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The hydrologic and economic feasibility of micro hydropower upfitting and integration of existing low-head dams in the United States
Energy Policy 63 (2013) 261–271
Contents lists available at ScienceDirect
Energy Policy journal homepage: www.elsevier.com/locate/enpol
The hydrologic and economic feasibility of micro hydropower upfitting and integration of existing low-head dams in the United States Christopher J. Sandt a,n, Martin W. Doyle b,1 a b
511 N. Columbus Street, Alexandria, VA 22314, USA Nicholas School of the Environment, 317A LSRC, Box 90328, Duke University, Durham, NC 27708-0328, USA
H I G H L I G H T S
We assess opportunities to leverage existing low-head dams as energy resources. We determine the viability of upfitting low-head dams using a run-of-river approach. Energy generation on existing low-head dams is most affected by flow availability. Micro-hydropower upfitting may be viable if provided subsidized energy pricing.
art ic l e i nf o
a b s t r a c t
Article history: Received 3 January 2013 Accepted 28 August 2013 Available online 26 September 2013
The integration of hydropower facilities on existing low-head, non-Federal dams and their subsequent tie to regional electricity grids may serve as a useful de-centralized component of renewable energy integration in the United States. Thousands of low-head dams do not provide power and thus present few benefits with significant costs, including safety liability, fragmentation of river ecosystems, and persistent economic burden induced on state agencies due to regular inspection requirements. We conducted a feasibility study in the Piedmont region of North Carolina cataloguing over 1000 nonFederal dams with hydraulic head ranging from 4.6 m to 10.7 m (15 ft to 35 ft) and power capacity o300 kW (“micro” hydropower). Generation potential, greenhouse gas reductions, and financial viability were refined for 49 low-head dams over a 30-year life cycle using industry standard software (RETScreen4). Results suggest that most of these dams are not financially viable for energy production under cost structures evaluated at the time of this study. However, our results indicate that some lowhead dams may be viable for energy production if provided funding opportunities comparable to the concurrent wind and solar markets. & 2013 Elsevier Ltd. All rights reserved.
Keywords: Hydropower Dams Feasibility
1. Introduction Hydroelectricity represented approximately seven percent of 2010 net energy generation in the United States Energy Information Administration (2009). While hydroelectricity embodies a relatively small portion of the total energy generation in the U.S., it is currently the largest domestic source of renewable energy and also plays a critical role in providing energy to meet peak demands in responding to rapid, short-term energy demand fluctuations. Because of the potential role for expanded hydropower, there have been recent efforts to incorporate more hydropower capacity into the national portfolio of energy generation (U.S. Department n
Corresponding author. Tel.: þ 1 512 590 0359; fax: þ1 202 646 8628. E-mail addresses: [email protected] (C.J. Sandt), [email protected] (M.W. Doyle). 1 Tel.: þ1 919 613 8026; fax: þ1 919 613 8719. 0301-4215/$ - see front matter & 2013 Elsevier Ltd. All rights reserved. http://dx.doi.org/10.1016/j.enpol.2013.08.087
of Energy (USDOE), 2011). Of particular interest is the potential of the tens of thousands of existing dams in the U.S. The National Inventory of Dams (NID, nid.usace.army.mil/) lists over 85,000 dams in the U.S., with over 42,000 dams having a height of less than 7.6 m (25 ft). These dams were originally built for a variety of purposes, including irrigation, fire protection, and hydroelectric generation—with the most common purposes being recreation (38.4 percent of NID dams) and flood control (17.7 percent of NID dams). Moreover, the majority of existing dams in the United States are privately owned (56.4 percent), (Fig. 1). The presence of small dams across the country may be largely overlooked, as it is estimated that there are at least 2.6 million small impoundments (mostly of manmade origin) across the conterminous United States – with most located in the eastern half of the country (Smith et al., 2002). In this study, we define low-head dams as those with gross hydraulic head (hydraulic height) ranging from 4.57 m to 10.67 m (15 ft to 35 ft). This height
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Fig. 1. Dam ownership (left) and dam purposes (right) in the U.S. (NID, 2005).
range was selected due to the potential for smaller-scale, lower power capacity hydropower production at these sites. This category of dams represents the majority of existing structures in North Carolina due to the transitional rolling topography associated with the region. To illustrate, of the 5559 dams contained in the 2011 North Carolina State Dam Safety database, 3003 of them (54 percent) fall within the low-head height category. The United States currently sits at the unusual interface of three trends: (a) ubiquitous obsolete small dams, (b) energy shortages, and (c) interest in renewable energy. These present rare opportunities to potentially harness energy from small, low-head dams via integration of micro hydropower generation facilities. Small dams will likely only provide small-scale hydropower (10 MW capacity or less), or micro hydropower (300 kW capacity or less; International Energy Agency (IEA), 2011). The micro hydropower sites in the U.S. that require the least regulation are typically run-of-river facilities. The run-of-river design approach used in this study assumes a design flow based on the available river flow that must be released for safety reasons over the spillway or through the existing draw-down structure when the dam impoundment is above normal pool. Run-of-river hydropower facilities do not require large storage reservoirs and are often used for micro hydropower. These types of hydropower facilities are able to avoid many of the upstream and downstream environmental impacts associated with large-scale hydropower projects because they are designed around natural river flows and minimal water storage, rather than conventional water storage/ release operation based on diurnal energy demand patterns. While ubiquitous structures exist that could provide such power, numerous barriers to micro hydropower development exist. These barriers include physical constraints (e.g., limited hydraulic head, low available flows, geographic isolation) and political constraints (e.g., lack of sufficient development incentives), but the primary barrier for micro hydropower remains cost-sensitivity. Smaller, micro hydropower sites are inherently deficient of the economies of scale that larger, conventional hydropower sites are able to realize. Other factors inhibiting micro hydropower development are their relatively small power capacities (o300 kW) as compared to their required capital costs, the difficulty in getting new micro hydropower sites permitted and licensed, and not least, the lack of knowledge that most land owners have in regard to micro hydropower potential on their property. Yet there are also potential incentives for small or micro hydropower development from existing small dams, such as recent adoption of renewable energy standards. As of 2011, 29 states had adopted variants of renewable energy standards (DSIREa, 2011) to incentivize
alternative energy production. In North Carolina (our study area), the State implemented Renewable Energy and Energy Efficiency Portfolio Standards (REPS) in August 2007, requiring all publicly-owned electric power suppliers to meet a specified percentage of their production with energy supplied by renewable energy facilities or reduced energy consumption. Small hydropower, defined in the REPS as o2 MW capacity, is accepted in North Carolina as a new renewable energy source. Energy produced by a registered new renewable energy facility may be sold to public power suppliers to meet REPS requirements. Due to the thousands of existing low-head dams across North Carolina, along with many other Eastern US states, the integration of hydropower facilities on these dams and their subsequent tie to the regional electricity grid may serve as a useful component of renewable domestic energy assimilation and REPS compliance. It is unclear, however, whether small dams can provide sufficient power to meet economic realities, although some recent studies provide important insight into feasibility and constraints of small hydropower. Two studies from Europe (Anagnostopoulos and Papantonis, 2007; Bockman et al., 2008) found that small, runof-river dams, were most sensitive to electricity buyback rates and hydrological constraints, along with other factors such as transmission bottlenecks and regulatory uncertainty. In the U.S., Kosnik (2008) evaluated the potential for hydropower generation from multiple sources (new small/micro hydro dams, facility uprating at existing hydro sites, small/micro hydro at existing non-powered dams, hydrokinetics) and estimated over 17,000 MW of potential power at existing non-powered dam sites, although this included large dam sites. In a later study, Kosnik (2010) assessed 125,000 potential run-of-river hydropower sites for potential energy generation and financial feasibility, concluding that that the “micro” hydro sites as modeled were cost-ineffective, while larger projects (41 MW) show the greatest potential for development. Other studies have similarly indicated the potential for hydropower development in the U.S. Department of Energy (USDOE), 2011, Navigant Consulting (2009), and, particularly, that hydropower is currently the largest renewable energy resource in the southern U.S. (53 percent of the existing renewable energy market share). A significant portion of that power comes from small hydropower (Brown et al., 2010). These previous studies have primarily provided broad-scale analysis of small-hydropower potential. Yet, because the vast majority of small dams are privately owned, site-specific financial conditions and realities will drive whether or not individual owners upfit existing facilities to generate electricity. It is unclear whether such fine-scale realities are adequately captured in previous, broad scale analyses.
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Here we focus specifically on non-powered, run-of-river, lowhead dams with gross hydraulic head ranging between 4.6 m and 10.7 m (15 ft to 35 ft). Such dams are ubiquitous and result in less severe ecological impacts than store-and-release structures. Specifically, we focus on whether micro hydropower is financially viable, and what physical and financial constraints might exist in determining whether a low-head dam is worth pursuing as a micro hydropower investment. Moreover, we assess whether specific policy practices, including renewable energy purchasing programs, can potentially influence low-head dam hydropower feasibility. Our approach uses publically available software, and was developed to be a generalizable method based on limited data and assumptions that could be easily modified and implemented in other hydrologic regions across the United States.
2. Methods Fig. 3. Low-head dams in Study Area.
2.1. Study region and dams This study focused on the Piedmont region of North Carolina. The majority of the terrain is rolling foothills with over 305 m (1000 ft) of topographic relief. Rivers and streams are primarily surface water-sourced, but are influenced by groundwater contributions to the east of the Atlantic coast fall line. Annual precipitation typically averages from 102 cm to 140 cm (40 in. to 55 in.) State Climate Office of North Carolina (SCO) (2011). In 2011, over 3000 low-head dams were on record in North Carolina based on publicly-available dam inventories (Fig. 2). With the decline of the textile industry in the southern U.S. since the mid-1900s, hundreds of dams that once produced local power are now functionally dormant. Some structures have been successfully re-developed as drinking water supplies, hubs for private residential subdivisions, or public recreational facilities; while others remain abandoned as possible safety hazards and environmental liabilities. We focused on 1049 non-Federal low-head dams contained within an 18,630 km2 (7193 m2) region of the Haw, Deep, Upper Cape Fear, and Upper Neuse River basins (Fig. 3). One of the key inputs to small or micro hydropower is stream flow. There were 54 USGS gauges within the study area; fifty one of the gauges had 410 years of mean daily flow data, and only 39 of the existing gauges had 420 years of data. Drainage areas ranged from 2.6 km2 (1 mile2) to over 2590 km2 (1000 mile2). Dam ages within the study area ranged from o2 years to 4 200 years and dam impoundment areas (i.e., reservoir areas) ranged from 0.004 km2 (o 0.0015 mile2) to over 6.5 km2 (2.5 mile2). From these 1049 dams, 49 sites were selected for detailed investigation based on their providing a wide range of available
Fig. 2. Low-head dams in North Carolina.
flows and hydraulic heights, adequate powerhouse footprint areas, a relatively even split between public and private ownership, and a well-distributed geographic representation (Fig. 4). All 49 test dam sites fall within 0.40 km (0.25 mile) of existing electrical grid infrastructure (e.g., overhead power lines or substations) based on detailed observation of aerial photography. Twenty-two of the 49 test dam sites were publicly-owned, either by municipalities or public water utilities. The remaining 28 test dam sites were privately-owned, either by home owners associations, private land owners, community groups, or private developers.
2.2. Analysis: RETScreen4 software Our goal was to conduct more detailed energy generation estimates and financial analyses than those done previously at broader scales (e.g., U.S. Department of Energy (USDOE) (2011)), but to do so in a way that could be readily transferred to other regions and to maximize the use of publicly available data and software. RETScreen4 software (free of charge by Natural Resources CAMNET Energy Technology Centre, downloadable at: http://www.retscreen.net/ang/version4.php) was used to estimate potential power capacity, capital costs, operating costs, and energy revenues for the 49 test dam sites. RETScreen4 is an Excel-based software package that allows preliminary assessments of renewable energy projects, including small hydropower. The user can choose a less detailed and less accurate analysis option that combines limited data entry with default empirical formulae (Method 1); or a more detailed and more accurate analysis option requiring increased levels of project site knowledge and more detailed data entry by the user (Method 2). For the more complex Method 2 analysis, a standard five-step procedure is followed that includes an Energy Model, Cost Analysis, a Greenhouse Gas (GHG) Analysis, a Financial Summary, and a Sensitivity and Risk Analysis. RETScreen4 has been widely used for renewable energy studies (e.g., Rehman et al., 2007; Kosnik, 2010). RETScreen4 analysis is considered “Pre-Feasibility Study” stage —corresponding to a cost accuracy of 740–50 percent. Each hydropower site is unique, since about 75 percent of the development cost is determined by the location and site conditions. Only about 25 percent of the cost is relatively fixed, being the cost of manufacturing the electromechanical equipment (RETScreen4 International, 2011). This research study provides concept-level engineering designs and financial analyses based on a series of design assumptions.
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Fig. 4. Test dam sites.
2.3. Energy generation analysis RETScreen4 uses a standard flow duration curve (FDC) to calculate energy generation potential. However, like most dam upfitting project sites, the majority of the 49 test dam sites were not adjacent to existing USGS gauges. Rather, existing gauges within the study region were analyzed to generate rudimentary, basin-specific FDCs. Basin-specific FDCs were generated using the available 39 USGS gauges with at least 20 years of data. The basinspecific FDCs were normalized per unit watershed area, and then scaled to the watershed area at the 49 test dam sites to produce simplified, site-specific flow duration curve approximations. From these estimated FDCs, mean values for the 30 percent met or exceeded stream flows were used as the base design flow for the selection of a simplex cross-flow turbine (Ossberger-model or similar) and asynchronous generator housed in a simple, noninsulated cinder block power house situated on an engineered concrete slab. Residual flows (flows that must bypass the hydropower facility for ecosystem benefits) were included in all RETScreen4 model iterations. These values were based on 7Q10 values generated from model runs using the U.S. Environmental Protection Agency's (EPA) DFLOW 3.1 software Environmental Protection Agency (2011). Additional assumptions included that the penstock configuration would include a buried C-900 PVC pipe and a custom-fitted, hydraulically-engineered, double-valved wye apparatus connected to the existing dam drainage valve or sluice gate. 2.4. Financial viability analysis A life cycle cost analysis was conducted over a 30-year project life to determine whether the investments required to up-rate these facilities with micro hydropower infrastructure were financially viable. While most hydropower facilities will easily surpass a useful project life of 30 years, this temporal length was assumed in order to represent a common Federal Energy Regulatory Commission (FERC) license term. Initial costs were quantified based on total capital costs (i.e., Development Costs, Engineering Costs, and Power System Costs, and Miscellaneous Costs), minus up-front
incentives and financed capital (i.e., loan principal). Annual revenues were based on electricity sales and theoretical GHG emission reduction credits, while annual costs were based on yearly operation and maintenance (O&M) costs and debt payments. The present value of annual cash flows (i.e., the difference between annual costs and benefits) was determined by applying an assumed five percent annual discount rate and an assumed two percent annual inflation rate. 2.5. Sensitivity analysis and risk analysis Risk analysis was based on Monte Carlo simulation in which the distribution of possible financial indicators was generated using a Gaussian distribution of 500 random values within a range for selected sets of nine key input variables. A specified level of risk for the financial indicator was chosen, for which the RETScreen4 software calculated a minimum, median, and maximum level of confidence. We modeled a 10 percent sensitivity range to observe how electricity export rate, GHG reduction income, initial costs, O&M costs, debt interest rate, and debt term rate affected the NPV in terms of an NPV ¼0 threshold. For our risk analysis, we used a five percent risk level (i.e., α¼5, 95 percent confidence interval) and a 50 percent uncertainty range for the following input values: initial costs, O&M costs, electricity export rate, GHG reduction credit rate, Net GHG reduction credit duration, debt ratio, debt interest rate, and debt term length. The 50 percent uncertainty range was assumed to be a conservative value, reflective of a worst case scenario in terms of the accuracy of RETScreen4 model results for our test dam sites. 2.6. Base model The State-wide average price of electricity at the time of this study (February 2011) was 10.12 cents/kWh, 8.06 cents/kWh, and 6.72 cents/kWh for residential, commercial, and industrial users, respectively—all falling below the U.S. national averages Energy Information Administration (2011). Analyses were performed for the 49 test dam sites to estimate realistic potential for hydropower
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generation and financial viability using three different electricity export rates: $0.075/kWh ($75/MWh), $0.115/kWh ($115/MWh), and $0.180/kWh ($180/MWh). These export rates represented three scenarios inclusive of regional energy pricing and Renewable Energy Credits (RECs) for micro hydropower. Applicable RECs as approved by the North Carolina Utility Commission (NCUC) are typically included in the contracted electricity sale price when Power Purchase Agreements (PPAs) are executed with electric utilities. At the time of this study, hydropower RECs were trading in North Carolina for anywhere between $6.00/MWh to $12.00/ MWh (Givens, 2011). The first electricity export rate scenario ($0.075/kWh) represented an electricity export rate falling on the more liberal end of the PPAs that were observed during our evaluation of the case study sites. The second scenario ($0.115/kWh) was specific to electricity export rates similar to the North Carolina State average for residential customers as per the U.S. Energy Information Agency Energy Information Administration (2011). The third scenario was specific to hypothetical electricity export rates similar to current solar renewable energy credits (SCRECs) as per Progress Energy's SunSense Program (DSIREb, 2011), which was active at the time of this study in 2011. We then quantified the electricity prices required to provide a net present value of zero for each of the test dams—defined hereafter as Net Present Value Breakpoints. Existing dam sites with positive net present value (NPV 40) were then analyzed further via a more detailed feasibility study. A sensitivity analysis and a risk analysis using Monte-Carlo simulation as described earlier were also performed on all 49 test dam sites to determine site-specific relationships between design parameters and the key financial indicator (i.e., NPV). Three down payment scenarios were applied in the identification of Net Present Value Breakpoints: one in which an owner was able to finance 100 percent of initial capital costs over a 10-year period with a standard 10 percent interest rate (i.e., zero down); one in which an owner financed 50 percent of initial capital costs over at 10-year period with a standard 10 percent interest rate (i.e., 50 percent down); and one in which an owner was able to assume zero debt and cover initial capital costs with an upfront lump sum payment (i.e., 100 percent down). 2.7. Supplemental model iteration 2: Private vs public facilities Twenty-two of the 49 test dam sites were publicly-owned, either by municipalities or public water utilities— the remaining 28 test dam sites are privately-owned, either by HOAs, private land owners, community groups, or private developers. Critical differences exist in the available funding mechanisms and tax burdens specific to public ownership and private ownership (e.g., incentives, loan programs, grant programs, tax breaks, etc.). A municipality may have access to tax-exempt general obligation bonds or revenue bonds that could be used for a micro hydropower project on an existing dam, while a private owner such as an HOA or family estate may have more limited access to lending mechanisms. Revenues from privately-owned micro hydropower facilities are typically subject to both Federal and State income tax for private dam owners, while publicly-owned micro hydropower facilities may not be subject to Federal and State income tax. However, there are subsidized low-interest loan programs available to private Owners/Developers for use in financing the capital costs involved with the construction of a new renewable energy facility. A supplemental model iteration was therefore performed to apply an assumed income tax burden in combination with the application of subsidized financing mechanisms, annual depreciation, and the use of annual revenue losses for income tax
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reductions. Supplemental Model Iteration 2 was performed for the 15 most promising test dam sites in terms of financial viability (i.e., the sites with the highest NPV as determined by the base model). This model iteration incorporated a four percent debt interest rate over a 15-year debt term in lieu of the 10 percent debt interest rate and 10-year debt term used in the base model. An 18 percent effective income tax burden was applied to the annual revenues derived from electricity sales, and it was assumed that annual losses (i.e., negative taxable income) may be used in the year in which they occur to reduce income tax burden. Supplemental Model Iteration 2 also incorporated the use of straight-line annual depreciation of 45 percent of capital costs (e.g., turbine/generator, piping, etc.). These financial modeling adjustments are likely more reflective of the financial scenarios facing most private Owners/ Developers during the construction and operation of a new micro hydropower site in North Carolina (i.e., a best case financing package, a mid-range income tax burden, and the ability to write-off revenue losses/depreciation). The standard five percent annual discount rate and two percent annual inflation rate as included in the base model were retained in Supplemental Model Iteration 2 so as to adjust annual costs and benefits. The site-specific electricity export rate (electricity price) required to generate a positive net present value (NPV 40) was then back-calculated for Supplemental Model Iteration 2. A summary of the primary assumptions and methodologies used within the Base Model and Supplemental Model Iteration 2 is presented in Table 1. 2.8. Field data collection We collected additional qualitative data through consultation with Federal and State regulators, as well as low-head hydropower specialists. We also performed personal site visits to the 15 most promising test dam sites based on preliminary NPV estimates in order to provide supplemental quantitative data at these sites. Data such as Owner knowledge of FERC requirements, Federal/ State/local regulatory jurisdiction, permitting history, upstream and downstream water use, and electrical utility constraints were evaluated in conjunction with the quantitative data derived from the physical characteristics of each test dam site. This combined information was then used to confirm the validity of model input data in order to help calibrate the RETScreen4 models.
3. Results 3.1. Energy generation Drainage basin areas for the 49 test dam sites ranged from as low as 2.5 km2 (0.97 mile2) to as high as 659.5 km2 (254.6 mile2); with potential power capacity ranging from 1 kW to 168 kW, respectively. Annual power capacity factors (the percentage of the year that the micro hydropower facility would operate) ranged from 46.0 percent to 52.2 percent. The majority of the dams studied were located on low-order tributaries (Strahler Stream Orders 2, 3, and 4). Annual electricity export rates were found to be directly dependent on dam height and dam drainage basin area — ranging from 6 MWh to 649 MWh (Fig. 5). 3.2. Financial viability Flow availability was the dominant independent variable for energy production and the subsequent financial viability of lowhead dam sites in our study area. Both hydraulic head and available flow were important factors for micro hydropower generation; however, it was the available flow (i.e., drainage area)
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Table 1 Summary of RETScreen4 model iterations.
Dam sites Project life Capital costs O&M costs Electricity export rates (three scenarios)
Financing of capital costs (three scenarios)
Discount rate Inflation rate Financing interest rate Income tax rate Income tax credit Debt term Depreciation (equipment) Loss write-off
Base model
Supplemental model iteration 2
49 30 years Variable by dam site Variable by dam site 7.5 cents/kWh 11.5 cents/kWh 18 cents/kWh 0% 50% 100% 5% 2% 10% 0% 35% of capital costs, 5 years 10 years None None
15 30 years Variable by dam site Variable by dam site 7.5 cents/kWh 11.5 cents/kWh 18 cents/kWh 0% 50% 100% 5% 2% 4% 18% None 15 years Straight-line, annual, 45% of capital costs Annual, carry-forward
Fig. 5. Energy export vs. hydraulic height and drainage area (red spheres indicate NPV o0; green spheres indicate NPV 40). (For interpretation of the references to color in this figure legend, the reader is referred to the web version of this article.)
that tended to dominate the ability to generate sufficient energy to attain financial viability. Assuming $0.075/kWh as the electricity export rate, NPV ranged from $91,982 for the largest site, to $502,424 for the smallest site; micro hydropower in the North Carolina Piedmont region was not financially viable at current electricity export rates. Assuming $0.115/kWh as the electricity export rate, NPV ranged from $493,833 for the largest site, to -$497,350 for the smallest site, allowing the seven largest test dam sites to realize positive NPV. With a $0.180/kWh electricity export rate, NPV ranged from $1445,782 for the largest site, to $489,104 for the smallest site, allowing fourteen of the largest test dam sites to realize positive NPV.
3.3. Net present value breakpoints The preliminary cut-off relationship for realizing positive NPV in the base model ranged from a higher head, lower flow scenario of 9.75 m (32 ft) and 77.7 km2 (30 mile2) drainage basin area to a lower head, higher flow scenario of 4.57 m (15 ft) and 285 km2 (110 mile2). These cut-off relationships were used to create an estimated Financial Viability Trendline specific to the sites evaluated in this study (Fig. 5) under the base model assumptions. Test dam sites falling below this trendline (i.e., to the left side of the trendline) were deemed financially non-feasible for hydropower generation based on realistic electricity export rates (electricity prices). Test dam sites falling above this trendline (i.e., to the right
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Fig. 6. Dam sites: net present value and power capacity.
side of the trendline) were deemed financially viable for hydropower generation based on realistic electricity export rates (electricity prices). In order to obtain a NPV40 (i.e., NPV breakpoint) in the base model, the required electricity export rates ranged from as low as 7.8 cents/kWh, to as high as an unrealistic $4.04/kWh. There were 15 dam sites within the base model that were able to obtain a positive net present value when electricity export rates (electricity prices) fell within a realistic range of 7 cents/kWh to 22 cents/kWh. Relationships were observed between the NPV breakpoint, power capacity, energy export rate, dam drainage area, O&M costs, and capital costs. The required electricity price decreased significantly as potential power capacity increased (Fig. 6) and as annual energy export rates increased (Fig. 7). Low-head dams with drainage basin areas less than 129.5 km2 (50 mile2) exhibited negative NPV through all ranges of realistic electricity export rates (Fig. 8), and no apparent relationship was observed between NPV and the available hydraulic head of the dam through all ranges of realistic electricity export rates (Fig. 9). There was also a high sensitivity to capital expenditures (Fig. 10) and annual operation and maintenance (O&M) expenses (Fig. 11), suggesting that upfront costs and O&M costs must be minimized to promote financial viability for these types of structures. There was also a relationship between the NPV break point and the amount of capital that a potential developer invested. Model iterations accommodating full capital cost coverage (i.e., no debt accrued), 50 percent capital cost coverage (i.e., 50 percent of capital costs was borrowed), and zero percent capital cost coverage (i.e., 100 percent of capital costs was borrowed), showed that the required electricity price needed for NPV4 0 could can be greatly reduced by avoiding the acquisition of debt for project construction. This relationship was a direct function of using a loan interest rate (10 percent) that was considerably higher than the discount rate used (five percent). 3.4. Supplemental model iteration 2 A subsidized low-interest financing mechanism and longer debt term counterbalanced some of the losses derived from an assumed 18 percent effective tax burden on annual revenues.
Combined with the use of straight-line annual depreciation for 45 percent of capital costs and the ability to “write off” annual losses, a four percent interest rate with 15-year debt term significantly decreased annual costs for Test Dam Sites 1–15. Supplemental Model Iteration 2 revealed that net present value breakpoints (i.e., the electricity price needed for NPV 40) were noticeably reduced from those derived in the base model runs (Fig. 12). For Test Dam Sites 1–15, the net present value breakpoints derived in Supplemental Model Iteration 2 decreased from the base model values anywhere from 8.6 percent to 13.6 percent. Net present value breakpoints under this scenario ranged from 7.6 cents/kWh to 19.2 cents/kWh. These breakpoint reductions were achieved primarily due to the six percent decrease in debt interest rate and the five year increase in loan term length. Note that these findings were based on an assumed best case scenario; one in which an Owner/Developer would be able to qualify for a low-interest State-subsidized loan package combined with a fairly aggressive ability to decrease income tax burden through annual depreciation and revenue losses. 3.5. Sensitivity and risk analysis results Even the most promising low-head dam sites, in terms of energy production, were not financially feasible for micro hydropower integration when electricity export rates were 7.5 cents/kWh or lower. Results also showed that the 49 test dam sites were more sensitive to initial project costs rather than O&M costs. The fluctuation of debt interest rate, debt interest term, and GHG reduction credit rate over the specified 10 percent sensitivity range did not influence financial viability as significantly as electricity export rates or initial costs. Risk analyses for the base model runs (i.e., model runs using 7.5 cents/kWh, 11.5 cents/kWh, and 18 cents/kWh) showed that electricity export rate was by far the dominant input variable. While every test dam site analyzed in our study produced independent and dynamic risk analysis results based on individual site characteristics, we observed a recurring underlying relationship between the relative impact of specific model input variables and the relative size (power capacity) of individual test dam sites. O&M costs and initial costs, as well as debt interest rate for some sites, tended to be the most influential input factors on financial viability for low-head dam sites with smaller power
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Fig. 7. Dam sites: net present value and energy export.
Fig. 8. Dam sites: net present value and dam drainage area.
capacities—those with power capacities less than approximately 20 kW. For sites with slightly larger power capacities – those with power capacities between 20 kW and 50 kW – O&M costs and initial costs still dominated, but were followed closely by electricity export rates. For the largest sites in our study – those with power capacities greater than 50 kW – the electricity export rate itself became the most influential input factor in terms of financial viability. 3.6. Cost comparisons to other energy sources In terms of capital costs per unit of energy generation (e.g., $/kWh) over the 30-year life of the facility, many of the test dam sites exhibited energy generation costs comparable to or lower than those achieved by conventional coal-fired generation in 2011. Although capacity factors for micro hydropower sites are relatively low (i.e., 46 percent to 52.2 percent in this study), the relatively long operating life (e.g., 30 to 100 þ years) and lack of annual fuel
costs allow micro hydropower sites to exhibit lower capital costs per unit energy produced. At the time of our study in 2011, thirteen test dam sites had lower capital costs per unit energy produced than conventional coal (6.8 cents/kWh; U.S. Energy Information Administration (2010)). Eighteen test dam sites had lower capital costs per unit energy produced than advanced nuclear technologies (9.4 cents/kWh; U.S. Energy Information Administration (2010)), and 29 test dam sites had lower capital costs per unit energy than solar photovoltaic generation (20.4 cents/kWh; U.S. Energy Information Administration (2010)). 3.7. Dam owner feedback The majority of the public dam owners consulted were Water Resource Directors or Public Utility Directors, but other representatives ranged from Town Council members to Mayors. Most public dam owner representatives supported the idea of micro hydropower; however, they approached the possible installation
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Fig. 9. Dam sites: net present value and hydraulic head.
Fig. 10. Dam sites: net present value and capital costs.
of micro hydropower infrastructure on their facilities with great trepidation. Their primary concerns were specific to the potential threat of any changes to their primary duty—providing reliable and affordable drinking water services to their customer base. All of the public dam owners articulated that flow limitations were their most pressing concerns. Some public representatives expressed interest in installing micro hydropower facilities on their dam structures if deemed financially feasible per their internal standards (i.e., positive NPV, positive cash flow, political popularity, etc.). These same representatives also stated that the additional operational demands required for micro hydropower facilities would likely not be feasible due to annual monetary constraints, the need to maintain redundant water volume behind the impoundment at all times, and personnel training issues. The private dam owners consulted ranged from HOA board members to Facility Maintenance Managers. Most private dam owners responded to the idea of micro hydropower installation with great interest. Rather than perceiving micro hydropower
operations as a liability, the majority of private dam owners stated that they would consider installing a micro hydropower facility as a possible asset assuming a viable NPV and adequate access to capital. However, knowledge of FERC licensing requirements (or even the existence of FERC) was fundamentally lacking for all private dam owners involved with the study. Private dam owners also expressed their concerns over maintenance/operational requirements and sufficient access to free or low-interest capital via Federal/State/local incentive programs. Many private dam owners stated that Federal grants and tax deductions were preferable over loan programs.
4. Discussion and conclusion None of the low-head dams contained within this study (0 out of 49 sites) were financially viable for energy production when modeled with electricity export rates (electricity pricing) similar to
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Fig. 11. Dam sites: net present value and O&M costs.
Fig. 12. Effects of loan subsidization and income tax circumstances on net present value breakpoints.
the rates that existing micro hydropower operators are currently receiving (7.5 cents/kWh; Fig. 5) during normal operation (i.e., when not receiving higher contracted rates associated with peakshaving events). However, sensitivity analyses suggested that a surprising number of low-head dam sites – 14 out of 49 in this study – may have been viable for production if provided funding opportunities comparable to alternative sources of renewable energy (i.e., up to 18 cents/kWh; Fig. 5). Nine of the low-head dam sites contained within the study area (Test Dam Site Numbers 1–9) could have realized positive NPV if provided electricity export rates at or slightly below 12 cents/kWh, and four of the low-head dam sites contained within the study area (Test Dam Site Numbers 1–4) could have realized positive NPV if provided electricity export rates at or slightly below 10 cents/kWh. These specific electricity export rates served as regional “trigger prices” for low-head dams in the North Carolina Piedmont, as conceptualized by Bockman et al. (2008).
The viability of retrofitting existing low-head dams with micro hydropower infrastructure in the North Carolina Piedmont – as modeled in this study – were most dependent on flow availability, cost-minimization and the availability of adequate electricity export rates. Anagnostopoulos and Papantonis (2007) showed similar results, in which electricity buyback rates and hydrological constraints were identified as the most significant factors affecting small hydropower development. The observed sensitivity analysis patterns also reinforce the importance of minimizing initial construction costs and O&M costs during the development of an existing low-head dam site as a micro hydropower asset. Dam sites with power capacities lower than 50 kW will likely not be practical for hydropower development unless developers can bypass or minimize a significant portion of upfront construction costs and incorporate very low overhead cost for daily operations. Sites with power capacities greater than 50 kW were less likely to experience the demanding fiscal constraints on site
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construction, operation, and maintenance that much smaller sites would experience. The smaller the power capacity of a proposed micro hydropower site, the more dependent the site becomes on receiving adequate electricity export rates as a revenue source. Other factors affecting the viability of micro hydropower integration may include physical access to the public electrical grid and the ever-increasing issue of electrical grid capacity and stability, as suggested by Lopez et al. (2007). The addition of micro hydropower sites to the existing grid will require technological advancements capable of integrating de-centralized systems in a safe and efficient manner while also ensuring grid stability. In addition, the relatively low percentage of initial costs that are due to capital costs is important to note. Most incentive programs available for funding the construction of hydropower facilities are designed around tax breaks based on capital investments (i.e., design and construction costs only) (Hughes, 2011). Many of the micro hydropower sites included in this study had relatively high permitting costs (in order to meet Federal, State, and local regulatory requirements) as compared to the actual capital costs needed for design/construction. More flexible incentive programs would help support low-head dam owners during the complex and unpredictable FERC permitting and licensing phases, as well as the more region-specific permitting phases. All told, the low-head dam sites included in our study area only approached financial viability if adequate flows could be met at all times while simultaneously minimizing upfront costs and operational costs over the life the proposed micro-hydropower system. Financially viable sites were generally those that comprised of dams with drainage basin areas larger than 129.5 km2 (50 mile2) and the use of subsidized low-interest financing mechanisms that are publicly-available. The integration of micro hydropower facilities on low-head dam sites within North Carolina may serve as a useful decentralized component of renewable domestic energy assimilation and REPS compliance. There may be hundreds of existing lowhead dam sites similar to these across North Carolina, and thousands of existing low-head dam sites across the U.S. that would become financially feasible for micro hydropower production if provided electricity export rates and subsidized loan programs comparable to those currently provided to the small wind and small solar industries. Nevertheless, the data contained in this study suggest that the apparent barriers to micro hydropower integration can only be alleviated by policy changes in the renewable energy market that will help make small hydropower more accessible, incentivized and marketed to the public along the lines of solar and wind. If the micro hydropower industry is to gain increasing market share, an increased knowledge of common site development constraints, permitting requirements, available tax incentives, subsidized low-interest loan programs, and standard contracts with Investor Owned Utilities (IOUs) will likely be needed. In early-2011, North Carolina had a total of 63 independent incentive programs related to renewables and efficiency (DSIREb, 2011); only 10 of which were applicable to non-marine hydropower facilities, with 19 programs dedicated to incentivizing small photovoltaic electricity generation. At the time of this study, solar renewable energy credits (SCRECs) under Progress Energy's SunSense Program were selling for as high as 18 cents/kWh. The SunSense Commercial PV Program has since been cancelled in North Carolina, but options are still available to sell energy at standard or negotiated rates for generation from qualifying small
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wind, solar, and hydroelectric sites that are interconnected to the electric grid. Owners of qualifying generation facilities are able to maintain all RECs associated with the output Progress Energy (Progress) (2012). As similar programs across the United States adjust to an everchanging energy market, the incentives available to micro hydropower generators may need to provide trigger prices similar to the ones demonstrated in this study. If the correct combination of creative financing and efficient design is applied, there may be an opportunity to access a potentially significant source of domestic energy that is currently stored behind countless low-head dams across the United States.
References Anagnostopoulos, J.S., Papantonis, D.E., 2007. Optimal sizing of a run-of-river small hydropower plant. Energy Conservation Management 48 (10), 2663–2670. Bockman, T., Fleten, S., Juliussen, E., Langhammer, H., Revdal, I., 2008. Investment timing and optimal capacity choice for small hydropower projects. European Journal of Operational Research 190 (1), 255–267. Brown, M.A., Gumerman, E., Baek, Y., Wang, J., Morris, C., Wang, Y., 2010. Renewable Energy in the South. Southeast Energy Efficiency Alliance, Atlanta, GA. Database of State Incentives for Renewables and Efficiency (DSIREa), 2011. Summary Maps [Data file]. Retrieved in 2011 from: 〈http://www.dsireusa.org/ summarymaps/index.cfm?ee=1&RE=1〉. Database of State Incentives for Renewables and Efficiency (DSIREb), 2011. North Carolina—Incentives/Policies for Renewables & Efficiency. [Data files]. Retrieved in 2011 from: http://www.dsireusa.org/incentives/index.cfm?State=NC&Search =TableState&EE=0&RE=1. Givens, A., 2011. Personal Communication, March 2011. Hughes, J.A., 2011. Personal Communication, June 30, 2011. International Energy Agency (IEA), 2011. Hydropower FAQ. Retrieved in 2011 from: 〈http://www.ieahydro.org/FAQ.html〉. Kosnik, L., 2008. The potential of water power in the fight against global warming in the US. Energy Policy 36 (9), 3252–3265. Kosnik, L., 2010. The potential for small scale hydropower development in the US. Energy Policy 38 (10), 5512–5519. Lopez, J.A.P., Hatziargyriou, N., Mutale, J., Djapic, P., Jenkins, N., 2007. Integrating distributed generation into electric power systems: a review of drivers, challenges and opportunities. Electric Power Systems Research. 77 (9), 1189–1203. Navigant Consulting, 2009. Job Creation Opportunities in Hydropower, Final Report. Retrieved in 2010 from: 〈http://hydro.org/why-hydro/job-creation/navigantstudy/〉. Progress Energy (Progress), 2012. Sell Renewable Energy. Retrieved in 2012 from: 〈https://www.progress-energy.com/carolinas/business/renewable-energy/sell/ index.page?〉. Rehman, S., Bader, M.A., Al-Moallem, S.A., 2007. Cost of solar energy generated using PV panels. Renewable and Sustainable Energy Reviews 11 (8), 1843–1857. RETScreen4 International, 2001–2005. Introduction to Clean Energy Project Analysis. Retrieved in 2011 from: 〈http://www.retscreen.net/ang/clean_energy_pro ject_analysis.php〉. Canada: Minister of Natural Resources Canada. Smith, S.V., Renwick, W.H., Bartley, J.D., Buddemeier, R.W., 2002. Distribution and significance of small, artificial water bodies across the United States landscape. The Science of the Total Environment 299 (1-3), 21–36. State Climate Office of North Carolina (SCO), 2011. Overview. Retrieved in 2011 from: 〈http://www.nc-climate.ncsu.edu/climate/ncclimate.html〉. U.S. Department of Energy (USDOE), 2011. U.S. Hydropower Fleet and Resource Assessments. Washington, DC: B. Smith. Retrieved in 2011 from: 〈http://hydro. org/wp-content/uploads/2011/04/Brennan-Smith-PPT_NHA_April2011_Final.pdf〉. U.S. Energy Information Administration (USEIAa), 2009. International Energy Statistics. Hydroelectricity Net Generation/Consumption. [Data file]. Retrieved in 2010 from: 〈http://www.eia.doe.gov/cfapps/ipdbproject/iedindex3.cfm? tid=6&pid=33&aid=12&cid=regions&syid=2005&eyid=2009&unit=BKWH〉. U.S. Energy Information Administration (USEIAc), 2010. Annual Energy Outlook 2011. DOE/EIA-0383(2010). Retrieved in 2010 from: 〈http://www.eia.gov/fore casts/aeo/pdf/0383%282011%29.pdf〉. U.S. Energy Information Administration (USEIAb), 2011. North Carolina, Data, Prices. [Data file]. Retrieved in 2011 from: 〈http://www.eia.doe.gov/state/state-ener gy-profiles-data.cfm?sid=NC〉. U.S. Environmental Protection Agency (USEPA), 2011. Water: DFLOW, Water Quality Models and Tools—DFLOW. Retrieved in 2011 from: 〈http://water.epa.gov/ scitech/datait/models/dflow/index.cfm〉.
Contents lists available at ScienceDirect
Energy Policy journal homepage: www.elsevier.com/locate/enpol
The hydrologic and economic feasibility of micro hydropower upfitting and integration of existing low-head dams in the United States Christopher J. Sandt a,n, Martin W. Doyle b,1 a b
511 N. Columbus Street, Alexandria, VA 22314, USA Nicholas School of the Environment, 317A LSRC, Box 90328, Duke University, Durham, NC 27708-0328, USA
H I G H L I G H T S
We assess opportunities to leverage existing low-head dams as energy resources. We determine the viability of upfitting low-head dams using a run-of-river approach. Energy generation on existing low-head dams is most affected by flow availability. Micro-hydropower upfitting may be viable if provided subsidized energy pricing.
art ic l e i nf o
a b s t r a c t
Article history: Received 3 January 2013 Accepted 28 August 2013 Available online 26 September 2013
The integration of hydropower facilities on existing low-head, non-Federal dams and their subsequent tie to regional electricity grids may serve as a useful de-centralized component of renewable energy integration in the United States. Thousands of low-head dams do not provide power and thus present few benefits with significant costs, including safety liability, fragmentation of river ecosystems, and persistent economic burden induced on state agencies due to regular inspection requirements. We conducted a feasibility study in the Piedmont region of North Carolina cataloguing over 1000 nonFederal dams with hydraulic head ranging from 4.6 m to 10.7 m (15 ft to 35 ft) and power capacity o300 kW (“micro” hydropower). Generation potential, greenhouse gas reductions, and financial viability were refined for 49 low-head dams over a 30-year life cycle using industry standard software (RETScreen4). Results suggest that most of these dams are not financially viable for energy production under cost structures evaluated at the time of this study. However, our results indicate that some lowhead dams may be viable for energy production if provided funding opportunities comparable to the concurrent wind and solar markets. & 2013 Elsevier Ltd. All rights reserved.
Keywords: Hydropower Dams Feasibility
1. Introduction Hydroelectricity represented approximately seven percent of 2010 net energy generation in the United States Energy Information Administration (2009). While hydroelectricity embodies a relatively small portion of the total energy generation in the U.S., it is currently the largest domestic source of renewable energy and also plays a critical role in providing energy to meet peak demands in responding to rapid, short-term energy demand fluctuations. Because of the potential role for expanded hydropower, there have been recent efforts to incorporate more hydropower capacity into the national portfolio of energy generation (U.S. Department n
Corresponding author. Tel.: þ 1 512 590 0359; fax: þ1 202 646 8628. E-mail addresses: [email protected] (C.J. Sandt), [email protected] (M.W. Doyle). 1 Tel.: þ1 919 613 8026; fax: þ1 919 613 8719. 0301-4215/$ - see front matter & 2013 Elsevier Ltd. All rights reserved. http://dx.doi.org/10.1016/j.enpol.2013.08.087
of Energy (USDOE), 2011). Of particular interest is the potential of the tens of thousands of existing dams in the U.S. The National Inventory of Dams (NID, nid.usace.army.mil/) lists over 85,000 dams in the U.S., with over 42,000 dams having a height of less than 7.6 m (25 ft). These dams were originally built for a variety of purposes, including irrigation, fire protection, and hydroelectric generation—with the most common purposes being recreation (38.4 percent of NID dams) and flood control (17.7 percent of NID dams). Moreover, the majority of existing dams in the United States are privately owned (56.4 percent), (Fig. 1). The presence of small dams across the country may be largely overlooked, as it is estimated that there are at least 2.6 million small impoundments (mostly of manmade origin) across the conterminous United States – with most located in the eastern half of the country (Smith et al., 2002). In this study, we define low-head dams as those with gross hydraulic head (hydraulic height) ranging from 4.57 m to 10.67 m (15 ft to 35 ft). This height
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Fig. 1. Dam ownership (left) and dam purposes (right) in the U.S. (NID, 2005).
range was selected due to the potential for smaller-scale, lower power capacity hydropower production at these sites. This category of dams represents the majority of existing structures in North Carolina due to the transitional rolling topography associated with the region. To illustrate, of the 5559 dams contained in the 2011 North Carolina State Dam Safety database, 3003 of them (54 percent) fall within the low-head height category. The United States currently sits at the unusual interface of three trends: (a) ubiquitous obsolete small dams, (b) energy shortages, and (c) interest in renewable energy. These present rare opportunities to potentially harness energy from small, low-head dams via integration of micro hydropower generation facilities. Small dams will likely only provide small-scale hydropower (10 MW capacity or less), or micro hydropower (300 kW capacity or less; International Energy Agency (IEA), 2011). The micro hydropower sites in the U.S. that require the least regulation are typically run-of-river facilities. The run-of-river design approach used in this study assumes a design flow based on the available river flow that must be released for safety reasons over the spillway or through the existing draw-down structure when the dam impoundment is above normal pool. Run-of-river hydropower facilities do not require large storage reservoirs and are often used for micro hydropower. These types of hydropower facilities are able to avoid many of the upstream and downstream environmental impacts associated with large-scale hydropower projects because they are designed around natural river flows and minimal water storage, rather than conventional water storage/ release operation based on diurnal energy demand patterns. While ubiquitous structures exist that could provide such power, numerous barriers to micro hydropower development exist. These barriers include physical constraints (e.g., limited hydraulic head, low available flows, geographic isolation) and political constraints (e.g., lack of sufficient development incentives), but the primary barrier for micro hydropower remains cost-sensitivity. Smaller, micro hydropower sites are inherently deficient of the economies of scale that larger, conventional hydropower sites are able to realize. Other factors inhibiting micro hydropower development are their relatively small power capacities (o300 kW) as compared to their required capital costs, the difficulty in getting new micro hydropower sites permitted and licensed, and not least, the lack of knowledge that most land owners have in regard to micro hydropower potential on their property. Yet there are also potential incentives for small or micro hydropower development from existing small dams, such as recent adoption of renewable energy standards. As of 2011, 29 states had adopted variants of renewable energy standards (DSIREa, 2011) to incentivize
alternative energy production. In North Carolina (our study area), the State implemented Renewable Energy and Energy Efficiency Portfolio Standards (REPS) in August 2007, requiring all publicly-owned electric power suppliers to meet a specified percentage of their production with energy supplied by renewable energy facilities or reduced energy consumption. Small hydropower, defined in the REPS as o2 MW capacity, is accepted in North Carolina as a new renewable energy source. Energy produced by a registered new renewable energy facility may be sold to public power suppliers to meet REPS requirements. Due to the thousands of existing low-head dams across North Carolina, along with many other Eastern US states, the integration of hydropower facilities on these dams and their subsequent tie to the regional electricity grid may serve as a useful component of renewable domestic energy assimilation and REPS compliance. It is unclear, however, whether small dams can provide sufficient power to meet economic realities, although some recent studies provide important insight into feasibility and constraints of small hydropower. Two studies from Europe (Anagnostopoulos and Papantonis, 2007; Bockman et al., 2008) found that small, runof-river dams, were most sensitive to electricity buyback rates and hydrological constraints, along with other factors such as transmission bottlenecks and regulatory uncertainty. In the U.S., Kosnik (2008) evaluated the potential for hydropower generation from multiple sources (new small/micro hydro dams, facility uprating at existing hydro sites, small/micro hydro at existing non-powered dams, hydrokinetics) and estimated over 17,000 MW of potential power at existing non-powered dam sites, although this included large dam sites. In a later study, Kosnik (2010) assessed 125,000 potential run-of-river hydropower sites for potential energy generation and financial feasibility, concluding that that the “micro” hydro sites as modeled were cost-ineffective, while larger projects (41 MW) show the greatest potential for development. Other studies have similarly indicated the potential for hydropower development in the U.S. Department of Energy (USDOE), 2011, Navigant Consulting (2009), and, particularly, that hydropower is currently the largest renewable energy resource in the southern U.S. (53 percent of the existing renewable energy market share). A significant portion of that power comes from small hydropower (Brown et al., 2010). These previous studies have primarily provided broad-scale analysis of small-hydropower potential. Yet, because the vast majority of small dams are privately owned, site-specific financial conditions and realities will drive whether or not individual owners upfit existing facilities to generate electricity. It is unclear whether such fine-scale realities are adequately captured in previous, broad scale analyses.
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Here we focus specifically on non-powered, run-of-river, lowhead dams with gross hydraulic head ranging between 4.6 m and 10.7 m (15 ft to 35 ft). Such dams are ubiquitous and result in less severe ecological impacts than store-and-release structures. Specifically, we focus on whether micro hydropower is financially viable, and what physical and financial constraints might exist in determining whether a low-head dam is worth pursuing as a micro hydropower investment. Moreover, we assess whether specific policy practices, including renewable energy purchasing programs, can potentially influence low-head dam hydropower feasibility. Our approach uses publically available software, and was developed to be a generalizable method based on limited data and assumptions that could be easily modified and implemented in other hydrologic regions across the United States.
2. Methods Fig. 3. Low-head dams in Study Area.
2.1. Study region and dams This study focused on the Piedmont region of North Carolina. The majority of the terrain is rolling foothills with over 305 m (1000 ft) of topographic relief. Rivers and streams are primarily surface water-sourced, but are influenced by groundwater contributions to the east of the Atlantic coast fall line. Annual precipitation typically averages from 102 cm to 140 cm (40 in. to 55 in.) State Climate Office of North Carolina (SCO) (2011). In 2011, over 3000 low-head dams were on record in North Carolina based on publicly-available dam inventories (Fig. 2). With the decline of the textile industry in the southern U.S. since the mid-1900s, hundreds of dams that once produced local power are now functionally dormant. Some structures have been successfully re-developed as drinking water supplies, hubs for private residential subdivisions, or public recreational facilities; while others remain abandoned as possible safety hazards and environmental liabilities. We focused on 1049 non-Federal low-head dams contained within an 18,630 km2 (7193 m2) region of the Haw, Deep, Upper Cape Fear, and Upper Neuse River basins (Fig. 3). One of the key inputs to small or micro hydropower is stream flow. There were 54 USGS gauges within the study area; fifty one of the gauges had 410 years of mean daily flow data, and only 39 of the existing gauges had 420 years of data. Drainage areas ranged from 2.6 km2 (1 mile2) to over 2590 km2 (1000 mile2). Dam ages within the study area ranged from o2 years to 4 200 years and dam impoundment areas (i.e., reservoir areas) ranged from 0.004 km2 (o 0.0015 mile2) to over 6.5 km2 (2.5 mile2). From these 1049 dams, 49 sites were selected for detailed investigation based on their providing a wide range of available
Fig. 2. Low-head dams in North Carolina.
flows and hydraulic heights, adequate powerhouse footprint areas, a relatively even split between public and private ownership, and a well-distributed geographic representation (Fig. 4). All 49 test dam sites fall within 0.40 km (0.25 mile) of existing electrical grid infrastructure (e.g., overhead power lines or substations) based on detailed observation of aerial photography. Twenty-two of the 49 test dam sites were publicly-owned, either by municipalities or public water utilities. The remaining 28 test dam sites were privately-owned, either by home owners associations, private land owners, community groups, or private developers.
2.2. Analysis: RETScreen4 software Our goal was to conduct more detailed energy generation estimates and financial analyses than those done previously at broader scales (e.g., U.S. Department of Energy (USDOE) (2011)), but to do so in a way that could be readily transferred to other regions and to maximize the use of publicly available data and software. RETScreen4 software (free of charge by Natural Resources CAMNET Energy Technology Centre, downloadable at: http://www.retscreen.net/ang/version4.php) was used to estimate potential power capacity, capital costs, operating costs, and energy revenues for the 49 test dam sites. RETScreen4 is an Excel-based software package that allows preliminary assessments of renewable energy projects, including small hydropower. The user can choose a less detailed and less accurate analysis option that combines limited data entry with default empirical formulae (Method 1); or a more detailed and more accurate analysis option requiring increased levels of project site knowledge and more detailed data entry by the user (Method 2). For the more complex Method 2 analysis, a standard five-step procedure is followed that includes an Energy Model, Cost Analysis, a Greenhouse Gas (GHG) Analysis, a Financial Summary, and a Sensitivity and Risk Analysis. RETScreen4 has been widely used for renewable energy studies (e.g., Rehman et al., 2007; Kosnik, 2010). RETScreen4 analysis is considered “Pre-Feasibility Study” stage —corresponding to a cost accuracy of 740–50 percent. Each hydropower site is unique, since about 75 percent of the development cost is determined by the location and site conditions. Only about 25 percent of the cost is relatively fixed, being the cost of manufacturing the electromechanical equipment (RETScreen4 International, 2011). This research study provides concept-level engineering designs and financial analyses based on a series of design assumptions.
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Fig. 4. Test dam sites.
2.3. Energy generation analysis RETScreen4 uses a standard flow duration curve (FDC) to calculate energy generation potential. However, like most dam upfitting project sites, the majority of the 49 test dam sites were not adjacent to existing USGS gauges. Rather, existing gauges within the study region were analyzed to generate rudimentary, basin-specific FDCs. Basin-specific FDCs were generated using the available 39 USGS gauges with at least 20 years of data. The basinspecific FDCs were normalized per unit watershed area, and then scaled to the watershed area at the 49 test dam sites to produce simplified, site-specific flow duration curve approximations. From these estimated FDCs, mean values for the 30 percent met or exceeded stream flows were used as the base design flow for the selection of a simplex cross-flow turbine (Ossberger-model or similar) and asynchronous generator housed in a simple, noninsulated cinder block power house situated on an engineered concrete slab. Residual flows (flows that must bypass the hydropower facility for ecosystem benefits) were included in all RETScreen4 model iterations. These values were based on 7Q10 values generated from model runs using the U.S. Environmental Protection Agency's (EPA) DFLOW 3.1 software Environmental Protection Agency (2011). Additional assumptions included that the penstock configuration would include a buried C-900 PVC pipe and a custom-fitted, hydraulically-engineered, double-valved wye apparatus connected to the existing dam drainage valve or sluice gate. 2.4. Financial viability analysis A life cycle cost analysis was conducted over a 30-year project life to determine whether the investments required to up-rate these facilities with micro hydropower infrastructure were financially viable. While most hydropower facilities will easily surpass a useful project life of 30 years, this temporal length was assumed in order to represent a common Federal Energy Regulatory Commission (FERC) license term. Initial costs were quantified based on total capital costs (i.e., Development Costs, Engineering Costs, and Power System Costs, and Miscellaneous Costs), minus up-front
incentives and financed capital (i.e., loan principal). Annual revenues were based on electricity sales and theoretical GHG emission reduction credits, while annual costs were based on yearly operation and maintenance (O&M) costs and debt payments. The present value of annual cash flows (i.e., the difference between annual costs and benefits) was determined by applying an assumed five percent annual discount rate and an assumed two percent annual inflation rate. 2.5. Sensitivity analysis and risk analysis Risk analysis was based on Monte Carlo simulation in which the distribution of possible financial indicators was generated using a Gaussian distribution of 500 random values within a range for selected sets of nine key input variables. A specified level of risk for the financial indicator was chosen, for which the RETScreen4 software calculated a minimum, median, and maximum level of confidence. We modeled a 10 percent sensitivity range to observe how electricity export rate, GHG reduction income, initial costs, O&M costs, debt interest rate, and debt term rate affected the NPV in terms of an NPV ¼0 threshold. For our risk analysis, we used a five percent risk level (i.e., α¼5, 95 percent confidence interval) and a 50 percent uncertainty range for the following input values: initial costs, O&M costs, electricity export rate, GHG reduction credit rate, Net GHG reduction credit duration, debt ratio, debt interest rate, and debt term length. The 50 percent uncertainty range was assumed to be a conservative value, reflective of a worst case scenario in terms of the accuracy of RETScreen4 model results for our test dam sites. 2.6. Base model The State-wide average price of electricity at the time of this study (February 2011) was 10.12 cents/kWh, 8.06 cents/kWh, and 6.72 cents/kWh for residential, commercial, and industrial users, respectively—all falling below the U.S. national averages Energy Information Administration (2011). Analyses were performed for the 49 test dam sites to estimate realistic potential for hydropower
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generation and financial viability using three different electricity export rates: $0.075/kWh ($75/MWh), $0.115/kWh ($115/MWh), and $0.180/kWh ($180/MWh). These export rates represented three scenarios inclusive of regional energy pricing and Renewable Energy Credits (RECs) for micro hydropower. Applicable RECs as approved by the North Carolina Utility Commission (NCUC) are typically included in the contracted electricity sale price when Power Purchase Agreements (PPAs) are executed with electric utilities. At the time of this study, hydropower RECs were trading in North Carolina for anywhere between $6.00/MWh to $12.00/ MWh (Givens, 2011). The first electricity export rate scenario ($0.075/kWh) represented an electricity export rate falling on the more liberal end of the PPAs that were observed during our evaluation of the case study sites. The second scenario ($0.115/kWh) was specific to electricity export rates similar to the North Carolina State average for residential customers as per the U.S. Energy Information Agency Energy Information Administration (2011). The third scenario was specific to hypothetical electricity export rates similar to current solar renewable energy credits (SCRECs) as per Progress Energy's SunSense Program (DSIREb, 2011), which was active at the time of this study in 2011. We then quantified the electricity prices required to provide a net present value of zero for each of the test dams—defined hereafter as Net Present Value Breakpoints. Existing dam sites with positive net present value (NPV 40) were then analyzed further via a more detailed feasibility study. A sensitivity analysis and a risk analysis using Monte-Carlo simulation as described earlier were also performed on all 49 test dam sites to determine site-specific relationships between design parameters and the key financial indicator (i.e., NPV). Three down payment scenarios were applied in the identification of Net Present Value Breakpoints: one in which an owner was able to finance 100 percent of initial capital costs over a 10-year period with a standard 10 percent interest rate (i.e., zero down); one in which an owner financed 50 percent of initial capital costs over at 10-year period with a standard 10 percent interest rate (i.e., 50 percent down); and one in which an owner was able to assume zero debt and cover initial capital costs with an upfront lump sum payment (i.e., 100 percent down). 2.7. Supplemental model iteration 2: Private vs public facilities Twenty-two of the 49 test dam sites were publicly-owned, either by municipalities or public water utilities— the remaining 28 test dam sites are privately-owned, either by HOAs, private land owners, community groups, or private developers. Critical differences exist in the available funding mechanisms and tax burdens specific to public ownership and private ownership (e.g., incentives, loan programs, grant programs, tax breaks, etc.). A municipality may have access to tax-exempt general obligation bonds or revenue bonds that could be used for a micro hydropower project on an existing dam, while a private owner such as an HOA or family estate may have more limited access to lending mechanisms. Revenues from privately-owned micro hydropower facilities are typically subject to both Federal and State income tax for private dam owners, while publicly-owned micro hydropower facilities may not be subject to Federal and State income tax. However, there are subsidized low-interest loan programs available to private Owners/Developers for use in financing the capital costs involved with the construction of a new renewable energy facility. A supplemental model iteration was therefore performed to apply an assumed income tax burden in combination with the application of subsidized financing mechanisms, annual depreciation, and the use of annual revenue losses for income tax
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reductions. Supplemental Model Iteration 2 was performed for the 15 most promising test dam sites in terms of financial viability (i.e., the sites with the highest NPV as determined by the base model). This model iteration incorporated a four percent debt interest rate over a 15-year debt term in lieu of the 10 percent debt interest rate and 10-year debt term used in the base model. An 18 percent effective income tax burden was applied to the annual revenues derived from electricity sales, and it was assumed that annual losses (i.e., negative taxable income) may be used in the year in which they occur to reduce income tax burden. Supplemental Model Iteration 2 also incorporated the use of straight-line annual depreciation of 45 percent of capital costs (e.g., turbine/generator, piping, etc.). These financial modeling adjustments are likely more reflective of the financial scenarios facing most private Owners/ Developers during the construction and operation of a new micro hydropower site in North Carolina (i.e., a best case financing package, a mid-range income tax burden, and the ability to write-off revenue losses/depreciation). The standard five percent annual discount rate and two percent annual inflation rate as included in the base model were retained in Supplemental Model Iteration 2 so as to adjust annual costs and benefits. The site-specific electricity export rate (electricity price) required to generate a positive net present value (NPV 40) was then back-calculated for Supplemental Model Iteration 2. A summary of the primary assumptions and methodologies used within the Base Model and Supplemental Model Iteration 2 is presented in Table 1. 2.8. Field data collection We collected additional qualitative data through consultation with Federal and State regulators, as well as low-head hydropower specialists. We also performed personal site visits to the 15 most promising test dam sites based on preliminary NPV estimates in order to provide supplemental quantitative data at these sites. Data such as Owner knowledge of FERC requirements, Federal/ State/local regulatory jurisdiction, permitting history, upstream and downstream water use, and electrical utility constraints were evaluated in conjunction with the quantitative data derived from the physical characteristics of each test dam site. This combined information was then used to confirm the validity of model input data in order to help calibrate the RETScreen4 models.
3. Results 3.1. Energy generation Drainage basin areas for the 49 test dam sites ranged from as low as 2.5 km2 (0.97 mile2) to as high as 659.5 km2 (254.6 mile2); with potential power capacity ranging from 1 kW to 168 kW, respectively. Annual power capacity factors (the percentage of the year that the micro hydropower facility would operate) ranged from 46.0 percent to 52.2 percent. The majority of the dams studied were located on low-order tributaries (Strahler Stream Orders 2, 3, and 4). Annual electricity export rates were found to be directly dependent on dam height and dam drainage basin area — ranging from 6 MWh to 649 MWh (Fig. 5). 3.2. Financial viability Flow availability was the dominant independent variable for energy production and the subsequent financial viability of lowhead dam sites in our study area. Both hydraulic head and available flow were important factors for micro hydropower generation; however, it was the available flow (i.e., drainage area)
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Table 1 Summary of RETScreen4 model iterations.
Dam sites Project life Capital costs O&M costs Electricity export rates (three scenarios)
Financing of capital costs (three scenarios)
Discount rate Inflation rate Financing interest rate Income tax rate Income tax credit Debt term Depreciation (equipment) Loss write-off
Base model
Supplemental model iteration 2
49 30 years Variable by dam site Variable by dam site 7.5 cents/kWh 11.5 cents/kWh 18 cents/kWh 0% 50% 100% 5% 2% 10% 0% 35% of capital costs, 5 years 10 years None None
15 30 years Variable by dam site Variable by dam site 7.5 cents/kWh 11.5 cents/kWh 18 cents/kWh 0% 50% 100% 5% 2% 4% 18% None 15 years Straight-line, annual, 45% of capital costs Annual, carry-forward
Fig. 5. Energy export vs. hydraulic height and drainage area (red spheres indicate NPV o0; green spheres indicate NPV 40). (For interpretation of the references to color in this figure legend, the reader is referred to the web version of this article.)
that tended to dominate the ability to generate sufficient energy to attain financial viability. Assuming $0.075/kWh as the electricity export rate, NPV ranged from $91,982 for the largest site, to $502,424 for the smallest site; micro hydropower in the North Carolina Piedmont region was not financially viable at current electricity export rates. Assuming $0.115/kWh as the electricity export rate, NPV ranged from $493,833 for the largest site, to -$497,350 for the smallest site, allowing the seven largest test dam sites to realize positive NPV. With a $0.180/kWh electricity export rate, NPV ranged from $1445,782 for the largest site, to $489,104 for the smallest site, allowing fourteen of the largest test dam sites to realize positive NPV.
3.3. Net present value breakpoints The preliminary cut-off relationship for realizing positive NPV in the base model ranged from a higher head, lower flow scenario of 9.75 m (32 ft) and 77.7 km2 (30 mile2) drainage basin area to a lower head, higher flow scenario of 4.57 m (15 ft) and 285 km2 (110 mile2). These cut-off relationships were used to create an estimated Financial Viability Trendline specific to the sites evaluated in this study (Fig. 5) under the base model assumptions. Test dam sites falling below this trendline (i.e., to the left side of the trendline) were deemed financially non-feasible for hydropower generation based on realistic electricity export rates (electricity prices). Test dam sites falling above this trendline (i.e., to the right
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Fig. 6. Dam sites: net present value and power capacity.
side of the trendline) were deemed financially viable for hydropower generation based on realistic electricity export rates (electricity prices). In order to obtain a NPV40 (i.e., NPV breakpoint) in the base model, the required electricity export rates ranged from as low as 7.8 cents/kWh, to as high as an unrealistic $4.04/kWh. There were 15 dam sites within the base model that were able to obtain a positive net present value when electricity export rates (electricity prices) fell within a realistic range of 7 cents/kWh to 22 cents/kWh. Relationships were observed between the NPV breakpoint, power capacity, energy export rate, dam drainage area, O&M costs, and capital costs. The required electricity price decreased significantly as potential power capacity increased (Fig. 6) and as annual energy export rates increased (Fig. 7). Low-head dams with drainage basin areas less than 129.5 km2 (50 mile2) exhibited negative NPV through all ranges of realistic electricity export rates (Fig. 8), and no apparent relationship was observed between NPV and the available hydraulic head of the dam through all ranges of realistic electricity export rates (Fig. 9). There was also a high sensitivity to capital expenditures (Fig. 10) and annual operation and maintenance (O&M) expenses (Fig. 11), suggesting that upfront costs and O&M costs must be minimized to promote financial viability for these types of structures. There was also a relationship between the NPV break point and the amount of capital that a potential developer invested. Model iterations accommodating full capital cost coverage (i.e., no debt accrued), 50 percent capital cost coverage (i.e., 50 percent of capital costs was borrowed), and zero percent capital cost coverage (i.e., 100 percent of capital costs was borrowed), showed that the required electricity price needed for NPV4 0 could can be greatly reduced by avoiding the acquisition of debt for project construction. This relationship was a direct function of using a loan interest rate (10 percent) that was considerably higher than the discount rate used (five percent). 3.4. Supplemental model iteration 2 A subsidized low-interest financing mechanism and longer debt term counterbalanced some of the losses derived from an assumed 18 percent effective tax burden on annual revenues.
Combined with the use of straight-line annual depreciation for 45 percent of capital costs and the ability to “write off” annual losses, a four percent interest rate with 15-year debt term significantly decreased annual costs for Test Dam Sites 1–15. Supplemental Model Iteration 2 revealed that net present value breakpoints (i.e., the electricity price needed for NPV 40) were noticeably reduced from those derived in the base model runs (Fig. 12). For Test Dam Sites 1–15, the net present value breakpoints derived in Supplemental Model Iteration 2 decreased from the base model values anywhere from 8.6 percent to 13.6 percent. Net present value breakpoints under this scenario ranged from 7.6 cents/kWh to 19.2 cents/kWh. These breakpoint reductions were achieved primarily due to the six percent decrease in debt interest rate and the five year increase in loan term length. Note that these findings were based on an assumed best case scenario; one in which an Owner/Developer would be able to qualify for a low-interest State-subsidized loan package combined with a fairly aggressive ability to decrease income tax burden through annual depreciation and revenue losses. 3.5. Sensitivity and risk analysis results Even the most promising low-head dam sites, in terms of energy production, were not financially feasible for micro hydropower integration when electricity export rates were 7.5 cents/kWh or lower. Results also showed that the 49 test dam sites were more sensitive to initial project costs rather than O&M costs. The fluctuation of debt interest rate, debt interest term, and GHG reduction credit rate over the specified 10 percent sensitivity range did not influence financial viability as significantly as electricity export rates or initial costs. Risk analyses for the base model runs (i.e., model runs using 7.5 cents/kWh, 11.5 cents/kWh, and 18 cents/kWh) showed that electricity export rate was by far the dominant input variable. While every test dam site analyzed in our study produced independent and dynamic risk analysis results based on individual site characteristics, we observed a recurring underlying relationship between the relative impact of specific model input variables and the relative size (power capacity) of individual test dam sites. O&M costs and initial costs, as well as debt interest rate for some sites, tended to be the most influential input factors on financial viability for low-head dam sites with smaller power
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Fig. 7. Dam sites: net present value and energy export.
Fig. 8. Dam sites: net present value and dam drainage area.
capacities—those with power capacities less than approximately 20 kW. For sites with slightly larger power capacities – those with power capacities between 20 kW and 50 kW – O&M costs and initial costs still dominated, but were followed closely by electricity export rates. For the largest sites in our study – those with power capacities greater than 50 kW – the electricity export rate itself became the most influential input factor in terms of financial viability. 3.6. Cost comparisons to other energy sources In terms of capital costs per unit of energy generation (e.g., $/kWh) over the 30-year life of the facility, many of the test dam sites exhibited energy generation costs comparable to or lower than those achieved by conventional coal-fired generation in 2011. Although capacity factors for micro hydropower sites are relatively low (i.e., 46 percent to 52.2 percent in this study), the relatively long operating life (e.g., 30 to 100 þ years) and lack of annual fuel
costs allow micro hydropower sites to exhibit lower capital costs per unit energy produced. At the time of our study in 2011, thirteen test dam sites had lower capital costs per unit energy produced than conventional coal (6.8 cents/kWh; U.S. Energy Information Administration (2010)). Eighteen test dam sites had lower capital costs per unit energy produced than advanced nuclear technologies (9.4 cents/kWh; U.S. Energy Information Administration (2010)), and 29 test dam sites had lower capital costs per unit energy than solar photovoltaic generation (20.4 cents/kWh; U.S. Energy Information Administration (2010)). 3.7. Dam owner feedback The majority of the public dam owners consulted were Water Resource Directors or Public Utility Directors, but other representatives ranged from Town Council members to Mayors. Most public dam owner representatives supported the idea of micro hydropower; however, they approached the possible installation
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Fig. 9. Dam sites: net present value and hydraulic head.
Fig. 10. Dam sites: net present value and capital costs.
of micro hydropower infrastructure on their facilities with great trepidation. Their primary concerns were specific to the potential threat of any changes to their primary duty—providing reliable and affordable drinking water services to their customer base. All of the public dam owners articulated that flow limitations were their most pressing concerns. Some public representatives expressed interest in installing micro hydropower facilities on their dam structures if deemed financially feasible per their internal standards (i.e., positive NPV, positive cash flow, political popularity, etc.). These same representatives also stated that the additional operational demands required for micro hydropower facilities would likely not be feasible due to annual monetary constraints, the need to maintain redundant water volume behind the impoundment at all times, and personnel training issues. The private dam owners consulted ranged from HOA board members to Facility Maintenance Managers. Most private dam owners responded to the idea of micro hydropower installation with great interest. Rather than perceiving micro hydropower
operations as a liability, the majority of private dam owners stated that they would consider installing a micro hydropower facility as a possible asset assuming a viable NPV and adequate access to capital. However, knowledge of FERC licensing requirements (or even the existence of FERC) was fundamentally lacking for all private dam owners involved with the study. Private dam owners also expressed their concerns over maintenance/operational requirements and sufficient access to free or low-interest capital via Federal/State/local incentive programs. Many private dam owners stated that Federal grants and tax deductions were preferable over loan programs.
4. Discussion and conclusion None of the low-head dams contained within this study (0 out of 49 sites) were financially viable for energy production when modeled with electricity export rates (electricity pricing) similar to
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Fig. 11. Dam sites: net present value and O&M costs.
Fig. 12. Effects of loan subsidization and income tax circumstances on net present value breakpoints.
the rates that existing micro hydropower operators are currently receiving (7.5 cents/kWh; Fig. 5) during normal operation (i.e., when not receiving higher contracted rates associated with peakshaving events). However, sensitivity analyses suggested that a surprising number of low-head dam sites – 14 out of 49 in this study – may have been viable for production if provided funding opportunities comparable to alternative sources of renewable energy (i.e., up to 18 cents/kWh; Fig. 5). Nine of the low-head dam sites contained within the study area (Test Dam Site Numbers 1–9) could have realized positive NPV if provided electricity export rates at or slightly below 12 cents/kWh, and four of the low-head dam sites contained within the study area (Test Dam Site Numbers 1–4) could have realized positive NPV if provided electricity export rates at or slightly below 10 cents/kWh. These specific electricity export rates served as regional “trigger prices” for low-head dams in the North Carolina Piedmont, as conceptualized by Bockman et al. (2008).
The viability of retrofitting existing low-head dams with micro hydropower infrastructure in the North Carolina Piedmont – as modeled in this study – were most dependent on flow availability, cost-minimization and the availability of adequate electricity export rates. Anagnostopoulos and Papantonis (2007) showed similar results, in which electricity buyback rates and hydrological constraints were identified as the most significant factors affecting small hydropower development. The observed sensitivity analysis patterns also reinforce the importance of minimizing initial construction costs and O&M costs during the development of an existing low-head dam site as a micro hydropower asset. Dam sites with power capacities lower than 50 kW will likely not be practical for hydropower development unless developers can bypass or minimize a significant portion of upfront construction costs and incorporate very low overhead cost for daily operations. Sites with power capacities greater than 50 kW were less likely to experience the demanding fiscal constraints on site
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construction, operation, and maintenance that much smaller sites would experience. The smaller the power capacity of a proposed micro hydropower site, the more dependent the site becomes on receiving adequate electricity export rates as a revenue source. Other factors affecting the viability of micro hydropower integration may include physical access to the public electrical grid and the ever-increasing issue of electrical grid capacity and stability, as suggested by Lopez et al. (2007). The addition of micro hydropower sites to the existing grid will require technological advancements capable of integrating de-centralized systems in a safe and efficient manner while also ensuring grid stability. In addition, the relatively low percentage of initial costs that are due to capital costs is important to note. Most incentive programs available for funding the construction of hydropower facilities are designed around tax breaks based on capital investments (i.e., design and construction costs only) (Hughes, 2011). Many of the micro hydropower sites included in this study had relatively high permitting costs (in order to meet Federal, State, and local regulatory requirements) as compared to the actual capital costs needed for design/construction. More flexible incentive programs would help support low-head dam owners during the complex and unpredictable FERC permitting and licensing phases, as well as the more region-specific permitting phases. All told, the low-head dam sites included in our study area only approached financial viability if adequate flows could be met at all times while simultaneously minimizing upfront costs and operational costs over the life the proposed micro-hydropower system. Financially viable sites were generally those that comprised of dams with drainage basin areas larger than 129.5 km2 (50 mile2) and the use of subsidized low-interest financing mechanisms that are publicly-available. The integration of micro hydropower facilities on low-head dam sites within North Carolina may serve as a useful decentralized component of renewable domestic energy assimilation and REPS compliance. There may be hundreds of existing lowhead dam sites similar to these across North Carolina, and thousands of existing low-head dam sites across the U.S. that would become financially feasible for micro hydropower production if provided electricity export rates and subsidized loan programs comparable to those currently provided to the small wind and small solar industries. Nevertheless, the data contained in this study suggest that the apparent barriers to micro hydropower integration can only be alleviated by policy changes in the renewable energy market that will help make small hydropower more accessible, incentivized and marketed to the public along the lines of solar and wind. If the micro hydropower industry is to gain increasing market share, an increased knowledge of common site development constraints, permitting requirements, available tax incentives, subsidized low-interest loan programs, and standard contracts with Investor Owned Utilities (IOUs) will likely be needed. In early-2011, North Carolina had a total of 63 independent incentive programs related to renewables and efficiency (DSIREb, 2011); only 10 of which were applicable to non-marine hydropower facilities, with 19 programs dedicated to incentivizing small photovoltaic electricity generation. At the time of this study, solar renewable energy credits (SCRECs) under Progress Energy's SunSense Program were selling for as high as 18 cents/kWh. The SunSense Commercial PV Program has since been cancelled in North Carolina, but options are still available to sell energy at standard or negotiated rates for generation from qualifying small
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wind, solar, and hydroelectric sites that are interconnected to the electric grid. Owners of qualifying generation facilities are able to maintain all RECs associated with the output Progress Energy (Progress) (2012). As similar programs across the United States adjust to an everchanging energy market, the incentives available to micro hydropower generators may need to provide trigger prices similar to the ones demonstrated in this study. If the correct combination of creative financing and efficient design is applied, there may be an opportunity to access a potentially significant source of domestic energy that is currently stored behind countless low-head dams across the United States.
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