Star Earth Energy, LLC
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
0
Randall G. Alley, MSEE
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
Star Earth Energy, LLC 1
Randall G. Alley, MSEE
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
2 Star Earth Energy, LLC
Randall G. Alley, MSEE
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.
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Randall G. Alley, MSEE
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.
Richland Creek Flow Data Richland Creek Flow Data USGS Data 1988 - 2008 USGS data, 1988-2008 250 180 Daily Data 160 Monthly Average 200 140 Correlated Data
120 150 100
80 100
Flow (ft3/sec) Flow 60 Flow (ft3/sec) Flow
50 40
20
0 0 01-Jan-88 01-Jan-91 01-Jan-94 01-Jan-97 02-Jan-00 02-Jan-03 02-Jan-06 02-Jan-09 1 51 101 151 201 251 301 351 Date of Flow Reading Day Number
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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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 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Flow (ft3/s) Flow Flow Flow Flow Flow Flow Flow Flow Flow Flow Flow 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.
Pigeon River Flow Pigeon River Average Daily Flow Data USGS Data 1933 - 2008 USGS Data 1985 - 2008 1200 1200
Single Reading, sampled monthly 1000 1000 Daily Values Average Value from 1933-2008 Monthly Average 800 800
600 600
400 400
Flow (ft3/sec) Flow (ft3/sec) Flow
200 200
0 0 1 2 3 4 5 6 7 8 9 10 11 12 1 31 61 91 121 151 181 211 241 271 301 331 361 Month Day of the Year
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 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Flow (ft3/s) Flow Flow Flow Flow Flow Flow Flow Flow Flow Flow Flow 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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Randall G. Alley, MSEE
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.
Estimating Richland Flow from Pigeon Flow Richland Creek Predicted Flow Method: Linear Correlation of data from same day Correlated to Pigeon River Flow using USGS data 1985-2008 200 180 y = 0.3323x Daily Data R² = 0.8252 160 175 Monthly Average 140 Correlated Data 150 120 125 100
100 80
60 75 (ft3/sec) Flow
40 50 Richland vs. Pigeon Data
Richland Richland CreekFlow (ft3/s) Linear (Richland vs. Pigeon 20 25 Data) 0 0 1 51 101 151 201 251 301 351 0 100 200 300 400 500 600 Day Number Pigeon River Flow (ft3/s)
Figure 5 - Correlating Richland to Pigeon Flow Figure 6 - Richland Creek Predicted Flow
Yearly Average Flow Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec (ft3/s) Flow Flow Flow Flow Flow Flow Flow Flow Flow Flow Flow 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.
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Richland Creek Flow Duration 33% Correlation to Pigeon Data (1933-2009) 200
175
150
125
100
Richland Richland CreekFlow (ft3/s) 75
50 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Flow Duration (% of year)
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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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.
Roadway
Lake Level
Generator Room
Potential Head = ~20 ft
Shutoff Valve
Intake Slide Gates
Intake Pipe (~20 ft) Turbine
Lake Bottom
Discharge
Gravel Bed
Figure 8 - Dam Cross-Section (not to scale)
Total Entrance Contraction 45deg Bend Gate Valve Loss Coefficients 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.
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Randall G. Alley, MSEE
Head Loss Due to Wall Effects Head Loss Due to Wall Effects L = 20 ft, Q = 150 ft3/s L = 20 ft, Q = 150 ft3/s 4.0 20
18
16 3.0 14
12
2.0 10
8
Head Loss Loss Head (ft) Head Loss Loss Head (%) 6 1.0 4
2
0.0 0 2.0 2.5 3.0 3.5 4.0 2.0 2.5 3.0 3.5 4.0 Penstock Pipe Diameter (ft) Penstock Pipe Diameter (ft)
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
Head Loss Due to Turbulence Loss Coefficient = 1.5 12.0
Q = 50 ft3/s 10.0 Q = 100 ft3/s
Q = 150 ft3/s 8.0
6.0
Head Loss Loss Head (ft) 4.0
2.0 Total Turbine Generator Utilization Efficiency Efficiency Efficiency Efficiency 0.0 3.5 4.0 4.5 5.0 5.5 6.0 Penstock Pipe Diameter (ft) 0.779 0.90 0.90 0.962
Figure 11 - Head Loss Due to Turbulence (ft) 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.
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Randall G. Alley, MSEE
Monthly Power Prediction (kWH) Instantaneous Power Prediction (kW)
160,000 250
140,000 200 120,000
100,000 150
80,000
100
60,000
Power (kWH) Power Power (kWH) Power 40,000 50 20,000
0 0 Jan Mar May Jul Sep Nov Jan Mar May Jul Sep Nov Month Month
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.
Generator Room Top View (not to scale)
Generator Room
By-Pass Pipe (~20 ft) By-Pass By-Pass Valve Intake 2 Room Discharge Intake Slide Transition Gates
Turbine Turbine Intake Pipe (~20 ft) Turbine Turbine Isolation Valve Intake 1 Room Discharge
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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Randall G. Alley, MSEE 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 Figure 17 - Intake Gate 2 Superstructure
6 North Fork Electric, Inc, http://www.nfei.com/LakeJun1.html.
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Figure 18 - Intake Gate 1 (interior left) Figure 19 - Intake Gate 1 (interior right)
Figure 20 - Interior of Trash Screen with Figure 21 - Close-up of Trash Screen Gate Hydraulics Dry Wells
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.
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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/.
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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.
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Randall G. Alley, MSEE 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.
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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
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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.
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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 Fixed Long-Term Credits Credit 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.
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Randall G. Alley, MSEE 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
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Randall G. Alley, MSEE 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 & - Existing equipment bypass Intake Transition 2x custom Gate to penstock transition - Penstock Piping 2x custom Direct flow to turbine 5’ diameter, 40’ Length, Steel or - & By-pass 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 5’ Diameter, Automated Positive flow shut-off & By-pass Turbine 1x Ossberger Energy extraction from flow SH600 Double-Cell Cross-flow 125 kW Peak Output or equivalent Kaplan Turbine Turbine Frame 1x Ossberger Turbine mounting Turbine Control 1x Ossberger Turbine control system Panel Water Level 1x Ossberger Head level controller Controls lake level & flow to Regulator 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
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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.
Item Description Input value Unit 1 OSSBERGER Turbine (SH600 double cell) Head Level Controller yes - 2 Baseframe Grid Parallel Operation yes - 3 OSSBERGER Water Level Regulator (automatic operation) Static Head 20.0 ft 4 Turbine Control Panel Net Head 19.6 ft 5 Transition Piece and Draft Tube Max. Flow 88 cfs 6 Service Valve Min. Flow 9 cfs 7 FLENDER Speed Increaser with Couplings Turbine Output 123 kW 8 HITZINGER Induction Generator Generator Output 114 kW 125 kW,1200 RPM, 480V/3/60, RTD’s, overspeed capable Turbine Nominal 153 rpm Price Estimate EUR 250,000 Generator Nominal Speed 1220 rpm US $ $350,305 (exchange rate 10/21/2010)
Table 8 - Ossberger Quote Assumptions Table 9 - Ossberger Scope of Supply
2. Survey of Hydroelectric Costs
Micro Hydro Development Costs 2010 Dollars
7,000
6,000
5,000
4,000
3,000
2,000
1,000 Development Cost Development Cost ($/kW) Ossberger Equipment 350,305 0 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)
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 $4,386
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$/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.
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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.
Tax Power Power Sale Power Sale Peak Business Owns Credits Seller Method Power Value Demand REC Model Scenario Facility <<<< >>>> >>>> Consumer ($/kW) Mitigation Owner Comment Assembly 1 A - A Sell all w/ PPA Utility ~0.055 No A Owns & 2 A - A Sell all w/ PPA Utility ~0.075 No NC Operates + NC Green Green Facility 3 A - A Sell excess Assembly ~0.08 Yes A w/ Net Meter &Utility 4 A - - Sell none Assembly ~0.11 Yes A Must be off-grid, backup complications. Power 5 D Yes D Sell all w/ Utility ~0.055 No D D leases dam from A. Developer (for D) PPA (same $ as 1) D earns tax credits. Owns & 6 D Yes D Sell all w/ PPA Utility ~0.075 No NC D leases dam from A. Operates (for D) + NC Green (same $ as 2) Green D earns tax credits. Facility Power 7 D Yes A Sell all w/ PPA Utility ~0.055 No A D leases dam from A. Developer (for D) (same $ as 1) D earns tax credits. Owns & A leases facility from D. Leases 8 D Yes A Sell all w/ PPA Utility ~0.075 No NC D leases dam from A. Facility (for D) + NC Green (same $ as 2) Green D earns tax credits. A leases system from D. 9 D Yes A Sell excess Assembly ~0.08 No A (for D) w/ Net Meter &Utility (same $ as 3) 10 D Yes A Sell none Assembly ~0.11 Yes A Must be off-grid, backup (for D) (same $ as 4) 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
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Randall G. Alley, MSEE 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 Gross Turbine Generator System Inflation Turbine Head Flow Efficiency Efficiency Utilization Efficiency (%) Type (ft) (cfs) (%) (%) (%) (%) 3%, 4%, 5% Kaplan 28 106.1 0.900 0.950 0.962 0.822
Table 12 - Common Revenue Simulation Inputs
REC System Power REC System Power Value Size Value Value Size Value Scenario Degrade ($) (kW) ($/kWh) Scenario Degrade ($) (kW) ($/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.
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a) Revenue Projections - 4% Energy Inflation
Cumulative Hydroelectric Revenuc Cumulative Hydroelectric Revenuc 125kW Kaplan, 4% Energy Inflation 150kW Kaplan, 4% Energy Inflation 9 9
8 8
7 7
6 6 1_125kW 1_150kW 5 2_125kW 5 2_150kW 3_125kW 3_150kW 4 4 4_125kW 4_150kW 3 3
2 2
Cumulative Revenue ($M) Revenue Cumulative ($M) Revenue Cumulative
1 1
0 0 0 5 10 15 20 25 0 5 10 15 20 25 Years of Operation Years of Operation
Figure 32 - Revenue Prediction (125 kW, 4% EI) Figure 33 - Revenue Prediction (150 kW, 4% EI)
Cumulative Hydroelectric Revenuc Cumulative Hydroelectric Revenuc 175kW Kaplan, 4% Energy Inflation 200kW Kaplan, 4% Energy Inflation 9 9
8 8
7 7
6 6 1_175kW 1_200kW 5 2_175kW 5 2_200kW 3_175kW 3_200kW 4 4 4_175kW 4_200kW 3 3
2 2
Cumulative Revenue ($M) Revenue Cumulative ($M) Revenue Cumulative
1 1
0 0 0 5 10 15 20 25 0 5 10 15 20 25 Years of Operation Years of Operation
Figure 34 - Revenue Prediction (175 kW, 4% EI) Figure 35 - Revenue Prediction (200 kW, 4% EI)
Cumulative Hydroelectric Revenuc Cumulative Hydroelectric Revenuc 225kW Kaplan, 4% Energy Inflation 250kW Kaplan, 4% Energy Inflation 9 9
8 8
7 7
6 6 1_225kW 1_250kW 5 2_225kW 5 2_250kW 3_225kW 3_250kW 4 4 4_225kW 4_250kW 3 3
2 2
Cumulative Revenue ($M) Revenue Cumulative Cumulative Revenue ($M) Revenue Cumulative
1 1
0 0 0 5 10 15 20 25 0 5 10 15 20 25 Years of Operation Years of Operation
Figure 36 - Revenue Prediction (225 kW, 4% EI) Figure 37 - Revenue Prediction (250 kW, 4% EI)
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b) Degraded Input Revenue Projections - 4% Energy Inflation
Cumulative Hydroelectric Revenuc Cumulative Hydroelectric Revenuc 125kW Kaplan, 4% Energy Inflation 150kW Kaplan, 4% Energy Inflation 9 9
8 8
7 7
6 6 1_125kW 1_150kW 5 2_125kW 5 2_150kW 3_125kW 3_150kW 4 4 4_125kW 4_150kW 3 3
2 2
Cumulative Revenue ($M) Revenue Cumulative Cumulative Revenue ($M) Revenue Cumulative
1 1
0 0 0 5 10 15 20 25 0 5 10 15 20 25 Years of Operation Years of Operation
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 $12,000 in the first year. Both labor and maintenance are increased by the inflation assumption of 2%. Profits earn an interest rate based on 20 year Treasury Bond earnings. The model simulates either non-profit or for-profit ownership. The table shows the tax rate, tax credit and depreciation values used in the case of for-profit ownership. The Profit and ROI predictions for the 4% energy inflation, non-profit cases are shown below. The 3% and 5% non-profit cases are contained in Appendix XVII.
System Interest Federal State Cost Operating Maintenance Inflation Rate Federal State Energy Energy per kW Costs Costs Rate 20 yr T-Bill Tax Rate Tax Rate Credit Credit Federal State ($/kW) ($) (% of System) (%) (%) (%) (%) (%) (%) Depreciation Depreciation $4,386 $12,000 1% 2% 3.5% 34% 6.9% 30% 35% MACRS Straight Line
Table 14 - Profit and ROI Simulation Inputs
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a) ROI Predictions - Non-profit Ownership, 4% Energy Inflation
Simple ROI After 25 Years Cumulative Profit After 25 Years Kaplan Turbine, 4% Energy Inflation Kaplan Turbine, 4% Energy Inflation 500% 10
450% 9
400% 8
350% 7
300% Scenario 4 6 Scenario 4 Scenario 3 Scenario 3 250% 5 Scenario 2 Scenario 2 200% Scenario 1 4 Scenario 1
Simple ROI (%) ROI Simple 150% 3
100% 2
50% 1 Cumulative 25 Year Profit ($Millions) Profit Year 25 Cumulative 0% 0 125 150 175 200 225 250 125 150 175 200 225 250 Turbine Size (kW) Turbine Size (kW)
Figure 40 - ROI vs. Turbine (Non-profit, 4% EI) Figure 41 - Profit vs. Turbine (Non-profit, 4% EI)
Annualized ROI After 25 Years Simple Payback Kaplan Turbine, 4% Energy Inflation Kaplan Turbine, 4% Energy Inflation 24% 14 22% 12 20% 18% 10 16% Scenario 4 Scenario 4 14% 8 Scenario 3 Scenario 3 12% Scenario 2 Scenario 2 10% 6 Scenario 1 Scenario 1
Simple ROI (%) ROI Simple 8% Years to Payback to Years 4 6% 4% 2 2% 0% 0 125 150 175 200 225 250 250 225 200 175 150 125 Turbine Size (kW) Turbine Size (kW)
Figure 42 - Annualized ROI (Non-profit, 4% EI) Figure 43 - Simple Payback (Non-profit, 4% EI)
Cumulative Profit - Scenario 1 Simple ROI - Scenario 1 Kaplan Turbine, 4% Energy Inflation Kaplan Turbine, 4% Energy Inflation 7.0 500%
450% 6.0 400%
5.0 250 kW 350% 250 kW
225 kW 300% 225 kW 4.0 200 kW 200 kW 250% 175 kW 175 kW 3.0 150 kW 200% 150 kW
125 kW (%) ROI Simple 125 kW 2.0 150%
100%
Cumulative Profit ($Millions) Profit Cumulative 1.0 50%
0.0 0% 0 5 10 15 20 25 0 5 10 15 20 25 Years of Operation Years of Operation
Figure 44 - Profit (Non-profit, S1, 4% EI) Figure 45 - Simple ROI (Non-profit, S1, 4% EI)
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Cumulative Profit - Scenario 2 Simple ROI - Scenario 2 Kaplan Turbine, 4% Energy Inflation Kaplan Turbine, 4% Energy Inflation 7.0 500%
450% 6.0 400%
5.0 250 kW 350% 250 kW
225 kW 300% 225 kW 4.0 200 kW 200 kW 250% 175 kW 175 kW 3.0 150 kW 200% 150 kW
Simple ROI (%) ROI Simple 125 kW 2.0 125 kW 150%
100%
Cumulative Profit ($Millions) Profit Cumulative 1.0 50%
0.0 0% 0 5 10 15 20 25 0 5 10 15 20 25 Years of Operation Years of Operation
Figure 46 - Profit (Non-profit, S2, 4% EI) Figure 47 - Simple ROI (Non-profit, S2, 4% EI)
Cumulative Profit - Scenario 3 Simple ROI - Scenario 3 Kaplan Turbine, 4% Energy Inflation Kaplan Turbine, 4% Energy Inflation 7.0 500%
450% 6.0 400%
5.0 250 kW 350% 250 kW
225 kW 300% 225 kW 4.0 200 kW 200 kW 250% 175 kW 175 kW 3.0 150 kW 200% 150 kW
Simple ROI (%) ROI Simple 125 kW 2.0 125 kW 150%
100%
Cumulative Profit ($Millions) Profit Cumulative 1.0 50%
0.0 0% 0 5 10 15 20 25 0 5 10 15 20 25 Years of Operation Years of Operation
Figure 48 - Profit (Non-profit, S3, 4% EI) Figure 49 - Simple ROI (Non-profit, S3, 4% EI)
Cumulative Profit - Scenario 4 Simple ROI - Scenario 4 Kaplan Turbine, 4% Energy Inflation Kaplan Turbine, 4% Energy Inflation 8.0 500%
450% 7.0 400% 6.0 250 kW 350% 250 kW 5.0 225 kW 300% 225 kW 200 kW 200 kW 4.0 250% 175 kW 175 kW 200% 3.0 150 kW 150 kW
125 kW (%) ROI Simple 150% 125 kW 2.0 100%
Cumulative Profit ($Millions) Profit Cumulative 1.0 50%
0.0 0% 0 5 10 15 20 25 0 5 10 15 20 25 Years of Operation Years of Operation
Figure 50 - Profit (Non-profit, S4, 4% EI) Figure 51 - Simple ROI (Non-profit, S4, 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.
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Randall G. Alley, MSEE
(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 $million, a 497% ROI and a payback of 5 years.
3% Energy Inflation 4% Energy Inflation 5% Energy Inflation 25 25 25 25 25 25 Power Turbine Year Year Years to Year Year Years to Year Year Years to Value Size Estimated Profit ROI Simple Profit ROI Simple Profit ROI Simple Scenario (cents/kW) (kW) Cost ($M) ($M) (%) Payback ($M) (%) Payback ($M) (%) Payback 1 5.5 250 1.097 2.00 106% 13 2.63 139% 12 3.36 177% 12 1 5.5 225 0.987 2.02 115% 13 2.62 150% 12 3.32 190% 11 1 5.5 200 0.877 2.00 125% 12 2.57 161% 11 3.24 203% 11 1 5.5 175 0.768 1.91 132% 11 2.45 169% 11 3.07 212% 10 1 5.5 150 0.658 1.76 135% 11 2.24 173% 11 2.80 216% 10 1 5.5 125 0.548 1.50 131% 11 1.92 167% 10 2.41 210% 10 2 7.5 250 1.097 3.53 186% 10 4.37 231% 10 5.35 282% 9 2 7.5 225 0.987 3.49 200% 9 4.30 246% 9 5.23 300% 9 2 7.5 200 0.877 3.41 214% 9 4.17 262% 9 5.06 317% 8 2 7.5 175 0.768 3.23 223% 9 3.94 272% 8 4.76 329% 8 2 7.5 150 0.658 2.95 228% 8 3.59 277% 8 4.34 335% 8 2 7.5 125 0.548 2.54 221% 8 3.09 270% 8 3.74 326% 8 3 8.0 250 1.097 4.15 219% 9 5.07 267% 9 6.14 324% 9 3 8.0 225 0.987 4.08 234% 9 4.96 284% 8 5.99 343% 8 3 8.0 200 0.877 3.97 249% 8 4.81 301% 8 5.78 362% 8 3 8.0 175 0.768 3.75 259% 8 4.53 313% 8 5.43 375% 7 3 8.0 150 0.658 3.42 264% 8 4.13 318% 7 4.95 381% 7 3 8.0 125 0.548 2.95 257% 7 3.56 310% 7 4.27 372% 7 4 11.0 250 1.097 6.81 359% 7 8.07 426% 7 9.54 503% 6 4 11.0 225 0.987 6.64 380% 6 7.85 449% 6 9.26 530% 6 4 11.0 200 0.877 6.41 401% 6 7.55 473% 6 8.88 557% 6 4 11.0 175 0.768 6.01 416% 6 7.08 489% 6 8.31 575% 6 4 11.0 150 0.658 5.48 422% 6 6.44 497% 5 7.56 583% 5 4 11.0 125 0.548 4.73 412% 5 5.57 485% 5 6.54 570% 5
Table 15 - Summary of Results (Non-profit, Kaplan)
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Randall G. Alley, MSEE
c) Profit & ROI Predictions - For-profit Ownership, 4% Energy Inflation
Simple ROI After 25 Years Cumulative Profit After 25 Years Kaplan Turbine, 4% Energy Inflation Kaplan Turbine, 4% Energy Inflation 650% 12 600% 550% 10 500%
450% 8 400% Scenario 4 Scenario 4 350% Scenario 3 Scenario 3 6 300% Scenario 2 Scenario 2 250% Scenario 1 Scenario 1
Simple ROI (%) ROI Simple 4 200% 150% 100% 2
50% Cumulative 25 Year Profit ($Millions) Profit Year 25 Cumulative 0% 0 125 150 175 200 225 250 125 150 175 200 225 250 Turbine Size (kW) Turbine Size (kW)
Figure 52 - ROI vs. Turbine (For-profit, 4% EI) Figure 53 - Profit vs. Turbine (For-profit, 4% EI)
Annualized ROI After 25 Years Simple Payback Kaplan Turbine, 4% Energy Inflation Kaplan Turbine, 4% Energy Inflation 24% 5 22% 20% 4 18% 16% Scenario 4 Scenario 4 14% 3 Scenario 3 Scenario 3 12% Scenario 2 Scenario 2 10% Scenario 1 2 Scenario 1
Simple ROI (%) ROI Simple 8% Years to Payback to Years 6% 1 4% 2% 0% 0 125 150 175 200 225 250 250 225 200 175 150 125 Turbine Size (kW) Turbine Size (kW)
Figure 54 - Annualized ROI (For-profit, 4% EI) Figure 55 - Simple Payback (For-profit, 4% EI)
Cumulative Profit - Scenario 1 Simple ROI - Scenario 1 Kaplan Turbine, 4% Energy Inflation Kaplan Turbine, 4% Energy Inflation 7.0 500%
450% 6.0 400%
5.0 250 kW 350% 250 kW
225 kW 300% 225 kW 4.0 200 kW 200 kW 250% 175 kW 175 kW 3.0 150 kW 200% 150 kW
125 kW (%) ROI Simple 125 kW 2.0 150%
100%
Cumulative Profit ($Millions) Profit Cumulative 1.0 50%
0.0 0% 0 5 10 15 20 25 0 5 10 15 20 25 Years of Operation Years of Operation
Figure 56 - Profit (For-profit, S5, 4% EI) Figure 57 - ROI (For-profit, S5, 4% EI)
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Randall G. Alley, MSEE
Cumulative Profit - Scenario 2 Simple ROI - Scenario 2 Kaplan Turbine, 4% Energy Inflation Kaplan Turbine, 4% Energy Inflation 7.0 500%
450% 6.0 400%
5.0 250 kW 350% 250 kW
225 kW 300% 225 kW 4.0 200 kW 200 kW 250% 175 kW 175 kW 3.0 150 kW 200% 150 kW
Simple ROI (%) ROI Simple 125 kW 2.0 125 kW 150%
100%
Cumulative Profit ($Millions) Profit Cumulative 1.0 50%
0.0 0% 0 5 10 15 20 25 0 5 10 15 20 25 Years of Operation Years of Operation
Figure 58 - Profit (For-profit, S6, 4% EI) Figure 59 - Simple ROI (For-profit, S6, 4% EI)
Cumulative Profit - Scenario 3 Simple ROI - Scenario 3 Kaplan Turbine, 4% Energy Inflation Kaplan Turbine, 4% Energy Inflation 7.0 500%
450% 6.0 400%
5.0 250 kW 350% 250 kW
225 kW 300% 225 kW 4.0 200 kW 200 kW 250% 175 kW 175 kW 3.0 150 kW 200% 150 kW
Simple ROI (%) ROI Simple 125 kW 2.0 125 kW 150%
100%
Cumulative Profit ($Millions) Profit Cumulative 1.0 50%
0.0 0% 0 5 10 15 20 25 0 5 10 15 20 25 Years of Operation Years of Operation
Figure 60 - Profit (For-profit, S9, 4% EI) Figure 61 - Simple ROI (For-profit, S9, 4% EI)
Cumulative Profit - Scenario 4 Simple ROI - Scenario 4 Kaplan Turbine, 4% Energy Inflation Kaplan Turbine, 4% Energy Inflation 10.0 600%
9.0 550% 500% 8.0 450% 7.0 250 kW 250 kW 400% 225 kW 225 kW 6.0 350% 200 kW 200 kW 5.0 300% 175 kW 175 kW 250% 4.0 150 kW 150 kW
Simple ROI (%) ROI Simple 200% 3.0 125 kW 125 kW 150% 2.0
100% Cumulative Profit ($Millions) Profit Cumulative 1.0 50% 0.0 0% 0 5 10 15 20 25 0 5 10 15 20 25 Years of Operation Years of Operation
Figure 62 - Profit (For-profit, S10, 4% EI) Figure 63 - Simple ROI (For-profit, S10, 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.
3% Energy Inflation 4% Energy Inflation 5% Energy Inflation 25 25 25 25 25 25 Power Turbine Year Year Years to Year Year Years to Year Year Years to Value Size Estimated Profit ROI Simple Profit ROI Simple Profit ROI Simple Scenario (cents/kW) (kW) Cost ($M) ($M) (%) Payback ($M) (%) Payback ($M) (%) Payback 1 5.5 250 1.097 3.75 184% 4 4.39 216% 4 5.14 253% 4 1 5.5 225 0.987 3.61 193% 4 4.22 226% 4 4.94 264% 4 1 5.5 200 0.877 3.43 201% 4 4.02 236% 4 4.70 275% 4 1 5.5 175 0.768 3.18 206% 4 3.72 241% 4 4.35 282% 4 1 5.5 150 0.658 2.85 207% 4 3.34 242% 4 3.91 284% 4 1 5.5 125 0.548 2.41 198% 4 2.84 233% 4 3.33 274% 4 2 7.5 250 1.097 5.39 265% 4 6.24 307% 4 7.22 356% 4 2 7.5 225 0.987 5.18 277% 4 5.99 321% 4 6.93 371% 4 2 7.5 200 0.877 4.92 289% 4 5.69 334% 4 6.59 386% 3 2 7.5 175 0.768 4.56 296% 3 5.27 342% 3 6.10 396% 3 2 7.5 150 0.658 4.10 298% 3 4.75 344% 3 5.50 399% 3 2 7.5 125 0.548 3.50 288% 3 4.06 334% 3 4.71 388% 3 3 8.0 250 1.097 6.03 297% 4 6.96 343% 4 8.04 396% 4 3 8.0 225 0.987 5.79 310% 3 6.68 358% 3 7.71 413% 3 3 8.0 200 0.877 5.50 323% 3 6.35 372% 3 7.32 430% 3 3 8.0 175 0.768 5.10 331% 3 5.88 382% 3 6.79 440% 3 3 8.0 150 0.658 4.59 333% 3 5.30 384% 3 6.12 444% 3 3 8.0 125 0.548 3.92 323% 3 4.53 373% 3 5.25 432% 3 4 11.0 250 1.097 8.78 432% 3 10.05 495% 3 11.52 567% 3 4 11.0 225 0.987 8.42 451% 3 9.64 516% 3 11.04 591% 3 4 11.0 200 0.877 8.00 469% 3 9.15 537% 3 10.48 615% 3 4 11.0 175 0.768 7.41 481% 3 8.48 550% 3 9.72 631% 3 4 11.0 150 0.658 6.68 485% 3 7.65 555% 3 8.77 636% 3 4 11.0 125 0.548 5.74 472% 3 6.58 541% 3 7.55 621% 3
Table 16 - Summary of Results (For-profit, Kaplan)
(1) Scenario 5 (coded 1 in graphs) In Scenario 1 is the case where the for-profit company owns the facility, the ROI is again optimized by using the 15o kW turbine. For the 4% energy inflation case, the model predicts a profit of 3.34 $million, a 49% increase over the non-profit case. The ROI and payback are similarly improved, with values 242% and 4 years respectively.
(2) Scenario 6 (coded 2 in graphs) The trends are as above. ROI is again optimized by using the 15o kW turbine. With the inclusion of tax credits and deductions, the profit prediction improves to 4.75 $million, an increase of 32%. ROI and payback improved to 344% 3 years, respectively.
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Randall G. Alley, MSEE
(3) Scenario 9 (coded 3 in graphs) The trends are as above. The profit prediction increases to 5.3 $million, ROI to 384%, and payback to 3 years.
(4) Scenario 10 (coded 4 in graphs) The trends are as above. The profit prediction increases to 6.44 $million, ROI to 497% and payback to 5 years.
IX. Discussion A. Suitability of Lake Junaluska Site The Lake Junaluska site has the advantage of existing infrastructure in the form of an existing dam, trash screens, flow gates and an existing power house. The dam has recently undergone substantial repairs and reinforcement.
Additional equipment in the form of large diameter penstock pipe, automated gate valves to control flow, and potentially a flow diversion penstock will be needed to support a generation system. Additionally, if a cross-flow turbine is selected, a 25% increase in head can be achieved by creating a mounting area below the existing generator room. This would increase the output by a corresponding amount. If a Kaplan turbine is chosen, the head will be naturally maximized at approximately 28 feet.
While the water pressure, or “feet of head” is considered in the low range, a reasonably healthy, if somewhat variable, flow helps to compensate for that deficiency. The resulting power output has the potential to exceed 200 kW (kilowatt), the equivalent of a 1 MW (megawatt) photovoltaic system costing considerably more. A turbine designed for low head and variable flow should be used to help optimize the system efficiency, which directly impacts profitability and ROI. Cross-flow and Kaplan turbines can be designed to meet these criteria. B. Regulatory Issues No regulatory obstacles have been uncovered. If the project moves forward, a standard permitting process involving the Federal Energy Resource Commission (FERC), the NC Dept. of Environment and Natural Resources (DENR) and NC Utilities Commission will be required. C. Business Model Several different business modes and power sale schemes have been discussed. The Lake Junaluska Assembly must decide which of these options fits with their needs and expectations. Hydroelectric systems are capital intensive, and this project is not an exception. Unfortunately, as a non-profit entity, the Assembly cannot take advantage of federal and state tax credits. The reasonably healthy profit projections may mitigate this disadvantage somewhat. Any grants that could be secured to help defray the initial system cost would obviously improve the profit projections.
There is the possibility of allowing a private power developer to capitalize the project, and either operate the facility with a site lease from the Assembly, or lease the facility to the Assembly to operate. This arrangement would require careful legal construction, as the NCUC would prohibit the “sale of power” from a developer to the Assembly. Alternatively, it should be possible for the Assembly to lease the generation facility, and use or sell any power it produces.
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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
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Randall G. Alley, MSEE
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.
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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
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Randall G. Alley, MSEE
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
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Randall G. Alley, MSEE
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
Star Earth Energy, LLC 39
Randall G. Alley, MSEE 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]
Star Earth Energy, LLC 2817 Claremont Road Raleigh, NC 27608
40 Star Earth Energy, LLC
Randall G. Alley, MSEE
XV. Appendix - Revenue Predictions - 3% Energy Inflation
Cumulative Hydroelectric Revenuc Cumulative Hydroelectric Revenuc 125kW Kaplan, 3% Energy Inflation 150kW Kaplan, 3% Energy Inflation 9 9
8 8
7 7
6 6 1_125kW 1_150kW 5 2_125kW 5 2_150kW 3_125kW 3_150kW 4 4 4_125kW 4_150kW 3 3
2 2
Cumulative Revenue ($M) Revenue Cumulative Cumulative Revenue ($1M) Revenue Cumulative
1 1
0 0 0 5 10 15 20 25 0 5 10 15 20 25 Years of Operation Years of Operation
Figure 64 - Revenue Prediction (125kW, 3% EI) Figure 65 - Revenue Prediction (150 kW, 3% EI)
Cumulative Hydroelectric Revenuc Cumulative Hydroelectric Revenuc 175kW Kaplan, 3% Energy Inflation 200kW Kaplan, 3% Energy Inflation 9 9
8 8
7 7
6 6 1_175kW 1_200kW 5 2_175kW 5 2_200kW 3_175kW 3_200kW 4 4 4_175kW 4_200kW 3 3
2 2
Cumulative Revenue ($M) Revenue Cumulative ($M) Revenue Cumulative
1 1
0 0 0 5 10 15 20 25 0 5 10 15 20 25 Years of Operation Years of Operation
Figure 66 - Revenue Prediction (175 kW, 3% EI) Figure 67 - Revenue Prediction (200 kW, 3% EI)
Cumulative Hydroelectric Revenuc Cumulative Hydroelectric Revenuc 225kWKaplan, 3% Energy Inflation 250kWKaplan, 3% Energy Inflation 9 9
8 8
7 7
6 6 1_225kW 1_250kW 5 2_225kW 5 2_250kW 3_225kW 3_250kW 4 4 4_225kW 4_250kW 3 3
2 2
Cumulative Revenue ($M) Revenue Cumulative ($M) Revenue Cumulative
1 1
0 0 0 5 10 15 20 25 0 5 10 15 20 25 Years of Operation Years of Operation
Figure 68 - Revenue Prediction (225 kW, 3% EI) Figure 69 - Revenue Prediction (250 kW, 3% EI)
Star Earth Energy, LLC 41
Randall G. Alley, MSEE
XVI. Appendix - Revenue Projections - 5% Energy Inflation
Cumulative Hydroelectric Revenuc Cumulative Hydroelectric Revenuc 125kW Kaplan, 5% Energy Inflation 150kW Kaplan, 5% Energy Inflation 9 9
8 8
7 7
6 6 1_125kW 1_150kW 5 2_125kW 5 2_150kW 3_125kW 3_150kW 4 4 4_125kW 4_150kW 3 3
2 2
Cumulative Revenue ($M) Revenue Cumulative ($M) Revenue Cumulative
1 1
0 0 0 5 10 15 20 25 0 5 10 15 20 25 Years of Operation Years of Operation
Figure 70 - Revenue Prediction (125 kW, 5% EI) Figure 71 - Revenue Prediction (150 kW, 5% EI)
Cumulative Hydroelectric Revenuc Cumulative Hydroelectric Revenuc 175kW Kaplan, 5% Energy Inflation 200kW Kaplan, 5% Energy Inflation 9 9
8 8
7 7
6 6 1_175kW 1_200kW 5 2_175kW 5 2_200kW 3_175kW 3_200kW 4 4 4_175kW 4_200kW 3 3
2 2
Cumulative Revenue ($M) Revenue Cumulative ($M) Revenue Cumulative
1 1
0 0 0 5 10 15 20 25 0 5 10 15 20 25 Years of Operation Years of Operation
Figure 72 - Revenue Prediction (175 kW, 5% EI) Figure 73 - Revenue Prediction (200 kW, 5% EI)
Cumulative Hydroelectric Revenuc Cumulative Hydroelectric Revenuc 225kW Kaplan, 5% Energy Inflation 250kW Kaplan, 5% Energy Inflation 9 9
8 8
7 7
6 6 1_225kW 1_250kW 5 2_225kW 5 2_250kW 3_225kW 3_250kW 4 4 4_225kW 4_250kW 3 3
2 2
Cumulative Revenue ($M) Revenue Cumulative Cumulative Revenue ($M) Revenue Cumulative
1 1
0 0 0 5 10 15 20 25 0 5 10 15 20 25 Years of Operation Years of Operation
Figure 74 - Revenue Prediction (225 kW, 5% EI) Figure 75 - Revenue Prediction (250 kW, 5% EI)
42 Star Earth Energy, LLC
Randall G. Alley, MSEE
XVII. Profit and ROI - Non-profit, 3% Energy Inflation
Simple ROI After 25 Years Cumulative Profit After 25 Years Kaplan Turbine, 3% Energy Inflation Kaplan Turbine, 3% Energy Inflation 450% 10
400% 9
350% 8 7 300% Scenario 4 6 Scenario 4 250% Scenario 3 Scenario 3 5 200% Scenario 2 Scenario 2 Scenario 1 4 Scenario 1
Simple ROI (%) ROI Simple 150% 3 100% 2
50% 1 Cumulative 25 Year Profit ($Millions) Profit Year 25 Cumulative 0% 0 125 150 175 200 225 250 125 150 175 200 225 250 Turbine Size (kW) Turbine Size (kW)
Figure 76 - Simple ROI vs. Turbine Size (3% EI) Figure 77 - Cumulative Profit vs. Turbine (3% EI)
Annualized ROI After 25 Years Simple Payback Kaplan Turbine, 3% Energy Inflation Kaplan Turbine, 3% Energy Inflation 24% 14 22% 12 20% 18% 10 16% Scenario 4 Scenario 4 14% 8 Scenario 3 Scenario 3 12% Scenario 2 Scenario 2 10% 6 Scenario 1 Scenario 1
Simple ROI (%) ROI Simple 8% Years to Payback to Years 4 6% 4% 2 2%
0% 0 125 150 175 200 225 250 250 225 200 175 150 125 Turbine Size (kW) Turbine Size (kW)
Figure 78 - Annualized ROI vs Turbine Size (3% EI) Figure 79 - Simple ROI (Scenario 1, 3% EI)
Cumulative Profit - Scenario 1 Simple ROI - Scenario 1 Kaplan Turbine, 3% Energy Inflation Kaplan Turbine, 3% Energy Inflation 7.0 450%
400% 6.0 350% 5.0 250 kW 250 kW 300% 225 kW 225 kW 4.0 200 kW 250% 200 kW 175 kW 175 kW 3.0 200% 150 kW 150 kW
Simple ROI (%) ROI Simple 150% 125 kW 125 kW 2.0 100%
Cumulative Profit ($Millions) Profit Cumulative 1.0 50%
0.0 0% 0 5 10 15 20 25 0 5 10 15 20 25 Years of Operation Years of Operation
Figure 80 - Cumulative Profit (Scenario 1, 3% EI) Figure 81 - Simple ROI (Scenario 1, 3% EI)
Star Earth Energy, LLC 43
Randall G. Alley, MSEE
Cumulative Profit - Scenario 2 Simple ROI - Scenario 2 Kaplan Turbine, 3% Energy Inflation Kaplan Turbine, 3% Energy Inflation 7.0 450%
400% 6.0 350% 5.0 250 kW 250 kW 300% 225 kW 225 kW 4.0 200 kW 250% 200 kW 175 kW 175 kW 3.0 200% 150 kW 150 kW
Simple ROI (%) ROI Simple 150% 125 kW 125 kW 2.0 100%
Cumulative Profit ($Millions) Profit Cumulative 1.0 50%
0.0 0% 0 5 10 15 20 25 0 5 10 15 20 25 Years of Operation Years of Operation
Figure 82 - Cumulative Profit (Scenario 2, 3% EI) Figure 83 - Simple ROI (Scenario 2, 3% EI)
Cumulative Profit - Scenario 3 Simple ROI - Scenario 3 Kaplan Turbine, 3% Energy Inflation Kaplan Turbine, 3% Energy Inflation 7.0 450%
400% 6.0 350% 5.0 250 kW 250 kW 300% 225 kW 225 kW 4.0 200 kW 250% 200 kW 175 kW 175 kW 3.0 200% 150 kW 150 kW
Simple ROI (%) ROI Simple 150% 125 kW 125 kW 2.0 100%
Cumulative Profit ($Millions) Profit Cumulative 1.0 50%
0.0 0% 0 5 10 15 20 25 0 5 10 15 20 25 Years of Operation Years of Operation
Figure 84 - Cumulative Profit (Scenario 3, 3% EI) Figure 85 - Simple ROI (Scenario 3, 3% EI)
Cumulative Profit - Scenario 4 Simple ROI - Scenario 4 Kaplan Turbine, 3% Energy Inflation Kaplan Turbine, 3% Energy Inflation 7.0 450%
400% 6.0 350% 5.0 250 kW 250 kW 300% 225 kW 225 kW 4.0 200 kW 250% 200 kW 175 kW 175 kW 3.0 200% 150 kW 150 kW
Simple ROI (%) ROI Simple 150% 125 kW 125 kW 2.0 100%
Cumulative Profit ($Millions) Profit Cumulative 1.0 50%
0.0 0% 0 5 10 15 20 25 0 5 10 15 20 25 Years of Operation Years of Operation
Figure 86 - Cumulative Profit (Scenario 4, 3% EI) Figure 87 - Simple ROI (Scenario 4, 3% EI)
44 Star Earth Energy, LLC
Randall G. Alley, MSEE
XVIII. Appendix - Profit & ROI - Non-profit, 5% Energy Inflation
Simple ROI After 25 Years Cumulative Profit After 25 Years Kaplan Turbine, 5% Energy Inflation Kaplan Turbine, 5% Energy Inflation 600% 10 550% 9 500% 8 450% 7 400% Scenario 4 Scenario 4 350% 6 Scenario 3 Scenario 3 300% 5 Scenario 2 Scenario 2 250% Scenario 1 4 Scenario 1
Simple ROI (%) ROI Simple 200% 3 150% 2 100%
50% 1 Cumulative 25 Year Profit ($Millions) Profit Year 25 Cumulative 0% 0 125 150 175 200 225 250 125 150 175 200 225 250 Turbine Size (kW) Turbine Size (kW)
Figure 88 - Simple ROI vs. Turbine (5% EI) Figure 89 - Cumulative Profit vs. Turbine (5% EI)
Annualized ROI After 25 Years Simple Payback Kaplan Turbine, 5% Energy Inflation Kaplan Turbine, 5% Energy Inflation 24% 14 22% 12 20% 18% 10 16% Scenario 4 Scenario 4 14% 8 Scenario 3 Scenario 3 12% Scenario 2 Scenario 2 10% 6 Scenario 1 Scenario 1
Simple ROI (%) ROI Simple 8% Years to Payback to Years 4 6% 4% 2 2%
0% 0 125 150 175 200 225 250 250 225 200 175 150 125 Turbine Size (kW) Turbine Size (kW)
Figure 90 - Annualized ROI vs. Turbine Size (5% EI) Figure 91 - Years to Payback vs. Turbine (5% EI)
Cumulative Profit - Scenario 1 Simple ROI - Scenario 1 Kaplan Turbine, 5% Energy Inflation Kaplan Turbine, 5% Energy Inflation 9.0 600% 550% 8.0 500% 7.0 450% 250 kW 250 kW 6.0 400% 225 kW 225 kW 350% 5.0 200 kW 200 kW 300% 4.0 175 kW 175 kW 250% 150 kW 150 kW
3.0 (%) ROI Simple 200% 125 kW 125 kW 150% 2.0
100% Cumulative Profit ($Millions) Profit Cumulative 1.0 50% 0.0 0% 0 5 10 15 20 25 0 5 10 15 20 25 Years of Operation Years of Operation
Figure 92 - Cumulative Profit (Scenario 1, 5% EI) Figure 93 - Simple ROI (Scenario 1, 5% EI)
Star Earth Energy, LLC 45
Randall G. Alley, MSEE
Cumulative Profit - Scenario 2 Simple ROI - Scenario 2 Kaplan Turbine, 5% Energy Inflation Kaplan Turbine, 5% Energy Inflation 9.0 600% 550% 8.0 500% 7.0 450% 250 kW 250 kW 6.0 400% 225 kW 225 kW 350% 5.0 200 kW 200 kW 300% 4.0 175 kW 175 kW 250% 150 kW 150 kW
3.0 (%) ROI Simple 200% 125 kW 125 kW 150% 2.0 100% Cumulative Profit ($Millions) Profit Cumulative 1.0 50% 0.0 0% 0 5 10 15 20 25 0 5 10 15 20 25 Years of Operation Years of Operation
Figure 94 - Cumulative Profit (Scenario 2, 5% EI) Figure 95 - Simple ROI (Scenario 2, 5% EI)
Cumulative Profit - Scenario 3 Simple ROI - Scenario 3 Kaplan Turbine, 5% Energy Inflation Kaplan Turbine, 5% Energy Inflation 9.0 600% 550% 8.0 500% 7.0 450% 250 kW 250 kW 6.0 400% 225 kW 225 kW 350% 5.0 200 kW 200 kW 300% 4.0 175 kW 175 kW 250% 150 kW 150 kW
3.0 (%) ROI Simple 200% 125 kW 125 kW 150% 2.0 100% Cumulative Profit ($Millions) Profit Cumulative 1.0 50% 0.0 0% 0 5 10 15 20 25 0 5 10 15 20 25 Years of Operation Years of Operation
Figure 96 - Cumulative Profit (Scenario 3, 5% EI) Figure 97 - Simple ROI (Scenario 3, 5% EI)
Cumulative Profit - Scenario 4 Simple ROI - Scenario 4 Kaplan Turbine, 5% Energy Inflation Kaplan Turbine, 5% Energy Inflation 9.0 600% 550% 8.0 500% 7.0 450% 250 kW 250 kW 6.0 400% 225 kW 225 kW 350% 5.0 200 kW 200 kW 300% 4.0 175 kW 175 kW 250% 150 kW 150 kW
3.0 (%) ROI Simple 200% 125 kW 125 kW 150% 2.0 100% Cumulative Profit ($Millions) Profit Cumulative 1.0 50% 0.0 0% 0 5 10 15 20 25 0 5 10 15 20 25 Years of Operation Years of Operation
Figure 98 - Cumulative Profit (Scenario 4, 5% EI) Figure 99 - Simple ROI (Scenario 4, 5% EI)
46 Star Earth Energy, LLC
Randall G. Alley, MSEE
XIX. Appendix - Ossberger Price Quote
Star Earth Energy, LLC 47
Randall G. Alley, MSEE
A. FERC Hydropower Project Comparison Chart25
Conduit Exemption 5-MW Exemption License
Installed Capacity 15 MW or less (for non-municipality) 5 MW or less Unlimited Limitations 40 MW or less (for a municipality)
Location Limitations in Must be located on a conduit used for Must be located at an existing dam or natural water feature Addition to Off-Limits agricultural, municipal, or industrial Sites consumption Cannot be located at a dam owned or operated by the federal government Cannot be located on federal lands
Cannot be located at an impoundment
Ownership Limitations Must have all real property rights If located on private lands, must have all real property rights Proof of ownership not required at time of filing the necessary to develop and operate the necessary to develop and operate the project or an option application; power of eminent domain may be conferred project or an option to obtain such to obtain such interests by section 21 of the FPA, 16 U.S.C. § 814 interests Proof of ownership required at time of filing the application Proof of ownership required at time of filing the application
Term Limitations Issued in perpetuity Issued in perpetuity Up to 50 years for license
May be Subject to the Federal and state fish and wildlife Federal and state fish and wildlife conditions under section Federal reservation conditions under section 4(e) of the Following Mandatory conditions under section 30(c) of the FPA, 30(c) of the FPA, 16 U.S.C. § 823a(c) FPA, 16 U.S.C. § 797(e) Conditions 16 U.S.C. § 823a(c) Fishway prescriptions under section 18 of the FPA, 16 U.S.C. § 811
Consultation 3-stage consultation required under 18 3-stage consultation required under 18 C.F.R. § 4.38 Integrated Licensing Process (ILP) required under 18 C.F.R Requirements C.F.R. § 4.38 § 5 With concurrence from all resource agencies, the applicant With concurrence from all resource may seek waiver of the consultation requirements under 18 If waiver of ILP regulations was sought under 18 C.F.R. § agencies, the applicant may seek waiver of C.F.R. § 4.38(e) 5.1(f), and granted, then 3-stage consultation required the consultation requirements under 18 under 18 C.F.R. § 4.34(i) for the Alternative Licensing C.F.R. § 4.38(e) 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 Categorically exempt from preparing an Prepared consistent with NEPA Prepared consistent with NEPA Environmental environmental document under 18 C.F.R. § Document 380.4(a)(14) unless determined necessary
Project Boundary Includes powerhouse and connection to Includes all associated lands and facilities, such as the Includes all associated lands and facilities, such as the conduit (excludes the transmission line and powerhouse, dam, impoundment, transmission line, and any powerhouse, dam, impoundment, transmission line, and the conduit itself). lands that fulfill a project purpose (e.g., recreation, any lands that fulfill a project purpose (e.g., recreation, resource protection, and access roads). resource protection, and access roads).
Filing Fees None None None
Annual Charges Currently projects up to 1.5 MW not Currently projects up to 1.5 MW not charged Currently projects up to 1.5 MW not charged charged
Implementing Statutes FPA section 30(c). 16 U.S.C. § 823a Public Utility Regulatory Policies Act (PURPA) sections 405 FPA sections 4 thru 27 16 U.S.C. §§ 797-821 and 408. 16 U.S.C. §§ 2705 and 2708
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.
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B. FERC Matrix Comparison Licensing Processes26
Integrated Licensing Process (ILP) Traditional Licensing Process (TLP) Alternative Licensing Process (ALP) Consultation w/ Resource - Integrated - Paper-driven - Collaborative Agencies and Indian Tribes FERC Staff Involvement - Pre-filing [beginning at filing of Notice of Intent (NOI)] - Post filing (after the application has - Pre-filing (beginning at filing the NOI) been filed) - Early and throughout process - Early involvement for National Environmental - Available for education and guidance Policy Act (NEPA) scoping as requested Deadlines - Defined deadlines for all participants (including FERC) - Pre-filing: some deadlines for - Pre-filing: deadlines defined by collaborative throughout the process participants group
- Post-filing: defined deadlines for - Post-filing: defined deadlines for participants participants Study Plan Development - Developed through study plan meetings with all stakeholders - Developed by applicant based on early - Developed by collaborative group - FERC staff stakeholder recommendations assist as resources allow - Plan approved by FERC - No FERC involvement Study Dispute Resolution - Informal dispute resolution available to all participants - FERC study dispute resolution available - FERC study dispute resolution available upon upon request to agencies and affected request to agencies and affected tribes - Formal dispute resolution available to agencies with tribes mandatory conditioning authority - OEP Director issues advisory opinion - Office of Energy Projects (OEP) Director - Three-member panel provides technical recommendation on issues advisory opinion study dispute
- OEP Director opinion binding on applicant Application - Preliminary licensing proposal or draft application and final - Draft and final application include - Draft and final application with applicant- application include Exhibit E (environmental report) with form Exhibit E prepared environmental assessment or third- and contents of an EA party environmental impact statement Additional Information - Available to participants before application filing - Available to participants after filing of - Available to participants primarily before Requests application application filing - No additional information requests after application filing - Post-filing requests available but should be limited due to collaborative approach Timing of Resource Agency - Preliminary terms and conditions filed 60 days after Ready - Preliminary terms and conditions filed - Preliminary terms and conditions filed 60 days Terms and Conditions for Environmental Analysis (REA) notice 60 days after REA notice after REA notice
- Modified terms and conditions filed 60 days after comments - Schedule for final terms and conditions - Schedule for final terms and conditions on draft NEPA document
26 FERC Website, http://www.ferc.gov/industries/hydropower/gen-info/licensing/matrix.asp.
Star Earth Energy, LLC 49
Randall G. Alley, MSEE
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 FERC Correspondence With Government Agencies / issuance of 951020 order accepting surrender of lic under P-3474. 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 Order/Opinion / Proj (P-3474). 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 Applicant Correspondence / program for Lake Junaluska P-3474.Availability: Public 05/03/95 Untyped During RIMS II Conversion 03/15/95 P-3474-000 Lake Junaluska Council of United Methodist Church fwds proposal for professional servs re Lake Applicant Correspondence / Junaluska Proj under P-3474.Availability: Public 03/20/95 Untyped During RIMS II Conversion 02/17/95 P-3474-000 NC Dept of Environment,Health & Natural Resources submits copies of 750512 et al Other Submittal / correspondence,each Dam Safety Law of 1967 etc re Lake Junaluska Dam under P-3474.Availability: Public 03/03/95 Government Agency Submittal 02/17/95 P-3474-000 Expresses appreciation for assistance,cooperation/profess- ional courtesy re 950214 meeting re Lake FERC Correspondence With Government Agencies / Junaluska Proj-3474. 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 Notice / safety measures as outlined in 921223 ltr re Lake Junaluska P-3474.Availability: Public 01/20/95 Formal Notice 11/30/94 P-3474-000 Lake Junaluska Assembly's response to 941104 ltr and request for extension of time for certain items Applicant Correspondence / 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 Notice / Proj under P-3474 w/in 30 days.Availability: Public 11/30/94 Formal Notice 11/04/94 P-3474-000 Ltr notice to Lake Junaluska Assembly confirming recommendations made as result of annual Notice / operation inspec- tion of Lake Junaluska Proj (P-3474).Plan/sched due:30 days. 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 Notice / safety re Lake Junaluska Proj-3474.Availability: Public 10/05/94 Formal Notice 12/08/93 P-3474-000 Ltr notice requesting United Methodist Church Southeastern Jurisdictional Admin Council to submit Notice / sched for exercise for Lake Junaluska Proj under P-3474.Due w/in 10 days.Availability: Public 12/08/93 Formal Notice 08/05/93 P-3474-013 Notice of Lake Junaluska Assembly 930729 filed appl for surrend of exemption for Lake Junaluska P- Notice / 3474,NC. Comment date:930924. 08/05/93 Availability: Public Formal Notice 07/26/93 P-3474-013 Lake Junaluska Assembly informs FERC of breakdown of hydro equipment at Lake Junaluska under P- Applicant Correspondence / 3474. 07/29/93 Availability: Public Untyped During RIMS II Conversion 05/24/93 P-3474-000 Ltr order granting United Methodist Church Southeastern Jurisdictional Admin Council time Order/Opinion / extension for conducting design/remedial work for Lake Junaluska Proj-3474. 05/24/93 Availability: Public Delegated Order 05/10/93 P-3474-012 Order amend Lake Junaluska Assembly exemption for Lake Junaluska Proj under P-3474. Order/Opinion / 05/10/93 Availability: Public Delegated Order 05/07/93 P-3474-011 Ltr to Lake Junaluska Assembly re request to amend exemption for Lake Junaluska Proj (P- FERC Correspondence With Applicant / 3474).Availability: Public 05/07/93 Untyped During RIMS II Conversion 03/19/93 P-3474-000 Lake Junaluska Assembly requesting that SEJAC be granting exemption by FERC to operate one 200 Applicant Correspondence / kw hydro-power unit in Lake Junaluska Dam Proj-3474. 04/19/93 Availability: Public Untyped During RIMS II Conversion 03/30/93 P-3474-000 Ltr notice directing Lake Junaluska Assembly to file explanation of discrepancy re installation Notice / capacity at Lake Junaluska Proj w/in 30 days under P-3474. 03/30/93 Availability: Public Formal Notice 12/08/92 P-3474-000 Lake Junaluska Assembly submits EAP for Lake Junaluska Hydroelec Proj (P-3474). Report/Form / 01/22/93 Availability: CEII Emergency Action Plan 10/12/92 P-3474-000 Rep CH Taylor submits correspondence from MG Martin re Lake Junaluska Hydro P-3474. Other Submittal / 10/16/92 Availability: Public Congressional Submittal 09/16/92 P-3474-000 Ltr order denying Lake Junaluska Assembly request for extension of time to submit plan & schedule Order/Opinion / for violation of Art 6,Part 12 re Lake Junaluska Project under P-3474. PART 12 09/17/92 Availability: Public Delegated Order 09/01/92 P-3474-000 Lake Junaluska Assembly files request for extension of time to submit plan & schedule per Art 6 Part Report/Form / 12 re Lake Junaluska Project under P-3474. PART 12
50 Star Earth Energy, LLC
Randall G. Alley, MSEE
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 Notice / submit plan/sched re Lake Junaluska P-3474. PART 12 08/18/92 Availability: Public Formal Notice 06/24/92 P-3474-000 Ltr notice directing Lake Junaluska Assembly to submit addl suppl to 2nd consultant Part 12 safety Notice / insp rept for Lake Junaluska Proj #3474.Plan & schedule due:30 days. PART 12Availability: Public 06/24/92 Formal Notice 06/03/92 P-3474-000 Ltr notice requesting Lake Junaluska Division of United Methodist Church to submit plan/sched,w/in Notice / 30 days re consultants recommendations for Lake Junaluska P-3474.Availability: Public 06/03/92 Formal Notice 12/18/91 P-3474-000 Ltr notice to Lake Junaluska Assembly to submit overdue data on Lake Junalaska Proj #3474 for Natl Notice / Inventory of Dams.Due immediately. 12/18/91 Availability: Public Formal Notice 12/12/91 P-3474-000 Ltr order accepting United Methodist Church public safety plan as satisfactory re Lake Junaluska Order/Opinion / Project under P-3474.Availability: Public 12/11/91 Delegated Order 08/27/91 P-3474-000 Ltr notice ack cooperation extended for const insp & submitting recommendations re Lake Junaluska Notice / Proj under P-3474.Plan & sched due within 30-days.Availability: Public 08/27/91 Formal Notice 06/07/91 P-3474-000 Ltr order granting Lake Junaluska Assembly extension of time to submit plan & sched re Lake Order/Opinion / Junaluska Proj by 910901 under P-3474.Availability: Public 06/07/91 Delegated Order 04/19/91 P-3474-000 Ltr notice requesting Lake Junaluska Assembly to submit plan for remote surveillance per rev to EAP Notice / re Lake Junaluska Proj w/in 30-days under P-3474. PART 12Availability: Public 04/19/91 Formal Notice 03/22/91 P-3474-008 Order granting Lake Junaluska Assembly extension of time re Lake Junaluska Hydro Proj,NC under P- Order/Opinion / 3474. 03/22/91 Availability: Public Delegated Order 03/07/91 P-3474-000 Lake Junaluska Assembly of UMC submits addl info to 910205 request for extension of time to Applicant Correspondence / 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 Notice / Junaluska Proj immediately under P-3474.Availability: Public 01/31/91 Formal Notice 01/31/91 P-3474-000 Ltr notice to Southern Jurisdictional Admin Council to conduct EAP test & submit test critique etc re Notice / Lake Junaluska Proj w/in 30 days under P-3474. PART 12Availability: Public 01/31/91 Formal Notice 11/30/90 P-3474-007 Ltr notice to SE Jurisdictional Adminiatrativre Council advising of failure to comply w/Exemption Art Notice / 6 re Lake Junaluska Hydro Proj under P-3474-007.Availability: Public 11/30/90 Formal Notice 11/15/90 P-3474-000 Ltr order accepting Lake Junaluska Assembly plan & sched re oprn insp of Lake Junaluska Proj under Order/Opinion / P-3474.Availability: Public 11/20/90 Delegated Order 11/15/90 P-3474-000 FERC acks receipt of Lake Junaluska Assembly 901106 ltr re respone to reccomendation #4 per Notice / recent operation insp at Proj-3474.Availability: Public 11/15/90 Formal Notice
10/02/90 P-3474-000 Lake Junaluska,NC submits rept of FERC 5-Yr independent insp rept for Proj-3474. PART Report/Form / 12Availability: CEII 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 Applicant Correspondence / instrumentation program at Proj-3474.Availability: Public 11/08/90 Untyped During RIMS II Conversion
10/25/90 P-3474-000 Ltr order accepting plan & sched for responding to recommen- dations 1-3 in recent operation insp Order/Opinion / of Lake Junaluska Proj-3474.Availability: Public 10/25/90 Delegated Order 10/02/90 P-3474-000 Fwds 2nd 5-yr independent consultant insp rept of Lake Junaluska Assembly re Lake Junaluska Dam Report/Form / Proj,NC under P-3474.W/o encl. PART 12Availability: CEII 10/11/90 Part 12 Consultant Safety Inspection Reports 06/01/90 P-3474-000 Southeastern Jurisdictional Admin Council responds to FERC inquiry re exempt for dam & hydro facil Applicant Correspondence / at Lake Junaluska,NC under P-3474.Availability: Public 06/04/90 Untyped During RIMS II Conversion 06/01/90 P-3474-000 Southeastern Jurisdictional Admin Council responds to FERC requirements re exempt for dam & Applicant Correspondence / hydro facil at Lake Junaluska,NC under P-3474.Availability: Public 06/04/90 Untyped During RIMS II Conversion 04/03/90 P-3474-000 Response to Lake Junaluska Assembly 900326 ltr requesting copy of exemption under P-3474. PART FERC Correspondence With Applicant / 12Availability: Public 04/03/90 Untyped During RIMS II Conversion 02/23/90 P-3474-000 Ltr notice to Lake Junaluska Assembly to submit addl suppl to initial consultants safety insp rept w/in Notice / 15 days for Lake Junaluska Project under P-3474.Availability: Public 03/23/90 Formal Notice 03/12/90 P-3474-000 ARO informs Lake Junaluska Assembly of require of Part 12 safety insp every 5 yrs re Lake Junaluska FERC Correspondence With Applicant / Project under P-3474. PART 12Availability: Public 03/12/90 Untyped During RIMS II Conversion 02/09/90 P-3474-006 Order granting extension of time re Lake Junaluska Assembly under P-3474-006. Order/Opinion / 02/09/90 Availability: Public Delegated Order 01/10/90 P-3474-006 Comments of United Methodist Chruch re Lake Junaluska hydro- power Proj under P- Applicant Correspondence / 3474.Availability: Public 01/18/90 Untyped During RIMS II Conversion
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Randall G. Alley, MSEE
10/25/89 P-3474-000 Ltr notice requesting Lake Junaluska Assembly to provide notification flowchart summarizing who is Notice / to be notified re EAP under P-3474 w/in 45 days.Availability: Public 10/25/89 Formal Notice 09/27/89 P-3474-005 United Methodist Church requests addl time for completion of Lake Junaluska Assembly Hydro Applicant Correspondence / Power Proj.Availability: Public 09/29/89 Untyped During RIMS II Conversion 01/30/89 P-3474-000 EAP of Lake Junaluska Assembly Inc for Lake Junaluska Hydro Proj under P-3474.Availability: CEII Report/Form / 07/19/89 Emergency Action Plan 05/03/89 P-3474-004 Order granting Lake Junaluska Assembly extension of time for completion of proj construction. Order/Opinion / 05/03/89 Availability: Public Delegated Order 03/27/89 P-3474-000 Lake Junaluska Assembly fwds exact name,title,address & phone # of corp president,or vice Other Submittal / president etc responsible for proj as lic(ee)/exemptee in P-3474.Availability: Public 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 Order/Opinion / Junaluska Proj.Availability: Public 01/12/89 Delegated Order 02/09/88 P-3474-000 Ltr notice directing Lake Junaluska Assembly to submit review,test & update of EAP w/in 30- Notice / days.Availability: Public 02/09/88 Formal Notice 02/08/88 P-3474-000 Lake Junaluska Assembly 1st consultant safety insp rept for Lake Junaluska Proj on 880115 by CE FERC Report/Study / Sams.Availability: Public 02/08/88 Untyped During RIMS II Conversion 10/13/87 P-3474-000 Ltr order granting Lake Junaluska Assembly an extension of time to submit addl info re Part 12 rept Order/Opinion / for P-3474. 871013Availability: Public 10/13/87 Delegated Order 09/30/87 P-3474-000 Lake Junaluska Assembly request an extension of time to com- plete Part 12 rept for Lake Junaluska Applicant Correspondence / Dam Proj.Availability: Public 10/05/87 Untyped During RIMS II Conversion 08/13/87 P-3474-000 Requests Lake Junaluska to submit inspection rept by 871012 for Lake Junaluska Proj.Availability: FERC Correspondence With Applicant / Public 08/13/87 Untyped During RIMS II Conversion 06/18/87 P-3474-003 Order granting extension of time to complete proj const to 890115 for Lake Junaluska Proj. Order/Opinion / 870618Availability: Public 06/18/87 Delegated Order 06/08/87 P-3474-003 Lake Junaluska Assembly request extension of time to com- plete const for lic re Lake Junaluska Application/Petition/Request / Hydropower Proj.Availability: Public 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 Applicant Correspondence / Proj.Availability: Public 06/09/87 Untyped During RIMS II Conversion 03/12/87 P-3474-000 Lake Junaluska Assembly informs FERC that BL Williams will assume liaison duties for Lake Junaluska Applicant Correspondence / Proj.Availability: Public 03/13/87 Untyped During RIMS II Conversion 10/31/85 P-3474-000 Ltr order approving R Hunt as consultant for initial insp of Lake Junaluska Proj. 851031Availability: Order/Opinion / Public 10/31/85 Delegated Order 09/12/85 P-3474-000 Acks receipt of Lake Junaluska Assembly revised EAP & addl info re Lake Junaluska Proj.Availability: FERC Correspondence With Applicant / Public 09/19/85 Untyped During RIMS II Conversion 09/17/85 P-3474-000 Ltr order denying request of ELI Corp for exemption of Lake Junaluska Hydro Proj. Order/Opinion / 850917Availability: Public 09/17/85 Delegated Order 08/30/85 P-3474-000 Submits request for exemption of safety insp for Lake Junaluska Hydro Proj.Availability: CEII Report/Form / 09/05/85 Part 12 Consultant Safety Inspection Reports 07/26/83 P-3474-002 Forwards agency ltrs commenting on Lake Junaluska Assembly's appl for exemption of Lake FERC Correspondence With Applicant / Junaluska Project.W/o encl.Availability: Public 07/26/83 Untyped During RIMS II Conversion 07/15/83 P-3474-002 Order granting exemption from licensing of small hydro proj 5 MW or less in the matter of Lake Order/Opinion / Junaluska Assembly.Availability: Public 07/15/83 Delegated Order 05/14/83 P-3474-000 Comments on notice of case specific exemption appl for Lake Junaluska Assembly Hydro Comments/Protest / Proj,Haywood County,NC.Availability: Public 05/17/83 Untyped During RIMS II Conversion 05/09/83 P-3474-002 Submits exhibits to Lake Junaluska Assembly appl for lic re P-3474-002.Availability: Public Application/Petition/Request / 05/17/83 Untyped During RIMS II Conversion 05/03/83 P-3474-002 Notice of case specific exemption appl of Lake Junaluska Assembly for Lake Junaluska Notice / Proj.Availability: Public 05/03/83 Formal Notice 04/14/83 P-3474-002 Ltr order accepting 830121 exemption appl of Lake Juanalus- ka Assembly,NC for Lake Junaluska Order/Opinion / Proj.W/encl. 830414Availability: Public 04/14/83 Delegated Order 03/14/83 P-3474-002 Suppl to appl of Lake Junaluska Assembly for lic exemption. Submits deeds showing site Application/Petition/Request / ownership.Availability: Public 03/18/83 Exemption From License - Conduit/5MW 02/28/83 P-3474-002 Ltr notice extending 45 days to correct deficiencies in appl for exemption of Lake Junaluska Hydro Notice / Proj.Availability: Public 02/28/83 Formal Notice 01/19/83 P-3474-002 Fwds appl for Lake Junaluska Assembly appl for exemption re Lake Junaluska Dam Proj.Availability: Applicant Correspondence / Public 01/21/83 Untyped During RIMS II Conversion
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Randall G. Alley, MSEE
01/19/83 P-3474-002 Appl for exemption from licensing by Lake Junaluska Assembly re Lake Junaluska Hydro Application/Petition/Request / Proj.Availability: Public 01/21/83 Exemption From License - Conduit/5MW
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