NREL is a national laboratory of the U.S. Department of Energy, 

Office of Energy Efficiency & Renewable Energy, operated by the 

Alliance for Sustainable Energy, LLC.

Contract No. DE-AC36-08GO28308

Feasibility Study of Economics 

and Performance of Solar 

Photovoltaics at the VAG Mine 

Site in Eden and Lowell, Vermont 

A Study Prepared in Partnership with the 

Environmental Protection Agency for the 

RE-Powering America’s Land Initiative: 

Siting Renewable Energy on Potentially 

Contaminated Land and Mine Sites

Joe Simon and Gail Mosey

Produced under direction of the U.S. Environmental Protection 

Agency (EPA) by the National Renewable Energy Laboratory (NREL) 

under Interagency Agreement IAG-09-1751 and Task No. 

WFD4.1001. 

Technical Report

NREL/TP-7A30-57766

April 2013
NREL is a national laboratory of the U.S. Department of Energy, Office of Energy 

Efficiency & Renewable Energy, operated by the Alliance for Sustainable Energy, LLC.

Contract No. DE-AC36-08GO28308

National Renewable Energy Laboratory

15013 Denver West Parkway

Golden, CO 80401

303-275-3000 • www.nrel.gov

Feasibility Study of Economics 

and Performance of Solar 

Photovoltaics at the VAG Mine 

Site in Eden and Lowell, Vermont 

A Study Prepared in Partnership with the 

Environmental Protection Agency for the 

RE-Powering America’s Land Initiative: 

Siting Renewable Energy on Potentially 

Contaminated Land and Mine Sites

Joe Simon and Gail Mosey

Prepared under Task No. WFD4.1001

Technical Report

NREL/ TP-7A30-57766

April 2013
NOTICE

This manuscript has been authored by employees of the Alliance for Sustainable Energy, LLC (“Alliance”) under 

Contract No. DE-AC36-08GO28308 with the U.S. Department of Energy (“DOE”).

This report was prepared as an account of work sponsored by an agency of the United States government. 

Neither the United States government nor any agency thereof, nor any of their employees, makes any warranty, 

express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of 

any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately 

owned rights. Reference herein to any specific commercial product, process, or service by trade name, 

trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, 

or favoring by the United States government or any agency thereof. The views and opinions of authors expressed 

herein do not necessarily state or reflect those of the United States government or any agency thereof.

Cover Photos: (left to right) PIX 16416, PIX 17423, PIX 16560, PIX 17613, PIX 17436, PIX 17721

Printed on paper containing at least 50% wastepaper, including 10% post consumer waste. 
iii

Acknowledgments

The National Renewable Energy Laboratory (NREL) thanks the U.S. Environmental Protection 

Agency (EPA) for its interest in securing NREL’s technical expertise. In particular, NREL and 

the assessment team for this project are grateful to the Vermont Asbestos Group (VAG) Mine 

facility managers, engineers, and operators for their generous assistance and cooperation. 

Special thanks go to Gary Lipson, Shea Jones, Katie Brown, Lura Matthews, Jessica Trice, and 

Brigid Lowery from EPA; John Schmeltzer and Linda Elliott from the Vermont Department of 

Environmental Conservation; John Mandeville from the Lamoille Economic Development 

Corporation; Bonnie Waninger from the Lamoille County Regional Planning Commission; Gail 

Aloisio from the Northeastern Vermont Development Association; Leslie White and Lynn Noah 

from the township of Eden; Alden Warner and Dwight Richardson from the township of Lowell; 

and Gary Nolan representing the property owner. The authors would also like to thank the team 

for the information provided on the site and the extensive tour of the overall site. In addition, the 

authors would like to thank the Mt. Norris Boy Scout Reservation for hosting the meeting 

portion of the site visit. 
iv

Executive Summary

The U.S. Environmental Protection Agency (EPA), in accordance with the RE-Powering 

America’s Land initiative, selected the Vermont Asbestos Group (VAG) Mine site in Eden, 

Vermont, and Lowell, Vermont, for a feasibility study of renewable energy production. The 

National Renewable Energy Laboratory (NREL) provided technical assistance for this project. 

The purpose of this report is to assess the site for a possible photovoltaic (PV) system installation 

and estimate the cost, performance, and site impacts of different PV options. In addition, the 

report recommends financing options that could assist in the implementation of a PV system at 

the site. This study did not assess environmental conditions at the site. 

The 1,550-acre VAG site is located in the townships of Eden and Lowell in northern Vermont. 

The site was mined for asbestos from 1936 until closure in 1993. The mine covers approximately 

650 acres and consists of two large tailing piles, several rock piles, quarries, a mill, miningrelated buildings, and a pit lake. Since closure, several interim measures have taken place to 

mitigate releases from the site, and while the site has been considered a candidate for the 

National Priorities List, the townships of Eden and Lowell have voted against pursuing 

Superfund status for the site. Additional information on the site is available through the EPA REPowering America’s Land fact sheet for Lowell and Eden1

 and the Vermont Department of 

Environmental Conservation website.2 

The scale of the mine is such that many large, non-vegetated flat open areas containing removed 

and graded cap rock within the 1,550-acre site could potentially be used for utility-scale solar 

development. Approximately 113 acres are potentially suitable for a PV installation, consisting 

of up to a 2.2-MW array on the waste-rock area (approximately 11 acres) on the northeast 

portion of the site, a 4.6-MW array in the current entry and building area (approximately 

21 acres), and an 11.6-MW array on the south facing slopes (approximately 81 acres) of the Eden 

and Lowell piles. 

The feasibility of a PV system installed is highly impacted by the available area for an array, the 

solar resource, distance to transmission lines, and distance to major roads. In addition, the 

operating status, ground conditions, and restrictions associated with redevelopment of 

contaminated mine sites impact the feasibility of a PV system. 

The economic feasibility of a potential PV system on the VAG Mine site depends greatly on the 

purchase price of the electricity produced. The economics of the potential system were analyzed 

using the current Vermont Sustainably Priced Energy Development (SPEED) standard offer for 

systems up to 2.2 MW in size of $0.27/kWh, non-escalating. For the analysis of a larger system, 

the average negotiated rate for systems within the SPEED program of $0.13/kWh was used. 

Table ES-1 summarizes the system performance and economics of a potential system that would 

use all available areas that were surveyed at the VAG Mine site. The table shows the annual 

 

1 RE-Powering America’s Land: Evaluating the Feasibility of Siting Renewable Energy Production

on Potentially Contaminated Land. EPA/Office of Solid Waste and Emergency Response, November 2011. 

http://www.epa.gov/oswercpa/docs/r01-11-009_edenandlowell.pdf. 2 For more information about the Vermont Department of Environmental Conservation, see 

http://www.anr.state.vt.us/dec/dec.htm. 
v 

energy output from the system, along with the number of average American households that 

could be powered from such a system and estimated job creation. 

As indicated in Table ES-1, a 2.2-MW ballasted fixed-tilt system installed on the flat cap-rock 

area of the site to take full advantage of the Vermont SPEED standard offer program prior to 

extensive site remediation could realize a net present value (NPV) of $2,199,995 and an internal 

rate of return (IRR) of approximately 24%. This analysis considers the current cost of energy, 

expected installation cost, 20% premium for working on a non-remediated site, site solar 

resource, and existing incentives for the proposed PV system. This savings and after-tax IRR is 

attractive, and as such, a solar PV system represents a viable reuse for the site and should 

be considered. 

A comparative single-axis tracking system would yield an after-tax NPV of $3,012,237 on firstyear annual revenue of $970,033/year. The after-tax IRR is estimated at 26%. While this is 

higher, it is important to note that complications associated with installing a tracking system on 

the existing land may incur atypical costs. Any differential settlement would also negatively 

impact the performance of the system and increase maintenance costs on the site. 

Secondly, a scenario was considered wherein the entire currently flat area potentially feasible for 

PV was used following, or as part of, a potential remediation strategy. Finally, a scenario was 

considered wherein a cap-integrated thin-film PV system would be installed on all of the southfacing slopes of the Eden and Lowell pile as part of a remediation plan. As both of these systems 

would be larger than 2.2 MW, a negotiated rate of $0.13/kWh was used. Both of these scenarios 

resulted in a negative NPV and low IRR. Due to the currently low NPV forecast, the lack of an 

agreed-upon remediation strategy for the Eden and Lowell piles, and potential complications of 

installing thin-film solar on the steep slopes of the piles, this solution is not attractive at this time.

Table ES-1. VAG Mine PV System Summary

System Type

Financial 

Model PV System Sizea Array Tilt Array Size Annual Output

Number of 

Houses Poweredb

Construction 

Period Jobsc

Jobs 

Sustainedd

(kW) (deg) (acres) (kWh/year)

Crystalline Silicon (Fixed Tilt) PPA 2,200 LAT 9.9 2,879,581 260.8 70.3 0.7

Crystalline Silicon (Single-axis Tracking) PPA 2,200 n/a 11 3,592,714 325.4 * *

Crystalline Silicon (Fixed Tilt) PPA 4,600 n/a 20.7 8,386,334 759.6 * *

Crystalline Silicon (Single-axis Tracking) PPA 4,600 LAT 23 10,462,389 947.7 * *

Thin-film (Integrated into cap) PPA 11,600 n/a 81 16,456,059 1490.6 * *

System Type

Financial 

Model Annual Output PPA Pricee System Cost

Total System 

Cost 1ST Year Revenue After-tax NPV After-tax IRR

(kWh/year) (¢/kWh) ($/watt) ($/year) %

Crystalline Silicon (Fixed Tilt) PPA 2,879,581 27 $ 3.34 $ 7,402,062 $ 777,486 $ 2,189,995.00 24.08

Crystalline Silicon (Single-axis Tracking) PPA 3,592,714 27 $ 4.02 $ 8,843,860 $ 970,033 $ 3,012,237.96 26.11

Crystalline Silicon (Fixed Tilt) PPA 8,386,344 13 $ 2.77 $ 17,728,946 $ 1,090,224 $ (913,636.00) 3.46

Crystalline Silicon (Single-axis Tracking) PPA 10,462,389 13 $ 3.34 $ 21,338,936 $ 1,360,110 $ (490,451.00) 5.28

Thin-film (Integrated into cap) PPA 16,456,059 13 $ 2.79 $ 32,363,629 $ 2,139,287 $ (510,574.00) 5.74

a Array size determined by available acerage for each scenario. 2.2 MW used for the first scenario to take adavantage of SPEED standard offer. 

b Number of average American households that could hypothetically be powered by the PV system assuming 11,040 kWh/year/household.

c Job-years created as a result of project capital investment including direct, indirect, and induced jobs.

d Jobs (direct, indirect, and induced) sustained as a result of operations and maintenance (O&M) of the system.

e Assumes a fixed PPA rate. Inflation assumed to be 1.5%/year.

* JEDI analysis was not completed for these systems

U.S. Energy Information Administration. http://www.eia.doe.gov/ask/electricity_faqs.asp#electricity_use_home. Accessed November 2, 2010.
vi 

Table of Contents

1 Study and Site Background................................................................................................................. 1

2 Development of a PV System on Mine Sites...................................................................................... 4

3 PV Systems ........................................................................................................................................... 6

3.1 PV Overview .................................................................................................................................... 6

3.2 Major System Components .............................................................................................................. 6

3.2.1 PV Module .......................................................................................................................... 7

3.2.2 Inverter ................................................................................................................................ 8

3.2.3 Balance-of-System Components ....................................................................................... 10

3.2.4 Operation and Maintenance .............................................................................................. 12

3.3 Siting Considerations ..................................................................................................................... 12

4 Proposed Installation Location Information .................................................................................... 13

4.1 VAG Mine Site PV System ........................................................................................................... 13

4.2 Utility-Resource Considerations .................................................................................................... 15

4.3 Useable Acreage for PV System Installation ................................................................................. 16

4.4 PV Site Solar Resource .................................................................................................................. 17

4.5 VAG Mine Energy Usage .............................................................................................................. 18

4.5.1 Net Metering ..................................................................................................................... 19

4.5.2 Virtual Net Metering ......................................................................................................... 20

5 Economics and Performance............................................................................................................ 21

5.1 Assumptions and Input Data for Analysis ..................................................................................... 21

5.2 Proposed PV Systems Analyzed .................................................................................................... 23

5.2.1 Scenario 1 ......................................................................................................................... 23

5.2.2 Scenario 2 ......................................................................................................................... 23

5.2.3 Scenario 3 ......................................................................................................................... 23

5.3 SAM-Forecasted Economic Performance ...................................................................................... 24

5.3.1 Scenario 1 ......................................................................................................................... 24

5.3.2 Scenario 2 ......................................................................................................................... 24

5.3.3 Scenario 3 ......................................................................................................................... 25

5.4 Job Analysis and Impact ................................................................................................................ 25

5.5 Financing Opportunities................................................................................................................. 26

5.5.1 Owner and Operator Financing ......................................................................................... 27

5.5.2 Third-Party Developers with Power Purchase Agreements .............................................. 27

5.5.3 Third-Party “Flip” Agreements......................................................................................... 27

5.5.4 Hybrid Financial Structures .............................................................................................. 28

5.5.5 Solar Services Agreement and Operating Lease ............................................................... 28

5.5.6 Sale/Leaseback .................................................................................................................. 29

5.5.7 Community Solar Gardens/Solar ...................................................................................... 29

6 Conclusions and Recommendations ............................................................................................... 30

Appendix A. Provided Site Information .................................................................................................. 31

Appendix B. Assessment and Calculations Assumptions ................................................................... 32

Appendix C. Solar Access Measurements ............................................................................................. 33

Appendix D. Results of the JEDI Model.................................................................................................. 34

Appendix E. Results of the System Advisor Model............................................................................... 38
vii 

List of Figures

Figure 1. Aerial view of the VAG Mine ..........................................................................................2

Figure 2. Images of the VAG Mine .................................................................................................2

Figure 3. Generation of electricity from a PV cell ...........................................................................6

Figure 4. Ground-mounted array diagram .......................................................................................7

Figure 5. Mono- and multi-crystalline solar panels .........................................................................8

Figure 6. Thin-film solar panels installed on (left) solar energy cover and (middle and right) 

fixed-tilt mounting system .........................................................................................................8

Figure 7. String inverter ...................................................................................................................9

Figure 8. View of feasible PV area at the VAG Mine site ............................................................13

Figure 9. Aerial view of the feasible area for PV at the VAG Mine site .......................................14

Figure 10. Views of the VAG Mine site ........................................................................................15

Figure 11. Electrical tie-in point for the PV system (left) and site distribution (right) .................16

Figure 12. Electrical tie-in point (A) for the PV system and site distribution ...............................16

Figure C-1. Solar access measurements for the VAG Mine PV site .............................................33

List of Tables

Table ES-1. VAG Mine PV System Summary ................................................................................v

Table 1. Energy Density by Panel and System ..............................................................................11

Table 2. Site Identification Information and Specifications ..........................................................17

Table 3. Performance Results for Fixed-Tilt PV ...........................................................................18

Table 4. Performance Results for Zero-Degree Single-Axis PV ...................................................18

Table 5. Installed System Cost Assumptions .................................................................................22

Table 6. PV System Summary .......................................................................................................25

Table 7. JEDI Analysis Assumptions ............................................................................................26

Table B-1. Cost, System, and Other Assessment Assumptions .....................................................32

Table D-1. PV Data Summary .......................................................................................................34

Table E-1. SAM Results ................................................................................................................38
1 

1 Study and Site Background

The U.S. Environmental Protection Agency (EPA), in accordance with the RE-Powering 

America’s Land initiative, selected the Vermont Asbestos Group (VAG) Mine site in

Eden, Vermont, and Lowell, Vermont, for a feasibility study of renewable energy 

production. The National Renewable Energy Laboratory (NREL) provided technical 

assistance for this project. The purpose of this report is to assess the site for a possible 

photovoltaic (PV) system installation and estimate the cost, performance, and site 

impacts of different PV options. In addition, the report recommends financing options 

that could assist in the implementation of a PV system at the site. This study did not 

assess environmental conditions at the site. 

The 1,550-acre VAG site is located in the townships of Eden and Lowell in northern 

Vermont. Major commercial asbestos mining at the site took place from 1936 until the 

site closed in 1993. The mine covers approximately 650 acres and consists of two large 

tailing piles, several rock piles, quarries, a mill, mining-related buildings, and a pit lake. 

Since closure, several interim measures have taken place to mitigate releases from the 

site, and while the site has been considered a candidate for the National Priorities List, 

the townships of Eden and Lowell have voted against pursuing Superfund status for the 

site. Additional information on the site is available through the EPA RE-Powering 

America’s Land fact sheet for Eden and Lowell3

 and the State of Vermont’s website for 

the VAG Mine site.4

Under the RE-Powering America’s Land initiative, the EPA provided funding to NREL 

to support a feasibility study of solar renewable energy generation at the VAG Mine site.

The site contains several major features and areas important for consideration of eligible 

solar installation. Figure 1 provides an aerial view of the site. In addition, Figure 2 shows 

the current condition of the site. Currently, the mine site consists of 11 mine and mill 

buildings and several large tailing and waste rock piles containing asbestos. The two 

largest tailing piles are estimated at 30 million tons. As demonstrated, a wide range of 

conditions exist. Several areas have unstable, non-vegetated ground conditions with 

significant slopes. As the site has not been remediated as of the writing of this report, a 

full understanding of the current ground conditions and contamination is necessary. The 

purpose of this report is not to summarize current conditions but rather to indicate the 

potential feasibility of a solar system installation, assuming that environmental risks 

could be overcome or mitigated. Summary information on the site is available through 

the State of Vermont and the EPA. 

 

3 RE-Powering America’s Land: Evaluating the Feasibility of Siting Renewable Energy Production

on Potentially Contaminated Land (Eden and Lowell, Vermont). U.S. Environmental Protection Agency 

Office of Solid Waste and Emergency Response, November 2011. http://www.epa.gov/oswercpa/docs/r01-

11-009_edenandlowell.pdf. 4 For more information about the VAG Mine site, see 

http://www.anr.state.vt.us/dec/wastediv/sms/VAG.htm. 
2 

Figure 1. Aerial view of the VAG Mine

Source: Image generated using Google Earth

Figure 2. Images of the VAG Mine. Photos by Joe Simon, NREL
3 

Feasibility assessment team members from NREL, the State of Vermont, VAG, and the 

Township of Eden conducted a site visit on July 17, 2012, to gather information integral 

to this feasibility study. The team considered a variety of information, including solar 

resource, transmission availability, community acceptance, and ground conditions. 
4 

2 Development of a PV System on Mine Sites

Through the RE-Powering America’s Lands initiative, the EPA has identified several 

benefits for siting solar PV facilities on contaminated mine lands, noting that they: 

• Can be developed in place of limited greenfields, preserving the land carbon sink 

• Could have environmental conditions that are not well-suited for commercial or 

residential redevelopment and may be adequately zoned for renewable energy

• Are generally located near existing roads and energy transmission or distribution 

infrastructure

• Might provide an economically viable reuse for sites that might have significant 

cleanup costs or low real estate development demand 

• Can provide job opportunities in urban and rural communities 

• Can advance cleaner and more cost-effective energy technologies and reduce the 

environmental impacts of energy systems (e.g., reduce greenhouse gas emissions). 

By taking advantage of these potential benefits, PV can provide a viable, beneficial reuse, 

and in many cases, generate significant revenue on a site that would otherwise go unused. 

The VAG Mine is owned by the Vermont Asbestos Group, which along with the 

community and the State of Vermont, is interested in potential revenue flows on the site.

As a large, significant site in the area, the local communities of Eden and Lowell have 

significant interest in the redevelopment of the site, and community engagement is 

critical to match future reuse options to the community’s vision for the site. 

Understanding opportunities studied and realized by other similar sites demonstrates the 

potential for PV system development. EPA has published the “Handbook on Siting 

Renewable Energy Projects While Addressing Environmental Issues,” which is relevant 

to the potential development at the VAG mine site.

5

 Past studies and developments have 

occurred at other mine sites, including the Molycorp site6 in Questa, New Mexico; the 

Freeport McMoRan Chino Mine7 in Silver City, New Mexico; and the Leviathan Mine 

superfund site8

 in Alpine County, California. 

 

5 Handbook on Siting Renewable Energy Projects While Addressing Environmental Issues. U.S. 

Environmental Protection Agency Office of Solid Waste and Emergency Response’s Center for Program 

Analysis, 2012. http://www.epa.gov/oswercpa/docs/handbook_siting_repowering_projects.pdf. 6 RE-Powering America’s Land Fact Sheet: Siting Renewable Energy Projects While Addressing 

Environmental Issues. U.S. Environmental Protection Agency, December 2011. 

http://www.epa.gov/oswercpa/docs/decision_tree_factsheet.pdf 7 RE-Powering America’s Land: Evaluating the Feasibility of Siting Renewable Energy Production

on Potentially Contaminated Land (Silver City, New Mexico). U.S. Environmental Protection Agency 

Office of Solid Waste and Emergency Response, November 2011. http://www.epa.gov/oswercpa/docs/r06-

11-002_silver_city.pdf. 8 RE-Powering America’s Land: Evaluating the Feasibility of Siting Renewable Energy Production

on Potentially Contaminated Land (Alpine County, California). U.S. Environmental Protection Agency, 

November 2011. http://www.epa.gov/oswercpa/docs/develop_potential/alpine.pdf. 
5 

Due to the scale and topographical conditions of the VAG mine site, it is unlikely that 

any PV system installed on the site would use all available land. Depending on 

remediation strategies pursued, the subject site has potential to be used for other functions 

beyond the solar PV systems proposed in this report. Any potential use should align with 

the community vision for the site and should work to enhance the overall utility of 

the property. 

Beyond the financial benefits resulting from the development of renewable energy on the 

subject site, many additional nonfinancial benefits exist for the site, the community, and 

the state. There are many compelling reasons to consider moving toward renewable 

energy sources for power generation instead of fossil fuels, including: 

• Renewable energy sources offer a sustainable energy option in the broader 

energy portfolio 

• Renewable energy can have a net positive effect on human health and the 

environment 

• Deployment of renewable energy bolsters national energy independence and 

increases domestic energy security

• Fluctuating electric costs can be mitigated by locking in electricity rates 

through long-term power purchase agreements (PPAs) linked to renewable 

energy systems 

• Generating energy without harmful emissions or waste products can be 

accomplished through renewable energy sources.
6 

3 PV Systems

3.1 PV Overview

Solar PV technology converts energy from solar radiation directly into electricity. Solar 

PV cells are the electricity-generating component of a solar energy system. When 

sunlight (photons) strikes a PV cell, an electric current is produced by stimulating 

electrons (negative charges) in a layer in the cell designed to give up electrons easily. The 

existing electric field in the solar cell pulls these electrons to another layer. By 

connecting the cell to an external load, this current (movement of charges) can then be 

used to power the load (e.g., light bulb). Figure 3 shows the generation of electricity from 

a PV cell. 

Figure 3. Generation of electricity from a PV cell

Source: EPA

PV cells are assembled into a PV panel or module. PV modules are then connected to 

create an array. The modules are connected in series and then in parallel as needed to 

reach the specific voltage and current requirements for the array. The direct current (DC) 

electricity generated by the array is then converted by an inverter to useable alternating 

current (AC) that can be consumed by adjoining buildings and facilities or exported to the 

electricity grid. PV system size varies from small residential (2–10 kW), to commercial 

(100–500 kW), to large utility scale (10+ MW). Central distribution plants are also 

currently being built in the 100+ MW scale. Electricity from utility-scale systems is 

commonly sold back to the electricity grid. 

3.2 Major System Components

A typical PV system is made up of several key components, including: 

• PV modules 

• Inverter

• Balance-of-system (BOS) components (e.g., combiner box, transformer, and 

meter).

These components (see Figure 4) and other PV system components are discussed below. 

(-)

(+)

-

- -

-

Electron

Current flow

-

Solar cell

- - -

Load
7 

Figure 4. Ground-mounted array diagram

Source: NREL

3.2.1 PV Module

Module technologies are differentiated by the type of PV material used, resulting in a 

range of conversion efficiencies from light energy to electrical energy. The module 

efficiency is a measure of the percentage of solar energy converted into electricity. 

Two common PV technologies that have been widely used for commercial- and utilityscale projects are crystalline silicon and thin film. 

3.2.1.1 Crystalline Silicon

Traditional solar cells are made from silicon, which is abundant and nontoxic. It builds on 

a strong industry on both supply (silicon industry) and product side. This technology has 

been demonstrated for a consistent and high efficiency for over 30 years in the field. The 

performance degradation, a reduction in power generation due to long-term exposure, is 

under 1% per year. Silicon modules have a lifespan in the range of 25–30 years but can 

keep producing energy beyond this range. 

Typical overall efficiency of silicon solar panels is between 12% and 18%. However, 

some manufacturers of mono-crystalline panels claim an overall efficiency nearing 20%. 

This range of efficiencies represents significant variation among the crystalline silicon 

technologies available. The technology is generally divided into mono- and multicrystalline technologies, which indicates the presence of grain-boundaries (i.e., multiple 

crystals) in the cell materials, and it is controlled by raw material selection and 

manufacturing technique. Crystalline silicon panels are widely used based on 

deployments worldwide. 
8 

Figure 5 shows two examples of crystalline solar panels: mono- and multi-silicon 

installed on tracking mounting systems.

Figure 5. Mono- and multi-crystalline solar panels. Photos from (left) SunPower 

Corporation, NREL 23816 and (right) SunPower, NREL 13823

3.2.1.2 Thin Film

Thin-film PV cells are made from amorphous silicon (a-Si) or non-silicon materials, such 

as cadmium telluride (CdTe). Thin-film cells use layers of semiconductor materials only 

a few micrometers thick. Due to their unique nature, some thin-film cells are constructed 

into flexible modules, enabling such applications as solar energy covers for landfills, such 

as a geomembrane system. Other thin-film modules are assembled into rigid 

constructions that can be used in a fixed-tilt or, in some cases, tracking system 

configurations. 

The efficiency of thin-film solar cells is generally less than for crystalline cells. Current 

overall efficiency of a thin-film panel is 6%–8% for a-Si and 11%–12% for CdTe. 

Figure 6 shows thin-film solar panels.

Figure 6. Thin-film solar panels installed on (left) solar energy cover and (middle and right) 

fixed-tilt mounting system. Pictures from (left) City of San Antonio, NREL 18068; (middle) 

Beck Energy, NREL 14726; and (right) U.S. Coast Guard Petaluma site, NREL 17395

Industry standard warranties of both crystalline and thin-film PV panels typically 

guarantee system performance of 80% of the rated power output for 25 years. After 25 

years, they will continue producing electricity at a lower performance level.

3.2.2 Inverter

Inverters convert DC electricity from the PV array into AC and can connect seamlessly to 

the electricity grid. Inverter efficiencies can be as high as 98.5%. 
9 

Inverters also sense the utility power frequency and synchronize the PV-produced power 

to that frequency. When utility power is not present, the inverter will stop producing AC 

power to prevent “islanding” or putting power into the grid while utility workers are 

trying to fix what they assume is a de-energized distribution system. This safety feature is 

built into all grid-connected inverters in the market. Electricity produced from the system 

may be fed to a step-up transformer to increase the voltage to match the grid. 

There are two primary types of inverters for grid-connected systems: string and microinverters. Each type has strengths and weaknesses and would be recommended for 

different types of installations.

String inverters are most common and typically range in size from 1.5 kW to 1,000 kW. 

These inverters tend to be cheaper on a capacity basis. They also have high efficiency and 

lower operation and maintenance (O&M) costs. String inverters offer various sizes and 

capacities to handle a large range of voltage output. For larger systems, string inverters 

are combined in parallel to produce a single point of interconnection with the grid. 

Warranties typically run between 10 and 20 years with 10 years being the current 

industry standard. On larger units, extended warranties up to 20 years are possible. Given 

that the expected life of PV panels is 25–30 years, an operator can expect to replace a 

string inverter at least one time during the life of the PV system. 

Micro-inverters are dedicated to the conversion of a single PV module’s power output. 

The AC output from each module is connected in parallel to create the array. This 

technology is relatively new to the market and in limited use in larger systems due to the 

potential increase in O&M associated with significantly increasing the number of 

inverters in a given array. Current micro-inverters range in size between 175 W and 

380 W. These inverters can be the most expensive option per watt of capacity. Warranties 

range from 10–20 years. Small projects with irregular modules and shading issues 

typically benefit from micro-inverters. 

With string inverters, small amounts of shading on a solar panel will significantly affect 

the entire array production. However, if micro-inverters are used, it impacts only that 

shaded panel and not the entire array production. Figure 7 shows a string inverter.

Figure 7. String inverter. Photo by Warren Gretz, NREL 07985
10 

3.2.3 Balance-of-System Components

In addition to the solar modules and inverter, a solar PV system consists of other parts 

called BOS components, which include: 

• Mounting racks and hardware for the panels 

• Wiring for electrical connections. 

3.2.3.1 Mounting Systems

An array has to be secured and oriented optimally to maximize system output. The 

structure holding the modules is referred to as the mounting system. 

3.2.3.1.1 Ground-Mounted Systems

For ground-mounted systems, the mounting system can be either directly anchored into 

the ground (via driven piers or concrete footers) or ballasted on the surface without 

ground penetration. Mounting systems must withstand local wind loads, which range 

from 90–120 mph for most areas or 130 mph or more for areas with hurricane potential. 

Depending on the region, snow and ice loads must also be a design consideration for the 

mounting system. For surface applications on potentially contaminated mine sites, such 

as the VAG mine, mounting system designs will be primarily driven by these 

considerations coupled with settlement concerns. 

Typical ground-mounted systems can be categorized as fixed tilt or tracking. Fixed-tilt 

mounting structures consist of panels installed at a set angle, typically based on site 

latitude and wind conditions, to increase exposure to solar radiation throughout the year. 

Fixed-tilt systems are used at many brownfield sites. They have lower maintenance costs 

but generate less energy (kWh) per unit power (kW) of capacity than tracking systems. 

Tracking systems rotate the PV modules so they are following the sun as it moves across 

the sky. This increases energy output but also increases maintenance and equipment costs 

slightly. Single-axis tracking, where PV is rotated on a single axis, can increase energy 

output up to 25% or more. With dual-axis tracking, PV is able to directly face the sun all 

day, potentially increasing output up to 35% or more. Depending on underlying soil 

conditions, single- and dual-axis trackers may not be suitable due to potential settlement 

effects, which can interfere with the alignment requirements of such systems. 

Each type of system requires a different amount of land per DC-watt of rated energy 

output. Table 1 summarizes the areas required and demonstrates that tracking systems 

require more land due to a need to avoid having the modules shade each other. While the 

DC-watts per square foot are lower, some of this difference is recouped because tracking 

systems are able to have a higher output, as described above. Table 1 also demonstrates 

that, for example, thin-film panels are not as efficient per square foot of area as 

crystalline silicon, though their cost is lower. 
11 

Table 1. Energy Density by Panel and System

System Type Fixed-Tilt Energy Density 

(DC-Watts/ft2

) 

Single-Axis Tracking 

Energy Density

(DC-Watts/ft2

) 

Crystalline Silicon 4.0 3.3

Thin Film 3.3 2.7

Hybrid High 

Efficiency

4.8 3.9

The selection of mounting type is dependent on many factors, including installation size, 

electricity rates, government incentives, land constraints, latitude, and local weather. 

Contaminated land applications may raise additional design considerations due to site 

conditions, including differential settlement. 

Selection of the mounting system is also heavily dependent on anchoring or foundation 

selection. The mounting system design will also need to meet applicable local building 

code requirements with respect to snow, wind, and seismic zones. Selection of mounting 

types should also consider frost protection needs, especially in cold regions, such as 

New England. 

3.2.3.2 Wiring for Electrical Connections

Electrical connections, including wiring, disconnect switches, fuses, and breakers are 

required to meet electrical code (e.g., NEC Article 690) for both safety and equipment 

protection. 

In most traditional applications, wiring from (1) the arrays to inverters and (2) inverters 

to point of interconnection is generally run as direct burial through trenches. In 

contaminated mine applications, this wiring may be required to run through aboveground conduit due to restrictions with cap penetration or other concerns. Therefore, 

developers should consider noting any such restrictions, if applicable, in requests for 

proposals in order to improve overall bid accuracy. Similarly, it is recommended that PV 

system vendors reflect these costs in the quote when costing out the overall system.

3.2.3.3 PV System Monitoring 

Monitoring PV systems can be essential for reliable functioning and maximum yield of a 

system. It can be as simple as reading values, such as produced AC power, daily kilowatthours, and cumulative kilowatt-hours, locally on an LCD display on the inverter. For 

more sophisticated monitoring and control purposes, environmental data, such as module 

temperature, ambient temperature, solar radiation, and wind speed, can be collected. 

Remote control and monitoring can be performed by various remote connections. 

Systems can send alerts and status messages to the control center or user. Data can be 

stored in the inverter’s memory or in external data loggers for further system analysis. 

Collection of this basic information is standard for solar systems and is not unique to 

brownfield or contaminated site applications. 
12 

Weather stations are typically installed in large-scale systems. Weather data, such as solar 

radiation and temperature, can be used to predict energy production, enabling comparison 

of the target and actual system output and performance and identification of underperforming arrays. Operators might also use these data to identify, for example, required 

maintenance, shade on panels, and accumulating dirt on panels. Monitoring system data 

can also be used for outreach and education. This can be achieved with publicly 

available, online displays, wall-mounted systems, or even smartphone applications. 

3.2.4 Operation and Maintenance

PV panels typically have a 25-year performance warranty. The inverters, which come 

standard with a 10-year warranty (extended warranties available), are expected to last 10–

15 years. System performance should be verified on a vendor-provided website. Wire and 

rack connections should be checked annually. This economic analysis uses an annual 

O&M cost computed as $20/kW/yr, which is based on the historical O&M costs of 

installed fixed-axis grid-tied PV systems. Single-axis tracking systems assume an annual 

O&M cost of $22/kW/yr, and dual-axis tracking systems assume an annual O&M cost of 

$25/kW/yr. In addition, the system should expect a replacement of system inverters in 

year 15 at a cost of $0.25/W. This is already factored in to the average O&M costs cited 

above. The values used here are industry averages. For a system placed in an area of the

site that has not been remediated, the O&M costs may be higher. For the purposes of this 

report, however, the average values were used. 

3.3 Siting Considerations

PV modules are very sensitive to shading. When shaded (either partially or fully), the 

panel is unable to optimally collect the high-energy beam radiation from the sun. As 

explained above, PV modules are made up of many individual cells that collectively

produce a small amount of current and voltage. These individual cells are connected in 

series to produce a larger current. If an individual cell is shaded, it acts as resistance to 

the whole series circuit, impeding current flow and dissipating power rather than 

producing it. 

The NREL solar assessment team uses a Solmetric SunEye solar path calculator to assess 

shading at particular locations by analyzing the sky view where solar panels will be 

located. By finding the solar access, the NREL team can determine if the area is 

appropriate for solar panels. 

Following the successful collection of solar resource data using the Solmetric SunEye 

tool and the determination that a site is adequate for a solar installation, an analysis must 

be conducted to determine the ideal system size. System size depends highly on the 

average energy use of the facilities on the site, PPAs, available incentives, and 

utility policy. 
13 

4 Proposed Installation Location Information

This section summarizes the findings of the NREL solar assessment site visit on

July 17, 2012. 

4.1 VAG Mine Site PV System

As discussed in Section 1, the VAG Mine site is currently owned by the Vermont 

Asbestos Group. 

When considering the feasibility of any PV system on the VAG Mine site, consideration 

must be made to the current site condition as well as the various potential remediation 

strategies. While the entire site is approximately 1,550 acres in total, a majority of the site 

is heavily vegetated, with a slope that is too steep to accommodate PV installation 

economically or has inappropriately facing slopes. Under a full remediation strategy, it is 

estimated that up to 113 acres could be available for a PV system. Use of 113 acres 

would require significant removal of infrastructure, remediation, development of 

electrical transmission, site grading, and access road development. 

Alternatively, approximately 11 acres are available and potentially suitable on portions of 

the site that are currently flat, stable, free of buildings, near electrical infrastructure, and 

unshaded with a suitable solar resource. Demonstrated in Figure 8, the waste-rock 

displacement area to the east of the Eden pile is potentially feasible for ballasted solar 

development in its current state. The largest flat area of waste-rock totals approximately 

8.2 acres, and the total flat, effective surface available is approximately 11 acres. This 

area is also reasonably close to the point where the mine previously tied into the electric 

utility, as indicated below. 

Figure 8. View of feasible PV area at the VAG Mine site

Source: Image generated using Google Earth
14 

In order to get the most out of the ground area available, it is important to consider 

whether the site layout can be improved to better incorporate a solar system. If and when 

substantial remediation of the site occurs, consideration can be made as to the potential 

future feasibility of a PV system on a larger portion of the site. 

Figure 9 shows an aerial view of the VAG Mine site taken from Google Earth; the total 

potential area feasible for ballasted PV systems is shaded. As shown, there are large 

expanses of relatively flat, un-shaded land that may be suitable for a PV system. In 

addition, the south-facing portions of the Eden and Lowell piles could potentially be used 

for thin-film PV panels integrated into any capping system that may be developed and 

implemented. The area highlighted in orange, as discussed above, is approximately 

11 acres. The area currently consisting of the significant mine structures and facilities is 

approximately 21.5 acres of flat, unshaded land and is highlighted in green. The existing 

buildings would need to be removed prior to any potential development of this area. 

Finally, the area highlighted in purple represents the south-facing slopes of the Eden and 

Lowell piles. It is possible that a cap-integrated thin-film PV system could be integrated 

into any remediation strategy considered for the site. This area totals approximately 

81 acres. In total, the shaded area represents approximately 113 acres. 

Figure 9. Aerial view of the feasible area for PV at the VAG Mine site

Source: Image generated using Google Earth

PV systems are viable in the Eden and Lowell area, where the average global horizontal 

annual solar resource—the total solar radiation for a given location, including direct, 

diffuse, and ground-reflected radiation—is 1,374 kWh/m2

/day. 

Figure 10 shows various views of the VAG Mine site. 
15 

Figure 10. Views of the VAG Mine site. Photos by Joe Simon, NREL

4.2 Utility-Resource Considerations

The expected electrical tie-in point and inverter for the PV system at the VAG Mine site 

is located on the northeast side of the site along Mines Road. When the mine was 

operating, the utility located a dedicated substation at this site to accommodate the 

electricity use. The substation has since been removed, but the distribution infrastructure 

remains, as well as the overhead electrical lines throughout the mine site. The expected 

electrical tie-in point is shown in Figure 11. While the site transmission lines still exist, 

they have been unused for many years and may not be sufficient for a new PV 

installation. The route, however, remains free and could likely be used. The capacity of 

the transmission lines is not known at this time; however, the large energy consumption 

of the prior mine indicates that capacity is likely adequate. This would need to be 

confirmed with the local utility, should the project move forward. Due to the site 

conditions and potential contamination, it is likely that an overhead solution would need 

to be used as trenching would either disturb existing potentially contaminated conditions 

or any potential remediation solution. Depending on the site location, the distance from 

the substation to the solar installation may range from under a quarter mile to over 1 mile.
16 

Figure 11. Electrical tie-in point for the PV system (left) and site distribution (right). Photos 

by Joe Simon, NREL

Figure 12. Electrical tie-in point (A) for the PV system and site distribution 

Source: Image generated using Google Earth

4.3 Useable Acreage for PV System Installation 

Typically, a minimum of 2 useable acres is recommended to site PV systems. Useable 

acreage is typically characterized as "flat to gently sloping" southern exposures that are 

free from obstructions and get full sun for at least a 6-hour period each day. For example, 

eligible space for PV includes underutilized or unoccupied land, vacant lots, and/or 

unused paved area (e.g., a parking lot or industrial site space, as well as existing 

building rooftops). 
17 

4.4 PV Site Solar Resource

The VAG Mine site has been evaluated to determine the adequacy of the solar resource 

available using both on-site data and industry tools. The assessment team for this 

feasibility study collected multiple Solmetric SunEye data points and found a solar access 

of 99% in unshaded areas, such as along the waste-rock deposits highlighted in orange in 

Figure 9 and estimated solar resource of 1,374 kWh/m2

. All data gathered using this tool 

is available in Appendix C.

The predicted array performance was found using PVWatts Version 29 for Eden and 

Lowell, Vermont. Table 2 shows the station identification information, PV system 

specifications, and energy specifications for the site. For this summary array performance 

information, a hypothetical system size of 1 kW was used to show the estimated 

production for each kilowatt so that additional analysis can be performed using the data 

indicated below. It is scaled linearly to match the proposed system size. The cost of 

electricity used was provided by PVWatts and is the estimate of the average for 

the location. 

Table 2. Site Identification Information and Specifications

Station Identification

Cell ID 0270360

State Vermont

Latitude 44.6° N

Longitude 72.56° E 

PV System Specifications

DC Rating 1.00 kW

DC to AC Derate Factor 0.8 

AC Rating 0.8 kW

Array Type Fixed Tilt 

Array Tilt 20° 

Array Azimuth 180°

Energy Specifications

Cost of Electricity $0.163/kWh

Table 3 shows the performance results for a fixed-tilt PV system in Eden and Lowell, 

Vermont, as calculated by PVWatts. 

 

9 For more information on NREL’s PVWatts Version 2 tool, see http://www.nrel.gov/rredc/pvwatts/. 
18 

Table 3. Performance Results for Fixed-Tilt PV

Month Solar Radiation

(kWh/m2/day)

AC Energy

(kWh)

Energy Value

($)

1 3.06 81 13.19

2 4.18 100 16.28

3 5.00 127 20.68

4 4.84 113 18.40

5 5.16 121 19.70

6 5.51 114 18.56

7 5.46 122 19.87

8 5.16 117 19.05

9 4.80 108 17.59

10 3.49 84 13.68

11 2.39 57 9.28

12 2.50 64 10.42

Year 4.27 1,210 197.05

Table 4 shows the performance results for a zero-tilt single-axis tracking PV system in

Eden and Lowell, Vermont, as calculated by PVWatts. 

Table 4. Performance Results for Zero-Degree Single-Axis PV

Month Solar Radiation

(kWh/m2

/day)

AC Energy

(kWh)

Energy Value

($)

1 3.43 92 14.98

2 4.93 119 19.38

3 6.01 155 25.24

4 6.14 146 23.78

5 6.67 159 25.89

6 6.73 151 24.59

7 7.14 165 26.87

8 6.71 156 25.40

9 5.90 135 21.98

10 4.16 102 16.61

11 2.66 64 10.42

12 2.79 72 11.73

Year 5.27 1,516 246.88

4.5 VAG Mine Energy Usage

The VAG Mine site has limited present energy use. One caretaker currently lives just 

outside the main entrance to the site. The remainder of the facility is not used and does 

not have any significant energy use. As remediation has not been determined at this time, 
19 

it is unknown what any potential future energy use will be. It is important to understand 

the energy use of the site to allow for a full analysis of whether or not energy produced 

would need to be sold or if it could offset on-site energy use.

4.5.1 Net Metering

Net metering is an electricity policy for consumers who own renewable energy facilities. 

"Net," in this context, is used to mean "what remains after deductions"—in this case, the 

deduction of any energy outflows from metered energy inflows. Under net metering, a 

system owner receives retail credit for at least a portion of the electricity it generates. As 

part of the Energy Policy Act of 2005, under Sec. 1251, all public electric utilities are 

required upon request to make net metering available to their customers:

(11) NET METERING.—Each electric utility shall make available upon 

request net metering service to any electric consumer that the electric 

utility serves. For purposes of this paragraph, the term ‘net metering 

service’ means service to an electric consumer under which electric energy 

generated by that electric consumer from an eligible on-site generating 

facility and delivered to the local distribution facilities may be used to 

offset electric energy provided by the electric utility to the electric 

consumer during the applicable billing period.10

In 1997, Vermont passed legislation allowing net metering with utilities in the state. This 

law was updated in January 2012 with the passing of bill “H.475 An Act Relating to Net 

Metering and Definitions of Capacity (Act 0125).”11 These bills, however, relate 

primarily to residential-scale systems and are not particularly useful for the VAG Mine 

site. Separately, net metering in Vermont is generally limited to systems up to 250 kW in 

capacity per HB 56 passed in May 2011. 

Renewable energy certificates (RECs),

12 also known as green certificates, green tags, or 

tradable renewable certificates, are tradable commodities in the United States that 

represent proof of electric energy generation from eligible renewable energy resources 

(renewable electricity). The RECs that are associated with the electricity produced and 

are used on site remain with the customer-generator. If, however, the customer chooses to 

receive financial compensation for the net energy gain (NEG) remaining after a 12-month 

period, the utility will be granted the RECs associated with only that surplus 

they purchase. 

Vermont does not currently support a solar renewable energy credit market; however, if 

developed over time, the income associated with the sale of RECs can potentially 

improve the economics of any proposed system. For the purposes of this report, it is 

assumed that no REC market exists.

 

10 Energy Policy Act of 2005: http://www.gpo.gov/fdsys/pkg/PLAW-109publ58/pdf/PLAW109publ58.pdf. 11 H.475 An Act Relating to Net Metering and Definitions of Capacity: 

http://www.leg.state.vt.us/docs/2012/bills/Intro/H-475.pdf. 12 For a description of RECs, see http://apps3.eere.energy.gov/greenpower/markets/certificates.
20 

4.5.2 Virtual Net Metering

Some states and utilities allow for virtual net metering (VNM). Vermont does not 

currently allow VNM, but should this be introduced in the future, it is worthwhile to 

consider. This arrangement can allow certain entities, such as a local government, to 

install renewable generation of up to 1 MW at one location within its geographic 

boundary and to generate credits that can be used to offset charges at one or more other 

locations within the same geographic boundary. 

Each state may determine whether or not local governments, often including cities, 

counties, school districts, special districts, political subdivisions, or other local public 

agencies, are authorized to generate electricity. As the site is not owned by the state or 

local government, this option is likely not feasible. 
21 

5 Economics and Performance

The economic performance of a PV system installed on the site is evaluated using a 

combination of the assumptions and background information discussed previously as well 

as a number of industry-specific inputs determined by other studies. In particular, this 

study uses the NREL System Advisor Model (SAM).13 

SAM is a performance and economic model designed to facilitate decision making for 

people involved in the renewable energy industry, ranging from project managers and 

engineers to incentive program designers, technology developers, and researchers. 

SAM makes performance predictions for grid-connected solar, solar water heating, wind, 

and geothermal power systems and makes economic calculations for both projects that 

buy and sell power at retail rates and power projects that sell power through a PPA. 

SAM consists of a performance model and financial model. The performance model 

calculates a system's energy output on an hourly basis (sub-hourly simulations are 

available for some technologies). The financial model calculates annual project cash 

flows over a period of years for a range of financing structures for residential, 

commercial, and utility projects. 

The model calculates the cost of generating electricity based on information you provide 

about a project's location, installation and operating costs, type of financing, applicable 

tax credits and incentives, and system specifications. 

5.1 Assumptions and Input Data for Analysis

Cost of a PV system depends on the system size and other factors, such as geographic 

location, mounting structure, and type of PV module. Based on significant cost 

reductions seen in 2011, the average cost for utility-scale ground-mounted systems have 

declined from $4.80/W in the first quarter of 2010 to $3.20/W in the fourth quarter of 

2011. With an increasing demand and supply, potential of further cost reduction is 

expected as market conditions evolve. 

NREL recently released the “Residential, Commercial, and Utility-Scale Photovoltaic 

(PV) System Prices in the United States: Current Drivers and Cost-Reduction 

Opportunities” report, which cites the 2011 benchmark price at $2.79/W for utility-scale

ground-mounted fixed-axis systems.

14 

At this time, there is not a developer or a specific plan to install a PV system on site; thus, 

it is uncertain if and when a PV system would be installed. However, for cost estimation 

purposes, system installation was assumed to take place in the first quarter of 2013, and 

as the trends in price reduction have continued, the assumed installed cost for a fixed-tilt 

 

13 For additional information on the NREL System Advisor Model, see https://sam.nrel.gov/cost. 14 Goodrich, A.; James, T.; Woodhouse, M. Residential, Commercial, and Utility-Scale Photovoltaic (PV) 

System Prices in the United States: Current Drivers and Cost-Reduction Opportunities. Technical Report

NREL/TP-6A20-53347. Golden, CO: National Renewable Energy Laboratory, 2012. 

http://www.nrel.gov/docs/fy12osti/53347.pdf. 
22 

ground-mounted system is assumed to be $2.232/W. The installed cost of single-axis

tracking was assumed to be $3.348/W. 

The estimated increase in cost from this baseline for a ballasted system is 25%. This 

increased cost is due to limitations placed on design and construction methods due to the 

ground conditions at the site. Such limitations include restrictions on storm water runoff, 

weight loading of construction equipment, inability to trench for utility lines, additional 

engineering costs, permitting issues, and nonstandard ballasted racking systems. In 

addition, due to the unique considerations with regard to the VAG Mine site and delayed 

remediation activities, a conservative increase of an additional 20% is assumed to 

accommodate additional training, precautions, and installation requirements for any 

system installed prior to any potential remediation. The installed system cost assumptions 

are summarized in Table 5. This increased value for work on a nonremediated site is not 

substantiated for this report and should be carefully considered by any party interested in 

developing a system on this site prior to remediation. The increased labor and 

management costs could be very significant. 

Table 5. Installed System Cost Assumptions

System Type Fixed-Tilt

($/Wp)

Single-Axis Tracking

($/Wp)

Baseline system 2.232 2.67

With ballast 0.558 0.678

Total installed cost 

(postremediation)

2.79 3.348

Total with increased cost 

for work preremediation

3.348 4.017

These prices include the PV array and the BOS components for each system, including 

the inverter and electrical equipment, as well as the installation cost. This includes 

estimated taxes and a national-average labor rate but does not include land cost. The 

economics of grid-tied PV depend on incentives, the cost of electricity, the solar resource, 

and panel tilt and orientation. 

It was assumed for this analysis that relevant federal incentives are received. It is 

important to consider all applicable incentives or grants to make PV as cost-effective as 

possible. Assuming the PV system is owned by a private tax-paying entity, this entity 

may qualify for federal tax credits and accelerated depreciation on the PV system, which 

can be worth about 15% of the initial capital investment. The total potential tax benefits 

to the tax-paying entity can be as high as 45% of the initial system cost. 

For the purposes of this analysis, the project is expected to have a 25-year life, although 

the systems can be reasonably expected to continue operation past this point. Inflation is 

assumed to be 1.5%, the real discount rate to be 6%, and the financing secured via a 25-

year loan at a 7% interest rate and 55% debt fraction. 
23 

The panels are assumed to have a 0.5% per year degradation in performance. The O&M 

expenses are estimated to be $20/kW/yr for the life of the system for a fixed-tilt system 

and $22/kW/yr for a single-axis tracking system. Similar to installation costs, the O&M 

would be likely be higher if the system was installed on the site prior to remediation. A 

dual-axis tracking system was not considered for this analysis due to potential concerns 

associated with grading, differential settlement, and increased labor costs due to higher 

expected maintenance and existing site contamination. A system DC-to-AC conversion 

of 80% was assumed. This includes losses in the inverter, wire losses, PV module losses, 

and losses due to temperature effects. PVWatts Version 2 was used to calculate expected

energy performance for the system. 

5.2 Proposed PV Systems Analyzed

For the purposes of this analysis, three separate scenarios were analyzed. 

5.2.1 Scenario 1

The first scenario assumes that installation of a ballasted system could be completed on 

the current site, prior to remediation, atop the cap-rock areas indicated in orange in 

Figure 8 of this report. Due to the existing level of nature, clear solar access, potentially 

limited ground contamination, and close proximity to electrical distribution lines, this 

area is considered most likely to support an installation prior to any potential overall site 

remediation. 

The economic feasibility of a potential PV system on the VAG Mine site depends greatly 

on the purchase price of the electricity produced. The state of Vermont currently supports 

the Vermont Sustainably Priced Energy Development (SPEED) standard offer for 

systems up to 2.2 MW in size of $0.27/kWh. Both a fixed-axis and a single-axis PV 

system of 2.2 MW would sufficiently fill the currently clear cap-rock area on the site and, 

consequently, are analyzed for viability. This standard offer is the levelized cost of 

energy (LCOE) and will not increase over the life of the system. 

5.2.2 Scenario 2

The second scenario considered evaluates the potential of using both the cap-rock area as 

well as the flat entry and structure area, which is indicated in green in Figure 9. This area 

totals 33 acres, and this scenario assumes that work is completed postremediation, so the 

increased construction cost associated with the potential ground contamination is not 

used. For the analysis of a larger system, the average negotiated rate for systems within 

the SPEED program of $0.13/kWh was used. 

5.2.3 Scenario 3

Finally, a scenario was considered for the installation of a cap-integrated thin-film PV on 

the south-facing slopes of the Eden and Lowell piles. This system could be developed in 

addition to either of the previously summarized scenarios. As this installation would be 

done following a potential remediation, the increased construction cost associated with 

working on a potentially contaminated site is not used. This system would also realize the 

average negotiated rate of $0.13/kWh. 
24 

5.3 SAM-Forecasted Economic Performance

Using the inputs and assumptions summarized in Section 5 of this report, the SAM tool 

predicts the internal rate of return (IRR) and the LCOE for the three scenarios. In each 

scenario, a break-even point was not considered because this depends on the required 

IRR, which is different for every investor and hard to estimate. A project that requires an 

IRR of 7% will have a much different break-even point than one with a different cost of 

capital or a different IRR. The examples in Sections 5.3.1, 5.3.2, and 5.3.3 are indicative 

of the overall performance of the system, as an investment. In general, an IRR around 

12% is considered satisfactory for this type of project; however, due to the unremediated 

nature of the site, other concerns relating to construction, and SPEED funding, it is likely 

that an investor would require a significantly higher IRR for this particular project. 

5.3.1 Scenario 1

For a 2.2-MW fixed-tilt system designed to take full advantage of the Vermont SPEED 

standard offer on the waste-rock area, the system could yield an after-tax NPV of 

$2,189,995 on first-year annual revenue, beginning at $777,486/yr. 

The fixed-tilt system would be expected to produce approximately 2.9 MWh annually, 

which is enough to offset approximately 260 households’ annual energy use. The

complete results and summary of inputs for SAM are available in Appendix E. At current 

packing factors of 4–5 acres/MW of peak DC power, a 2.2-MW system would fully 

utilize the area available on the waste-rock while simultaneously taking full advantage of 

the existing SPEED system. The after-tax IRR of this system would be about 24%. This 

assumes a 20% premium for construction on contaminated lands. If this premium were to 

increase, the IRR would decrease accordingly. 

A comparative single-axis tracking system would yield an after-tax NPV of $3,012,237 

on first-year annual revenue of $970,033/yr. The after-tax IRR is estimated at 26%. 

While this is higher, it is important to note that complications associated with installing a 

tracking system on the existing land may incur atypical costs. Any differential settlement 

would also negatively impact the performance of the system and increase maintenance 

costs on the site. 

A summary of the results of the economic analysis and the system considered is available 

in Appendix E. 

5.3.2 Scenario 2

The second scenario considers wherein the entire currently flat area potentially feasible 

for PV was used following, or as part of, a potential remediation strategy. This area totals 

32 acres and considers a 4.6-MW system for both a fixed-axis and single-axis tracking 

array. Both would result in a negative NPV and low IRR. Given the current available 

negotiable rate through the Vermont SPEED standard offer program as well as the 

amount of work required to prepare this land for a solar installation, this option is not 

recommended at this time. 
25 

5.3.3 Scenario 3

The third scenario considers wherein a cap-integrated thin-film PV system would be 

installed on all of the south-facing slopes of the Eden and Lowell piles as part of a 

remediation plan. This would total approximately 81 acres and, at the energy density 

factor indicated in Table 1, would represent approximately an 11.64-MW system. This 

system would also utilize the $0.13/kWh negotiated purchase price for electricity 

generated and utilizes an estimated installed cost of $2.79/W. This system would also 

realize a negative NPV and low IRR. Due to the low current NPV forecast, lack of 

resources to develop and implement a long-term remedy for the Eden and Lowell piles, 

and potential complications of installing thin-film solar on the steep slopes of the piles, 

this solution is not recommended at this time.

Table 6. PV System Summary

5.4 Job Analysis and Impact

To evaluate the employment and economic impacts of the PV project associated with this 

analysis, the NREL Jobs and Economic Development Impact (JEDI) models are used.15

The JEDI models are tools that estimate the economic impacts associated with the 

construction and operation of distributed generation power plants. JEDI is a flexible 

input-output tool that estimates, but does not precisely predict, the number of jobs and 

economic impacts that can be reasonably supported by the proposed facility. 

The JEDI models represent the entire economy, including cross-industry or crosscompany impacts. For example, JEDI estimates the impact that the installation of a 

distributed-generation facility would have on not only the manufacturers of PV modules 

and inverters but also on the associated construction materials, metal fabrication industry, 

 

15 The JEDI models have been used by the U.S. Department of Energy, the U.S. Department of Agriculture, 

NREL, and the Lawrence Berkeley National Laboratory, as well as a number of universities. For 

information on the NREL Jobs and Economic Development Impact tool, see 

http://www.nrel.gov/analysis/jedi/about_jedi.html. 

System Type

Financial 

Model PV System Sizea Array Tilt Array Size Annual Output

Number of 

Houses Poweredb

Construction 

Period Jobsc

Jobs 

Sustainedd

(kW) (deg) (acres) (kWh/year)

Crystalline Silicon (Fixed Tilt) PPA 2,200 LAT 9.9 2,879,581 260.8 70.3 0.7

Crystalline Silicon (Single-axis Tracking) PPA 2,200 n/a 11 3,592,714 325.4 * *

Crystalline Silicon (Fixed Tilt) PPA 4,600 n/a 20.7 8,386,334 759.6 * *

Crystalline Silicon (Single-axis Tracking) PPA 4,600 LAT 23 10,462,389 947.7 * *

Thin-film (Integrated into cap) PPA 11,600 n/a 81 16,456,059 1490.6 * *

System Type

Financial 

Model Annual Output PPA Pricee System Cost

Total System 

Cost 1ST Year Revenue After-tax NPV After-tax IRR

(kWh/year) (¢/kWh) ($/watt) ($/year) %

Crystalline Silicon (Fixed Tilt) PPA 2,879,581 27 $ 3.34 $ 7,402,062 $ 777,486 $ 2,189,995.00 24.08

Crystalline Silicon (Single-axis Tracking) PPA 3,592,714 27 $ 4.02 $ 8,843,860 $ 970,033 $ 3,012,237.96 26.11

Crystalline Silicon (Fixed Tilt) PPA 8,386,344 13 $ 2.77 $ 17,728,946 $ 1,090,224 $ (913,636.00) 3.46

Crystalline Silicon (Single-axis Tracking) PPA 10,462,389 13 $ 3.34 $ 21,338,936 $ 1,360,110 $ (490,451.00) 5.28

Thin-film (Integrated into cap) PPA 16,456,059 13 $ 2.79 $ 32,363,629 $ 2,139,287 $ (510,574.00) 5.74

a Array size determined by available acerage for each scenario. 2.2 MW used for the first scenario to take adavantage of SPEED standard offer. 

b Number of average American households that could hypothetically be powered by the PV system assuming 11,040 kWh/year/household.

c Job-years created as a result of project capital investment including direct, indirect, and induced jobs.

d Jobs (direct, indirect, and induced) sustained as a result of operations and maintenance (O&M) of the system.

e Assumes a fixed PPA rate. Inflation assumed to be 1.5%/year.

* JEDI analysis was not completed for these systems

U.S. Energy Information Administration. http://www.eia.doe.gov/ask/electricity_faqs.asp#electricity_use_home. Accessed November 2, 2010.
26 

project management support, transportation, and other industries that are required to 

enable the procurement and installation of the complete system. 

For this analysis, inputs, including the estimated installed project cost ($/kW), targeted 

year of construction, system capacity (kW), O&M costs ($/kW), and location, were 

entered into the model to predict the jobs and economic impact. It is important to note 

that the JEDI model does not predict or incorporate any displacement of related economic 

activity or alternative jobs due to the implementation of the proposed project. As such, 

the JEDI model results are considered gross estimates as opposed to net estimates. This 

analysis uses the proposed 2.2-MW fixed-tilt system as this is seen as the most 

economically and practically realizable system at this time. 

For the VAG Mine site, the values in Table 7 were assumed. 

Table 7. JEDI Analysis Assumptions

Input Assumed Value

Capacity 2,200 kW

Placed In Service Year 2013

Installed System Cost $7,402,062

Location Eden and Lowell, 

Vermont

Using these inputs, the JEDI tool estimates the gross direct, indirect, and induced jobs, 

associated earnings, and total economic impact supported by the construction and 

continued operation of the proposed PV system. 

The estimates of jobs associated with this project are presented as either construction 

period jobs or sustained operations jobs. Each job is expressed as a whole or fraction fulltime equivalent (FTE) position. An FTE is defined as one person working 40 hrs/week 

for the duration of a year. Construction period jobs are considered short-term positions 

that exist only during the procurement and construction periods. 

As indicated in the results of the JEDI model analysis provided in Appendix D, the total 

proposed system is estimated to support 70 direct, indirect, and induced jobs per year for 

the duration of the procurement and construction period. Total wages paid to workers 

during the construction period are estimated to be $2,928,000, and total economic output 

is estimated to be $7,505,000. The annual O&M of the new PV system is estimated to 

support 0.7 FTEs per year for the life of the system. The jobs and associated spending are 

projected to account for approximately $34,600 in earnings and $57,400 in economic 

activity each year for the next 25 years. 

5.5 Financing Opportunities

The procurement, development, construction, and management of a successful utilityscale distributed-generation facility can be owned and financed a number of different 

ways. The most common ownership and financing structures are described below. 
27 

5.5.1 Owner and Operator Financing

The owner/operator financing structure is characterized by a single entity with the 

financial strength to fund all of the solar project costs and, if a private entity, sufficient 

tax appetite to utilize all of the project’s tax benefits. Private owners/operators typically 

establish a special purpose entity (SPE) that solely owns the assets of the project. An 

initial equity investment into the SPE is funded by the private entity using existing funds, 

and all of the project’s cash flows and tax benefits are utilized by the entity. This equity 

investment is typically matched with debt financing for the majority of the project costs. 

Project debt is typically issued as a loan based on the assets and equity of the 

owners/operators for the project. In addition, private entities can utilize any of federal tax 

credits offered. 

Although not applicable to this site, given that it is privately owned, public entities that 

choose to finance, own, and operate a solar project can raise funding as part of a larger, 

general obligation bond; as a standalone tax credit bond; through a tax-exempt lease 

structure, bank financing, grant and incentive programs, or internal cash; or some 

combination of the above. Certain structures are more common than others, and grant 

programs for solar programs are on the decline. Regardless, as tax-exempt entities, public 

entities are unable to benefit directly from the various tax-credit-based incentives 

available to private companies. This has given way to the now common use of third-party 

financing structures, such as the PPA. 

5.5.2 Third-Party Developers with Power Purchase Agreements

Because many project site hosts do have the financial or technical capabilities to develop 

a capital intensive project, many times they turn to third-party developers (and/or their 

investors). In exchange for access to a site through a lease or easement arrangement, 

third-party developers will finance, develop, own, and operate solar projects utilizing 

their own expertise and sources of tax equity financing and debt capital. Once the system 

is installed, the third-party developer will sell the electricity to the site host or local utility 

via a PPA—a contract to sell electricity at a negotiated rate over a fixed period of time. 

The PPA typically will be between the third-party developer and the site host if it is a

retail “behind-the-meter” transaction or directly with an electric utility if it is a wholesale 

transaction. 

Site hosts benefit by either receiving competitively priced electricity from the project via 

the PPA or land lease revenues for making the site available to the solar developer via a 

lease payment. This lease payment can take on the form of either a revenue-sharing 

agreement or an annual lease payment. In addition, third-party developers are able to 

utilize federal tax credits. For public entities, this arrangement allows them to utilize the 

benefits of the tax credits (low PPA price, higher lease payment) while not directly 

receiving them. The term of a PPA typically varies from 20–25 years.

5.5.3 Third-Party “Flip” Agreements

The most common use of this model is a site host working with a third-party developer 

who then partners with a tax-motivated investor in a SPE that would own and operate the 

project. Initially, most of the equity provided to the SPE would come from the tax 

investor and most of the benefit would flow to the tax investor (as much as 99%). When 
28 

the tax investor has fully monetized the tax benefits and achieved an agreed-upon rate of 

return, the allocation of benefits and majority ownership (95%) would “flip” to the site 

host (but not within the first 5 years). After the flip, the site host would have the option to 

buy out all or most of the tax investor’s interest in the project at the fair market value of 

the tax investor’s remaining interest. 

A flip agreement can also be signed between a developer and investors within an SPE, 

where the investor would begin with the majority ownership. Eventually, the ownership 

would flip to the developer once each investor’s return is met.

5.5.4 Hybrid Financial Structures

As the solar market evolves, hybrid financial solutions have been developed in certain 

instances to finance solar projects. A particular structure, nicknamed “The Morris Model” 

after Morris County, New Jersey, combines highly rated public debt, a capital lease, and a 

PPA. Low-interest public debt replaces more costly financing available to the solar 

developer and contributes to a very attractive PPA price for the site host. New markets 

tax credits have been combined with PPAs and public debt in other locations, such as 

Denver and Salt Lake City. 

5.5.5 Solar Services Agreement and Operating Lease

The solar services agreement (SSA) and operating lease business models have been 

predominately used in the municipal and cooperative utility markets due its treatment of 

tax benefits and the rules limiting federal tax benefit transfers from nonprofit to for-profit 

companies. Under IRS guidelines, municipalities cannot enter capital leases with forprofit entities when the for-profit entities capture tax incentives. As a result, a number of 

business models have emerged as a workaround to this issue. One model is the solar 

services agreement, wherein a private party sells “solar services” (i.e., energy and RECs) 

to a municipality over a specified contract period (typically long enough for the private 

party to accrue the tax credits). The nonprofit utility typically purchases the solar services 

with either a one-time, up-front payment equal to the turn-key system cost minus the 30% 

federal tax credit or purchases the services in annual installments. The municipality may 

buy out the system once the third party has accrued the tax credits, but due to IRS 

regulations, the buyout of the plant cannot be included as part of the SSA (i.e., the SSA 

cannot be used as a vehicle for a sale and must be a separate transaction).

Similar to the SSA, there are a variety of lease options that are available to municipalities 

that allow the capture of tax benefits by third-party owners, which result in a lower cost 

to the municipality. These include an operating lease for solar services (as opposed to an 

equipment capital lease) and a complex business model called a “sale/leaseback.” Under 

the sale/leaseback model, the municipality develops the project and sells it to a thirdparty tax equity investor who then leases the project back to the municipality under an 

operating lease. At the end of the lease period and after the tax benefits have been 

absorbed by the tax equity investor, the municipality may purchase the solar project at 

fair market value.
29 

5.5.6 Sale/Leaseback

In the widely accepted sale/leaseback model, the public or private entity would install the 

PV system, sell it to a tax investor, and then lease it back. As the lessee, they would be 

responsible for operating and maintaining the solar system as well as have the right to sell 

or use the power. In exchange for use of the solar system, the public or private entity 

would make lease payments to the tax investor (the lessor). The tax investor would have 

rights to federal tax benefits generated by the project and the lease payments. Sometimes, 

the entity is allowed to buy back the project at 100% fair market value after the tax 

benefits are exhausted. 

5.5.7 Community Solar Gardens/Solar 

The concept of “community solar” is one in which the costs and benefits of one large 

solar project are shared by a number of participants. A site owner may be able to make 

the land available for a large solar project, which can be the basis for a community solar 

project. Ownership structures for these projects vary, but the large projects are typically 

owned or sponsored by a local utility. Community solar gardens are distributed solar 

projects wherein utility customers have a stake via a prorated share of the project’s 

energy output. This business model is targeted to meet demand for solar projects by 

customers who rent/lease homes or business, do not have good solar access at their site, 

or do not want to install a solar system on their facilities. Customer prorated shares of 

solar projects are acquired through a long-term transferrable lease of one or more panels, 

or they subscribe to a share of the project in terms of a specific level of energy output or 

the energy output of a set amount of capacity. Under the customer lease option, the 

customer receives a billing credit for the number of kilowatt-hours their prorated share of 

the solar project produces each month; it is also known as VNM. Under the customer 

subscription option, the customers typically pay a set price for a block of solar energy 

(i.e., 100 kWh/month blocks) from the community solar project. Other models include 

monthly energy outputs from a specific investment dollar amount or a specific number 

of panels. 

Community solar garden and customer subscription-based projects can be solely owned 

by the utility, solely owned by third-party developers with facilitation of billing provided 

by the utility, or be a joint venture between the utility and a third-party developer leading 

to eventual ownership by the utility after the tax benefits have been absorbed by the thirdparty developer. 

There are some states that offer solar incentives for community solar projects, including 

Washington state (production incentive) and Utah (state income tax credit). Community 

solar is also known as solar gardens depending on the location (e.g., Colorado). 
30 

6 Conclusions and Recommendations 

The site locations considered for a solar PV system in this report have various qualities 

that make them feasible areas in which to implement solar PV systems. Following 

analysis of three site scenarios, including installing a 2.2-MW system on the cap-rock 

areas of the site, installing a 4.6-MW system on all existing flat and unshaded areas of the 

site, and installing thin-film geomembrane cap system on the Eden and Lowell piles as 

part of a remediation strategy, it was determined that only the first is economically viable 

at this time. Installing a PV system on flat waste-rock land at the site could generate 

approximately 2,879,581 kWh annually and represent a significant distributed generation 

facility for the area. Additionally, reusing land that cannot be used for other purposes 

would minimize the environmental impact of the currently abandoned mine site. 

As summarized in Section 5, the economic analysis completed using SAM predicts an 

IRR and LCOE of 24.08% and $0.2332/kWh, respectively. A 2.2-MW fixed-tilt system 

installed at the site would have an after-tax NPV of $2,189,995 and represents a good 

value for the site. This option is seen as having the most likely feasible installation and 

maintenance strategy given the current conditions of the site and current expectations for 

potential future remediation. 

It should be noted that this analysis assumes that the current potential level of 

contamination on the proposed cap-rock land area can be mitigated through various 

construction and safety solutions combined with a ballasted PV system for an 

approximate increased cost of 20% over national averages for ballasted systems. If the 

premium were to be greater than a 20%, the NPV and after-tax IRR would decrease 

accordingly. 

It is recommended that the interested site parties move forward with additional 

investigation as to whether or not it is possible to install a system on the waste-rock area 

of the VAG Mine site given current ground contamination conditions. If feasible, a 

request for proposals should be developed to determine whether or not a developer may 

be interested in undertaking this project. This work should be done soon to take 

advantage of the current Vermont SPEED standard offer program. As appropriate, the 

site should work to submit an application to Vermont SPEED for consideration as part of 

the 2013 site selection process. When reviewing proposals for a PV system to be installed 

at this site, evaluation criteria should include the annual output (kWh/yr) as well as price 

per kilowatt-hour. Careful consideration will also need to be made as to the safety of the 

construction workers installing the PV system on the site prior to remediation strategies.

A design-build contract can enable vendors to optimize system configuration, including 

slope and tracking requirements or a specific system design can be required of 

the vendor. 

For multiple reasons—the high cost of energy, the dropping cost of PV, and the existence 

of a reasonable solar resource—this report finds that a PV system is a reasonable use for 

the site when partnered with the Vermont SPEED standard offer. 
31 

Appendix A. Provided Site Information

Several studies and evaluations of the VAG mine site located on Belvidere Mountain in 

Eden, Vermont, and Lowell, Vermont, have been conducted and provide extensive and 

valuable information regarding the history, current condition, and potential remediation 

strategies being considered. The following is a brief summary of some of the resources 

used in the development of this report. 

• EPA Waste Site Cleanup & Reuse in New England/VAG Mine Site

http://www.epa.gov/region1/removal-sites/VAGMineSite.html 

• University of Vermont, Department of Geology Summary of Mine Site 

Mineralogy

http://www.uvm.edu/~gdrusche/Mineralogy%20of%20VAG%20mine%20waste_

VGS%20talk.pdf

• State of Vermont Waste Management Division Vermont Asbestos Group Mine 

http://www.anr.state.vt.us/dec/wastediv/sms/VAG.htm

• Program Case for Pursuing Superfund Listing of the VAG Mine 

http://www.anr.state.vt.us/dec/wastediv/sms/VAG/0423.final.caseforsuperfund.fig

ures.appendicies.pdf

• Rejecting Superfund Status Puts End To Asbestos Cleanup, Vermont Public 

Radio News

http://www.vpr.net/news_detail/93698/rejecting-superfund-status-puts-end-toasbestos-cl/
32 

Appendix B. Assessment and Calculations 

Assumptions

Table B-1. Cost, System, and Other Assessment Assumptions

Cost Assumptions

Variable Quantity of Variable Unit of Variable

Cost of Site Electricity N/A $/kWh

Annual O&M (fixed)

Annual O&M (single)

20

22

$/kW/year

$/kW/year

Other Assumptions

1 acre 43,560 ft2

1 MW 1,000,000 W

Ground utilization 90% of available 

area
33 

Appendix C. Solar Access Measurements 

Figure C-1. Solar access measurements for the VAG Mine PV site
34 

Appendix D. Results of the JEDI Model

Table D-1. PV Data Summary

Photovoltaic—Project Data Summary Based on Model Default Values

Project Location Vermont

Year of Construction or Installation 2013

Average System Size—DC Nameplate 

Capacity (kW) 2,200

Number of Systems Installed 1 

Total Project Size—DC Nameplate 

Capacity (kW) 2,200

System Application Large Commercial

Solar Cell/Module Material Crystalline Silicon

System Tracking Fixed Mount

Base Installed System Cost ($/kWDC) $3,340

Annual Direct Operations and 

Maintenance Cost ($/kW) $20.00

Money Value—Current or Constant 

(Dollar Year) 2013

Project Construction or Installation Cost $7,348,000

Local Spending $4,394,694

Total Annual Operational Expenses $896,368

Direct Operating and Maintenance Costs $44,000

Local Spending $40,480

Other Annual Costs $852,368

Local Spending $0

Debt Payments $0

Property Taxes $0

Local Economic Impacts—Summary Results

Jobs Earnings Output

During construction and installation 

period $000 (2013) $000 (2013)

Project Development and On-Site Labor 

Impacts

Construction and Installation Labor 10.8 $697.20 

Construction and Installation-Related 

Services 16.8 $634.60 

Subtotal 27.6 $1,331.80 $2,415.50 
35 

Module and Supply Chain Impacts

Manufacturing 0.0 $0.00 $0.0

Trade (Wholesale and Retail) 6.6 $336.50 $994.20 

Finance, Insurance, and Real Estate 0.0 $0.00 $0.00 

Professional Services 5.0 $176.10 $592.20 

Other Services 4.8 $326.40 $1,092.60 

Other Sectors 10.3 $232.50 $628.70 

Subtotal 26.7 $1,071.50 $3,307.80 

Induced Impacts 16.1 $525.50 $1,781.80 

Total Impacts 70.3 $2,928.80 $7,505.00 

Annual Annual

Annual Earnings Output

During operating years Jobs $000 (2013) $000 (2013)

On-Site Labor Impacts

PV Project Labor Only 0.4 $24.50 $24.50 

Local Revenue and Supply Chain 

Impacts 0.1 $6.70 $21.30 

Induced Impacts 0.1 $3.40 $11.60 

Total Impacts 0.7 $34.60 $57.40 

Notes: Earnings and output values are thousands of dollars in year 2013 dollars. Construction and operating period jobs are full-time 

equivalent for one year (1 FTE = 2,080 hours). Economic impacts "during operating years" represent impacts that occur from 

system/plant operations/expenditures. Totals may not add up due to independent rounding.

Detailed PV Project Data Costs

Purchased Manufactured

Installation Costs Cost Locally (%) Locally (Y or N)

Materials and Equipment

Mounting (rails, clamps, fittings, etc.) $320,910 100% N 

Modules $2,664,735 100% N 

Electrical (wire, connectors, breakers, 

etc.) $225,035 100% N 

Inverter $480,952 100% N 

Subtotal $3,691,633

Labor

Installation $697,204 100%

Subtotal $697,204

Subtotal $4,388,837

Other Costs

Permitting $795,600 100%
36 

Other Costs $324,735 100%

Business Overhead $1,838,829 100%

Subtotal $2,959,163

Subtotal $7,348,000

Sales Tax (Materials and Equipment 

Purchases) $0 100%

Total $7,348,000

PV System Annual Operating and 

Maintenance Costs Cost Local Share

Labor

Technicians $26,400 100%

Subtotal $26,400

Materials and Services

Materials and Equipment $17,600 100%

Services $0 100%

Subtotal $17,600

Sales Tax (Materials and Equipment 

Purchases) $0 100%

Average Annual Payment (Interest and 

Principal) $852,368 0%

Property Taxes $0 100%

Total $896,368

Other Parameters

Financial Parameters

Debt Financing

Percentage Financed 80% 0%

Years Financed (Term) 10

Interest Rate 10%

Tax Parameters

Local Property Tax (Percent of Taxable 

Value) 0%

Assessed Value (Percent of Construction 

Cost) 0%

Taxable Value (Percent of Assessed 

Value) 0%

Taxable Value $0

Property Tax Exemption (Percent of 

Local Taxes) 0%
37 

Local Property Taxes $0 100%

Local Sales Tax Rate 6.00% 100%

Sales Tax Exemption (percent of local 

taxes) 100.00%

Payroll Parameters

Wage per 

hour

Employer Payroll 

Overhead

Construction and Installation Labor

Construction Workers/Installers $21.39 45.6%

O&M Labor

Technicians $21.39 45.6%
38 

Appendix E. Results of the System Advisor Model

Table E-1. SAM Results

2.2 MW FixedAxis System2.2 MW SingleAxis System6.4 MW Fixed-Axis 

System

6.4 MW SingleAxis System11.6 MW ThinFilm System

Metric Base Base Base Base Base

Net Annual Energy 2,879,581 kWh 3,592,714 kWh 8,386,344 kWh 10,462,389 kWh 16,456,059 kWh

PPA price 27.00 ¢/kWh 27.00 ¢/kWh 13.00 ¢/kWh 13.00 ¢/kWh 13.00 ¢/kWh

LCOE Nominal 27.00 ¢/kWh 27.00 ¢/kWh 13.00 ¢/kWh 13.00 ¢/kWh 13.00 ¢/kWh

LCOE Real 23.32 ¢/kWh 23.32 ¢/kWh 11.23 ¢/kWh 11.23 ¢/kWh 11.23 ¢/kWh

After-tax IRR 24.08% 26.11% 3.46% 5.28% 5.74%

Pre-tax min DSCR 1.37 1.46 0.69 0.74 0.76

After-tax NPV $2,189,995.03 $3,012,237.96 ($913,636.00) ($490,451.10) ($510,574.14)

PPA price escalation 0.00% 0.00% 0.00% 0.00% 0.00%

Debt Fraction 55.00% 55.00% 55.00% 55.00% 55.00%

Capacity Factor 15.00% 18.70% 15.00% 18.70% 16.10%

First year kWhac/kWdc 1,310 1,635 1,310 1,635 1,414

System Performance Factor 0.88 0.89 0.88 0.89 0.95