


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



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/professional 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 /


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).


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 /


11/04/94 P-3474-000 Ltr notice to Lake Junaluska Assembly confirming recommendations made as result of annual operation inspection 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 /


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 /


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 /


07/26/93 P-3474-013 Lake Junaluska Assembly informs FERC of breakdown of hydro equipment at Lake Junaluska under P-3474.



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 /


05/10/93 P-3474-012 Order amend Lake Junaluska Assembly exemption for Lake Junaluska Proj under P-3474. Order/Opinion /


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 /


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.



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 /


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 /


09/01/92 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 /



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 /


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 /


06/03/92 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 /


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 /


12/12/91 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 /


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 /


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 /


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 /


03/07/91 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


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 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 /


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 /


11/15/90 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 /


11/15/90 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 /


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



10/25/90 P-3474-000 Ltr order accepting plan & sched for responding to recommendations 1-3 in recent operation insp of Lake Junaluska Proj-3474.Availability: Public

Order/Opinion /


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 /


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



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



04/03/90 P-3474-000 Response to Lake Junaluska Assembly 900326 ltr requesting copy of exemption under P-3474. PART 12Availability: Public



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 /


03/12/90 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



02/09/90 P-3474-006 Order granting extension of time re Lake Junaluska Assembly under P-3474-006. Order/Opinion /


01/10/90 P-3474-006 Comments of United Methodist Chruch re Lake Junaluska hydropower Proj under P-3474.Availability: Public





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 /


09/27/89 P-3474-005 United Methodist Church requests addl time for completion of Lake Junaluska Assembly Hydro Power Proj.Availability: Public



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 /


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 /


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 /


02/08/88 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 /


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 /


09/30/87 P-3474-000 Lake Junaluska Assembly request an extension of time to complete Part 12 rept for Lake Junaluska Dam Proj.Availability: Public



08/13/87 P-3474-000 Requests Lake Junaluska to submit inspection rept by 871012 for Lake Junaluska Proj.Availability: Public



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 /


06/08/87 P-3474-003 Lake Junaluska Assembly request extension of time to complete 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



03/12/87 P-3474-000 Lake Junaluska Assembly informs FERC that BL Williams will assume liaison duties for Lake Junaluska Proj.Availability: Public



10/31/85 P-3474-000 Ltr order approving R Hunt as consultant for initial insp of Lake Junaluska Proj. 851031Availability: Public

Order/Opinion /


09/12/85 P-3474-000 Acks receipt of Lake Junaluska Assembly revised EAP & addl info re Lake Junaluska Proj.Availability: Public



09/17/85 P-3474-000 Ltr order denying request of ELI Corp for exemption of Lake Junaluska Hydro Proj. 850917Availability: Public

Order/Opinion /


08/30/85 P-3474-000 Submits request for exemption of safety insp for Lake Junaluska Hydro Proj.Availability: CEII Report/Form /


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



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 /


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 /


05/09/83 P-3474-002 Submits exhibits to Lake Junaluska Assembly appl for lic re P-3474-002.Availability: Public Application/Petition/Request /


05/03/83 P-3474-002 Notice of case specific exemption appl of Lake Junaluska Assembly for Lake Junaluska Proj.Availability: Public

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 /


03/14/83 P-3474-002 Suppl to appl of Lake Junaluska Assembly for lic exemption. Submits deeds showing site ownership.Availability: Public



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 /


01/19/83 P-3474-002 Fwds appl for Lake Junaluska Assembly appl for exemption re Lake Junaluska Dam Proj.Availability: Public





01/19/83 P-3474-002 Appl for exemption from licensing by Lake Junaluska Assembly re Lake Junaluska Hydro Proj.Availability: Public



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