Feasibility Study of Economics 

and Performance of Solar 

Photovoltaics at the Atlas 

Industrial Park in Duluth, 

Minnesota 

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 

Matthew Steen, Lars Lisell, and Gail Mosey 

Produced under direction of the Environmental Protection Agency 

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

Interagency Agreement IAG-08-0719 and Task No. WFD3.1002. 

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. 

Technical Report 

NREL/TP-7A40-56772 

January 2013 

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 Atlas 

Industrial Park in Duluth, 

Minnesota 

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 

Matthew Steen, Lars Lisell, and Gail Mosey 

Prepared under Task No. WFD3.1002 

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. 

Technical Report 

NREL/TP-7A40-56772 

January 2013 

Contract No. DE-AC36-08GO28308 
 

 

 

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. 
 

 

 

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 Heidi Timm-Bijold, Pakou Ly, and Mayor 

Don Ness of the City of Duluth for all of their help setting up site visits and meetings and for the 

time they spent supporting this project. The team would also like to thank Gary Schafer, Rosita 

Clarke, Shea Jones, Lura Matthews, and Jessica Trice of EPA and Katie Brown, AAAS Science 

& Technology Policy fellow hosted by the U.S. EPA, for supporting the study. Additionally, the 

team would like to thank Carol Andrews of Barr Engineering and Bill Sawyer of Minnesota 

Power for their generous assistance and cooperation. 

iii 
 

 

 

List of Acronyms 

AC alternating current 

a-Si amorphous silicon 

BOS balance of system 

CBI capacity-based incentive 

CREB clean renewable energy bond 

DC direct current 

DEDA Duluth Economic Development Authority 

EPA U.S. Environmental Protection Agency 

FTE full-time equivalent 

JEDI Jobs and Economic Development Impact 

kW kilowatt 

kWh kilowatt-hour 

kV kilovolt 

LCOE levelized cost of energy 

MP Minnesota Power 

M-RETS Midwest Renewable Energy Tracking System 

MW megawatt 

MWh megawatt-hour 

NREL National Renewable Energy Laboratory 

O&M operations and maintenance 

PAH polyaromatic hydrocarbons 

PBI production-based incentive 

PCB polychlorinated biphenyls 

PPA power purchase agreement 

PV photovoltaic 

QCEB qualified conservation energy bond 

REC renewable energy certificate 

RES renewable energy standard 

SAM System Advisor Model 

SPE special purpose entity 

SSA Solar Services Agreement 

UAC Universal Atlas Cement Company 

VNM virtual net metering 

W watt 

iv 
 

 

 

 

 

 

 

 

Executive Summary 

The U.S. Environmental Protection Agency (EPA) Region 5, in accordance with the REPowering America’s Land initiative, selected the Atlas Industrial Park in Duluth, Minnesota, for 

a feasibility study of renewable energy production. Under the RE-Powering America’s Land 

initiative, the EPA provided funding to the National Renewable Energy Laboratory (NREL) to 

support a feasibility study of solar renewable energy generation at the Atlas Industrial Park. 

NREL provided technical assistance for this project but did not assess environmental conditions 

at the site beyond those related to the performance of a photovoltaic (PV) system. The purpose of 

this study is to assess the site for a possible PV installation and estimate the cost, performance, 

and site impacts of different PV configurations. In addition, the study evaluates financing options 

that could assist in the implementation of a PV system at the site. 

The feasibility of a PV project depends greatly on both site-specific and economic factors. Sitespecific factors include the available area for an array, 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 sites impact the feasibility of a PV 

system. Economic factors include purchase price of the electricity produced, power purchase 

agreement (PPA) price, and retail electric rates along with federal, state, and utility incentives for 

PV systems. 

The Atlas Industrial Park is a 62-acre brownfield site currently undergoing remediation and 

redevelopment. The Duluth Economic Development Authority (DEDA), which owns the 

property, is considering a 2-acre parcel for a PV installation as part of its redevelopment plan. 

Based on an assessment of the site conditions, the Atlas Industrial Park is suitable for 

deployment of a large- or small-scale PV system; however, the economics specific to the area 

currently limit the financial viability of a PV installation. Table ES-1 summarizes the 

performance and economics of the different PV systems and the development/financing options 

evaluated in this study. The table shows the annual energy output, the levelized cost of energy 

(LCOE), and the PPA price along with the payback period and cost of each system. 

v 
 

 

 

Table ES-1. Atlas Industrial Park PV System Summary 

PV System Type System Scale System Sizea Array Tilt Annual Output 

Number of Houses 

Poweredb 

(kW) (deg) (kWh/year) 

Crystalline Silicon (Fixed Tilt) Commercial 348 20.0 423,073 38 

Crystalline Silicon (Fixed Tilt) Residential 10 20.0 12,157 1.1 

Crystalline Silicon (Fixed Tilt) Residential 8 20.0 9,726 0.9 

Development Scenario System Scale - Size System Cost LCOE Real LCOE Nominal Payback Period 

($/kWh) ($/kWh) or PPA Price 

DEDA Purchase Commercial - 348 kW $ 2,014,920 0.34 0.44 >25 years 

Private Purchase Commercial - 348 kW $ 2,014,920 0.15 0.19 >25 years 

Private Purchase with PPA Commercial - 348 kW $ 2,014,920 0.31 0.40 $0.31/kWh 

DEDA Purchase Residential - 8 kW $ 58,880 0.30 0.39 >25 years 

Private Purchase Residential - 10 kW $ 73,600 0.13 0.16 >25 years 

a Data assume a maximum usable area of 2 acres. 

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

As indicated in Table ES-1, each system configuration is expected to have an LCOE 

significantly greater than $0.05/kWh, the average commercial electricity rate in Duluth. These 

results include the current cost of energy, expected installation cost, site solar resource, and 

existing incentives for a PV system. The economic feasibility of a PV installation at the Atlas 

Industrial Park is primarily limited by lower-than-average electricity rates but also by available 

incentives that are based on system capacity and have a relatively low cap of $20,000. The 

current incentive structure favors smaller residential-scale systems reflected in a lower LCOE; 

however, the feasibility of these systems is constrained by higher module costs resulting from 

reduced economies of scale. The most cost-competitive scenario is for a privately owned system 

without a PPA. This scenario represents a PV configuration designed to offset on-site energy use, 

whereas the purpose of a PPA is to sell energy to another entity. 

If DEDA wishes to further pursue a PV installation at the Atlas Industrial Park, development 

options different from the ones evaluated in this study should be explored. A public-private 

partnership between DEDA and Minnesota Power, an energy services company, or a 

current/future site developer to create a demonstration project could be one way to successfully 

implement a PV project at the site. The results of this study indicate that a privately owned 

residential-scale PV installation, such as a rooftop system for future site-occupying businesses, is 

currently the lowest-cost option for the Atlas Industrial Park; however, further increases in 

electric rates combined with decreases in module costs and changes to incentive structures could 

make a PV system at the site cost-competitive in the future. 

vi 
Table of Contents 

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

2 Development of a PV System on Brownfields ...................................................................................3
 

3 PV Systems............................................................................................................................................5
 

3.1 PV Overview .................................................................................................................................... 5
 

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

3.2.1 PV Module ..........................................................................................................................6
 

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

3.2.3 Balance-of-System Components .........................................................................................9
 

3.2.4 Operation and Maintenance...............................................................................................11
 

3.3 Siting Considerations .....................................................................................................................11
 

4 Proposed Installation Location Information ....................................................................................12
 

4.1 Atlas Industrial Park PV System....................................................................................................12
 

4.2 Utility-Resource Considerations ....................................................................................................17
 

4.3 PV Site Solar Resource ..................................................................................................................18
 

4.4 Atlas Industrial Park Energy Usage ...............................................................................................18
 

4.4.1 Net Metering .....................................................................................................................18
 

4.4.2 Virtual Net Metering .........................................................................................................19
 

5 Economics and Performance ............................................................................................................20
 

5.1 Assumptions and Input Data for Analysis......................................................................................20
 

5.2 SAM Forecasted Economic Performance ......................................................................................23
 

5.3 Job Analysis and Impact.................................................................................................................26
 

5.4 Financing Opportunities.................................................................................................................27
 

5.4.1 Owner and Operator Financing .........................................................................................27
 

5.4.2 Third-Party Developers with Power Purchase Agreements ..............................................28
 

5.4.3 Third-Party “Flip” Agreements.........................................................................................28
 

5.4.4 Hybrid Financial Structures...............................................................................................28
 

5.4.5 Solar Services Agreement and Operating Lease ...............................................................29
 

5.4.6 Sale/Leaseback..................................................................................................................29
 

5.4.7 Community Solar Gardens/Solar.......................................................................................29
 

6 Conclusions and Recommendations................................................................................................31
 

Appendix A. Solar Access Measurements..............................................................................................33
 

Appendix B. Results from PVWatts.........................................................................................................34
 

Appendix C. Results of the SAM Analysis..............................................................................................37
 

Appendix D. Results of the JEDI Model ..................................................................................................39
 

vii 
 

 

 

 

 

 

 

 

 

List of Figures 

Figure 1. Generation of electricity from a PV cell...........................................................................5
 

Figure 2. Ground-mounted array diagram .......................................................................................6
 

Figure 3. Mono- and multi-crystalline solar panels.........................................................................7
 

Figure 4. Thin-film solar panels installed on a solar energy cover (left) and fixed-tilt 

mounting system (middle/right).................................................................................................7
 

Figure 5. String inverter...................................................................................................................9
 

Figure 6. Aerial view of the feasible area for PV at the Atlas Industrial Park ..............................13
 

Figure 7. Aerial view of the 2-acre silo site for PV at the Atlas Industrial Park ...........................14
 

Figure 8. Northwest view of the Atlas Industrial Park ..................................................................15
 

Figure 9. East view of the Atlas Industrial Park ............................................................................15
 

Figure 10. Southeast view of the Atlas Industrial Park .................................................................16
 

Figure 11. West view (near silo site) of the Atlas Industrial Park.................................................16
 

Figure 12. Potential electrical tie-in point for the PV system at the Atlas Industrial Park
 

showing the IKONICS building and meter in the background................................................17
 

Figure 13. Solar market insight Q1 2012 national weighted average system prices .....................21
 

Figure 14. Optimal system size for a DEDA-purchased residential-scale system ........................25
 

Figure 15. Optimal system size for a privately purchased residential-scale system......................25
 

Figure A-1. Solar access measurements for the Atlas Industrial Park PV site ..............................33
 

Figure C-1. Module cost versus real levelized cost of energy for grid parity ...............................38
 

List of Tables 

Table ES-1. Atlas Industrial Park PV System Summary............................................................... vi
 

Table 1. Energy Density by Panel and System..............................................................................10
 

Table 2. Performance Results for 1-kW PV Systems in Duluth, Minnesota.................................18
 

Table 3. Installed Fixed-Tilt System Cost Assumptions ...............................................................21
 

Table 4. Minnesota Power’s 2012 SolarSense Program Incentive Levels ....................................22
 

Table 5. SAM Inputs and Assumptions .........................................................................................23
 

Table 6. Atlas Industrial Park PV System Summary.....................................................................24
 

Table 7. Predicted Real Module Cost for Grid Parity ($0.05/kWh) ..............................................26
 

Table 8. JEDI Analysis Assumptions ............................................................................................26
 

Table 9. JEDI Summary Results....................................................................................................27
 

Table 10. Predicted Real Levelized Cost of Energy Using a Performance-Based Incentive 

in Duluth ..................................................................................................................................31
 

Table B-1. PVWatts Inputs............................................................................................................34
 

Table B-2. Performance Results for a 20-Degree Tilt System ......................................................34
 

Table B-3. Performance Results for a Tilt = Latitude (46.8°) Fixed-Tilt System .........................35
 

Table B-4. Performance Results for Zero-Degree Single-Axis System ........................................35
 

Table B-5. Performance Results for Zero-Degree Double-Axis System.......................................36
 

Table C-1. DEDA Purchase Scenario............................................................................................37
 

Table C-2. Third-Party Purchase Without PPA.............................................................................37
 

Table C-3. Commercial-Scale PPA Scenario ................................................................................38
 

Table D-1. JEDI Results, Residential-Scale System .....................................................................39
 

Table D-2. JEDI Results, Commercial-Scale System....................................................................42
 

viii 
 

 

 

 

 

 

 

 

 

 

1 Study and Site Background 

The U.S. Environmental Protection Agency (EPA) Region 5, in accordance with the REPowering America’s Land initiative, selected the Atlas Industrial Park in Duluth, 

Minnesota, for a feasibility study of renewable energy production. Under the REPowering America’s Land initiative, the EPA provided funding to the National 

Renewable Energy Laboratory (NREL) to support a feasibility study of solar renewable 

energy generation at the Atlas Industrial Park. NREL provided technical assistance for 

this project but did not assess environmental conditions at the site beyond those related to 

the performance of a photovoltaic (PV) system. The purpose of this study is to assess the 

site for a possible PV installation and estimate the cost, performance, and site impacts of 

different PV configurations. In addition, the study evaluates financing options that could 

assist in the implementation of a PV system at the site. 

The feasibility of a PV project depends greatly on both site-specific and economic 

factors. Site-specific factors include the available area for an array, 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 

sites impact the feasibility of a PV system. Economic factors include purchase price of 

the electricity produced, power purchase agreement (PPA) price, and retail electric rates 

along with federal, state, and utility incentives for PV systems. 

The Atlas Industrial Park is approximately 62 acres and is located at the corner of 

Commonwealth and Grand Avenues along the St. Louis River corridor in southern 

Duluth. The City of Duluth has a population of 86,2651

 and is served by the investorowned utility Minnesota Power (MP). MP is required to follow the state’s renewable 

energy standard (RES), which mandates that 25% of retail electricity sales come from 

renewable sources by 2025. The utility currently offers capacity-based incentives (CBI) 

up to $20,000 for solar electric systems through its SolarSense program. In 2012 the 

budget for the SolarSense program was $300,000 with all funds committed by June 4. 

The Atlas Industrial Park was part of a local industrial manufacturing hub along the St. 

Louis River and was operated by the Universal Atlas Cement Company (UAC), which 

produced Portland cement from 1915 to the mid-1970s. UAC, a subsidiary of U.S. Steel 

Corporation, used slag by-products from the nearby Duluth Works steel plant as a raw 

material in the manufacturing process. The Duluth Works plant was also closed in the 

1970s and is now a state and federal Superfund site covering approximately 500 acres. 

Following closure of the UAC plant, many of the structures were demolished and the 

debris spread across the site, which created fill depths up to 13 feet. This resulted in 

unstable soils and contamination, including high pH soils, polyaromatic hydrocarbons 

(PAH), polychlorinated biphenyls (PCB), metals (arsenic and lead), and likely presence 

of asbestos and petroleum. 

The Atlas Industrial Park is a state brownfield owned by the Duluth Economic 

Development Authority (DEDA), which acquired the land from UAC following its 

closure. The land is zoned General Industrial and the southwestern 11 acres have been 

1 U.S. Census Quickfacts. Accessed August 2012: http://quickfacts.census.gov/qfd/states/27/2717000.html. 

1 
 

remediated and redeveloped into a warehouse and manufacturing facility for the 

IKONICS Corporation, an imaging technology company headquartered in Duluth. DEDA 

plans to develop the southeastern corner of the site to provide IKONICS with a 4-acre 

expansion and create a 5-acre model site. The remaining 42 acres are undergoing 

remediation and redevelopment, including road, stormwater, sewer, and electric 

infrastructure, which are anticipated to be completed in December 2012. The 

revitalization of the Saint Louis River Corridor is a key part of the city’s communitysupported comprehensive plan,

2 and DEDA believes that a solar project at the Atlas site 

would contribute to the growth of the area. 

Feasibility assessment team members from NREL, DEDA, and the EPA conducted a site 

visit on April 17, 2012, to gather information integral to this feasibility study. The team 

considered information, including solar resource, transmission availability, community 

acceptance, and ground conditions. The site has un-shaded open areas, is generally flat, 

has electric infrastructure in place, and is close to transmission and distribution lines, 

making it a potential candidate for a PV installation. 

2 2006 City of Duluth Comprehensive Plan. Accessed September 2012: 

http://www.duluthmn.gov/planning/comp_plan/index.cfm. 

2 
 

 

 

 

 

 

2 Development of a PV System on Brownfields 

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

benefits for siting solar PV facilities on brownfields, noting that they: 

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

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

residential redevelopment and may be adequately zoned for renewable energy 

•	 Generally are located near existing roads and energy transmission or distribution 

infrastructure 

•	 May provide an economically viable reuse for sites that may 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—in many cases, generating significant revenue on a site that would otherwise go 

unused. For many brownfields, the local community has 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. 

Although brownfields can potentially present unique challenges for installing PV 

systems, in many ways brownfields can be ideal locations for renewable energy projects 

offering a productive use of unproductive land. PV systems have been successfully 

installed on a variety of brownfields in many parts of the country. For example, in 

Chicago, Illinois, a 41-acre site within the West Pullman industrial redevelopment area 

was used to install a 10-MW PV system in 2010. The project was the result of a 

partnership between the City of Chicago and the Excelon Corporation, a local utility that 

developed the site that had been home to numerous manufacturing facilities since 

the 1800s.3 

The Atlas Industrial Park 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. Some 

examples of other functions for the site include: 

•	 Renewable-energy-powered remediation 

•	 Business park with sustainable site features 

•	 Habitat restoration/open space. 

3 See http://www.exeloncorp.com/assets/energy/powerplants/docs/pdf_ExelonCitySolarFact.pdf for a 

description of the project. 

3 
 

 

 

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 PPAs linked to renewable energy systems. 

•	 Generating energy without harmful emissions or waste products can be
 

accomplished through renewable energy sources.
 

4 
 

 

 

 

 

 

 

-

- -

-

-

- - -

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., in a light bulb). 

(-) 

Solar cell 

Figure 1. 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. 

(+) 

Electron 

Load 

Current flow 

5 
 

 

 

3.2 Major System Components
 

Figure 2. Ground-mounted array diagram 

Source: NREL 

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

• PV modules 

• Inverter 

• Balance-of-system (BOS) components. 

These, along with other PV system components, are discussed below. 

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. Silicon is quite 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 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 25–30-year range 

but can keep producing energy beyond this range. 

6 
 

 

 

 

 

 

 

 

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 is controlled by raw material selection and 

manufacturing technique. Crystalline silicon panels are widely used based on 

deployments worldwide. 

Figure 3 shows two examples of crystalline solar panels: mono- and multi-silicon 

installed on tracking mounting systems. 

Source: SunPower, NREL PIX 23816 Source: NREL PIX 13823 

Figure 3. Mono- and multi-crystalline solar panels 

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 the unique nature of thin films, 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 fixed-tilt or, in some cases, tracking system 

configurations. 

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

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

Figure 4 shows thin-film solar panels. 

Source: Republic Services, NREL PIX 23817 Source: NREL PIX 14726 Source: NREL PIX 17395 

Figure 4. Thin-film solar panels installed on a solar energy cover (left) and fixed-tilt 

mounting system (middle/right) 

7 
 

 

 

 

 

 

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%. 

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 1.5–1,000 kW. These 

inverters tend to be cheaper on a capacity basis, as well as 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 are typically 10 years, and extended warranties up to 20 years are possible for 

larger units. 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. Instead, it impacts only that shaded panel if micro-inverters 

are used. Figure 5 shows a string inverter. 

8 
 

 

 

 

 

Figure 5. String inverter 

Source: NREL PIX 07985 

3.2.3 Balance-of-System Components 

In addition to the modules and inverter, a 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 brownfields, 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 and have lower maintenance costs 

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

However, energy density is often greater for fixed-tilt systems, which require less area 

per module and are less prone to “self-shading” than tracking systems, although selfshading does increase with panel-tilt for fixed-tilt systems requiring additional spacing 

between rows. 

9 
 

 

Table 1. Energy Density by Panel and System 

Fixed-Tilt Energy Single-Axis Tracking Energy System Type Density (DC-Watts/ft2

) Density (DC-Watts/ft2) 

Crystalline Silicon 4.0 3.3 

Thin Film 3.3 2.7 

Hybrid High Efficiency 4.8 3.9 

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, in which PV is rotated on a single axis, can increase energy 

output by 25% or more. With dual-axis tracking, the module is able to directly face the 

sun all day, potentially increasing energy output by 35% or more. Depending on 

underlying soiling 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. 

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 

brownfield applications, this wiring may be required to run through above-ground 

conduit due to restrictions with ground 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. 

10 
 

 

 

 

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 PV systems and not unique to landfill 

applications. 

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 may also use this 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 smart phone 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), would be 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 $30/kW/yr for the first 15 years and $20/kW/yr for the 

remaining 10 years, which is based on the historical O&M costs of installed fixed-axis 

grid-tied PV systems. The system should expect a replacement of system inverters in 

year 15 at a cost of $0.25/W, which has been amortized over the first 15 years of 

operation. 

3.3 Siting Considerations 

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

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 all 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 determination that the site is adequate for a solar 

installation, an analysis to determine the ideal system size must be conducted. System 

size depends highly on the average energy use of the facilities on the site, PPAs, available 

incentives, and utility policy. 

11 
 

 

4 Proposed Installation Location Information 

This section summarizes the findings of the NREL solar assessment site visit at the Atlas 

Industrial Park on April 17, 2012. 

4.1 Atlas Industrial Park PV System 

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 PV system. If there are 

structures, fences, vegetation, or electrical poles that can be removed, the un-shaded area 

can be increased to incorporate more PV panels. From the information collected during 

the site visit, the team concluded that 80% of the entire site could accommodate a PV 

system and the remaining 20% would be unusable due to roads, topography, vegetation, 

or other restrictions. 

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 under-utilized or unoccupied land, vacant lots, and/or 

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

building rooftops. 

Figure 6 shows an aerial view of the Atlas Industrial Park taken from Google Earth 

showing the total feasible area (highlighted in orange) and electrical tie-in point for a PV 

system. As shown, there are large expanses of relatively flat, un-shaded land, which 

makes it a suitable candidate for a PV system. The total area of the site that appears 

feasible for PV is 23.3 acres (1,016,969 ft2

), which could support a 4-MW fixed-tilt 

system or a 3.3-MW single-axis tracking system. 

12 
 

 

 

Figure 6. Aerial view of the feasible area for PV at the Atlas Industrial Park 

Illustration made in Google Earth 

Based on current development plans it is unlikely that the entire site will be utilized for a 

PV system. Instead, a smaller 2-acre parcel, which was formerly the location of the Atlas 

Cement silos, is being considered. This site is shown in Figure 7 and could support a 348­

kW fixed-tilt or 287-kW single-axis tracking PV system. The difference in system size is 

due to the need for additional space to prevent self-shading between modules with 

tracking systems, which also becomes more pronounced at higher tilt angles for fixed-tilt 

systems. In addition, if the existing vegetation could be removed along Commonwealth 

Avenue, the available acreage and visibility could be increased. 

13 
 

 

 

 

Figure 7. Aerial view of the 2-acre silo site for PV at the Atlas Industrial Park 

Illustration made in Google Earth 

PV systems are suitable for Duluth, Minnesota, where the average global horizontal 

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

diffuse, and ground-reflected radiation—is 4.33 kWh/m2/day. For comparison, Seattle, 

Washington, receives 3.67 kWh/m2

/day and Tucson, Arizona, receives 

6.13 kWh/m2

/day.4 Figures 8–11 show various views of the Atlas Industrial Park site 

taken during the site visit. 

4 PVWatts Viewer. Accessed August 2012: http://gisatnrel.nrel.gov/PVWatts_Viewer/index.html. 

14 
 

 

Figure 8. Northwest view of the Atlas Industrial Park 

Photo by Lars Lisell, NREL 

Figure 9. East view of the Atlas Industrial Park 

Photo by Lars Lisell, NREL 

15 
 

 

Figure 10. Southeast view of the Atlas Industrial Park 

Photo by Lars Lisell, NREL 

Figure 11. West view (near silo site) of the Atlas Industrial Park 

Photo by Lars Lisell, NREL 

16 
 

 

 

 

4.2 Utility-Resource Considerations 

When considering a ground-mounted system, an electrical tie-in location should be 

identified to determine how it would be connected to the grid or on-site facilities. The 

existing infrastructure at the Atlas Industrial Park is well suited for installation of a PV 

system. The expected electrical tie-in and inverter location for the PV system at the Atlas 

Industrial Park is located at the MP electrical box east of the IKONICS building along the 

road into the site. The proposed additional electric infrastructure might also be used as an 

alternative tie-in and inverter location and could add flexibility to the location of a PV 

system. Additionally, there are transmission and distribution lines crossing the southern 

portion of the property that could carry surplus electricity off-site. The electrical tie-in 

point was not evaluated specifically for compatibility with a PV system and for the 

purposes of this analysis the site was assumed to need no additional infrastructure. Before 

moving forward with a solar project, however, a grid integration study should be 

performed in order to determine definitively whether or not additional infrastructure will 

be needed to accommodate a PV system. The expected electrical tie-in point is shown in 

Figure 12. 

Figure 12. Potential electrical tie-in point for the PV system at the Atlas Industrial Park 

showing the IKONICS building and meter in the background 

Photo by Lars Lisell, NREL 

17 
 

 

 

 

 

 

 

 

 

4.3 PV Site Solar Resource 

The Atlas Industrial Park 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 an 

annual solar access of 95% and estimated solar resource of 4.19 kWh/m2

/day. The data 

gathered using this tool is available in Appendix A. 

The predicted array performance was found using PVWatts Version 25 for Duluth, 

Minnesota. For this summary array performance information, a hypothetical system size 

of 1 kW was used to show the estimated production for each kilowatt. It is scaled linearly 

so that additional analyses can be performed to match the proposed system size. Table 2 

shows the annual performance results of four different system configurations in Duluth, 

Minnesota, as calculated by PVWatts. The monthly results for each system type are 

available in Appendix B. 

Table 2. Performance Results for 1-kW PV Systems in Duluth, Minnesota 

System Type AC Energy 

(kWh/yr) 

Increase from 

Fixed 20° Tilt 

Fixed Tilt, 20° Tilt 1,216 0% 

Fixed Tilt, 46.8° Tilt (latitude) 1,271 4.5% 

Single-Axis Tracking 1,427 17.3% 

Double-Axis Tracking 1,714 41.0% 

4.4 Atlas Industrial Park Energy Usage 

Understanding the energy use of a site will enable a full analysis of whether or not energy 

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

Atlas Industrial Park does not have any energy-consuming infrastructure in place. 

However, a PV system could be used to offset adjacent facilities, such as the IKONICS 

building, or on-site energy use from future development. 

4.4.1 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 customers6

: 

5 NREL: Renewable Resource Data Center – PVWatts. Accessed September 2012: 

http://www.nrel.gov/rredc/pvwatts/. 6 Energy Policy Act of 2005, Title XII—Electricity, Subtitle E—Amendments to PURPA, Section 1251— 

Net Metering and Additional Standards. Accessed January 9, 2013: http://www.gpo.gov/fdsys/pkg/PLAW109publ58/pdf/PLAW-109publ58.pdf. 

18 
 

 

 

 

 

 

 

 

(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. 

Minnesota’s net-metering law,

7

 which took effect in 1983, requires utilities to offer net 

metering to all customers with solar and wind-energy systems up to 40 kW. 

Renewable energy certificates (RECs), 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 electricity generation remaining after a 12­

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

purchase. Minnesota currently participates in the Midwest Renewable Energy Tracking 

System (M-RETS), which uses production data from participating generators to create 

RECs in the form of digital tradable certificates for each megawatt-hour.8 

4.4.2 Virtual Net Metering 

Some states and utilities allow for virtual net metering (VNM), often referred to as 

community solar or solar gardens. This arrangement can allow certain entities, such as a 

local government, to install renewable generation 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. Currently neither MP nor the State of 

Minnesota offer VNM. 

7 For the full text of this bill, see 

http://www.dsireusa.org/incentives/incentive.cfm?Incentive_Code=MN01R&re=0&ee=0. 8 Midwest Renewable Energy Tracking System. Accessed August 2012: www.mrets.net. 

19 
 

 

 

 

 

 

 

 

5 Economics and Performance 

The economics and performance of a PV system installed on the site was 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 used the NREL System Advisor Model (SAM).9 

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. 

SAM makes performance predictions for grid-connected solar, small wind, and 

geothermal power systems and economic estimates for distributed energy and central 

generation 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 recent years, the average cost for utility-scale ground-mounted systems 

have declined from $4.80/W in the first quarter (Q1) of 2010 to $2.90/W in Q1 2012. 

Costs for smaller commercial and residential-scale systems have also declined steadily to 

$4.63/W and $5.89/W, respectively. The lower cost of utility-scale systems reflects 

increased economies of scale, which allows fixed costs to be spread over a larger project 

budget. With an increasing demand and supply, the potential for further cost reduction is 

expected as market conditions evolve. Figure 13 shows the cost per watt of PV systems 

from 2010 to 2012 for residential, commercial (non-residential), and utility-scale 

installations. 

9 For additional information on SAM, see https://sam.nrel.gov/cost. 

20 
 

 

 

 

 

 

Figure 13. Solar market insight Q1 2012 national weighted average system prices10 

Credit: Solar Energy Industries Association 

For this analysis, the installed cost of fixed-tilt ground-mounted commercial- and 

residential-scale systems was assumed to be $5.79/W and $7.36/W, respectively. The 

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

the ground conditions at the site and is estimated to be 25% for a ballasted system. 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 non-standard ballasted racking systems. The installed system cost 

assumptions for commercial- and residential-scale systems are summarized in Table 3. 

Table 3. Installed Fixed-Tilt System Cost Assumptions 

System Size Commercial 

($/W) 

Residential 

($/W) 

Baseline system 4.63 5.89 

With ballast 1.16 1.47 

Total installed cost 5.79 7.36 

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, 

10 Data and figure from the Solar Energy Industries Association, SEIA/GTM Research U.S. Solar Market 

Insight Report 2012 Q1. Accessed August 2012: http://www.seia.org/research-resources/solar-marketinsight-report-2012-q1. 

21 
 

 

 

 

 

 

 

 

and panel tilt and orientation. For this analysis, the cost of electricity was assumed to be 

$0.05/kWh, an average of MP’s commercial rates.

11 

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. If 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 taxpaying entity can be as high as 45% of the initial system cost. Because state and federal 

governments do not pay taxes, private ownership of the PV system would be required to 

capture tax incentives. 

MP’s current solar electric incentive program, SolarSense, uses a CBI structure with a 

cap of $20,000. The program budget for 2012 has been fully committed and the utility is 

currently evaluating the results for next year’s program. Due to the uncertainty of next 

year’s incentive structure, this analysis limited the incentive to the base level. Table 4 

shows the incentive levels for the SolarSense program. 

Table 4. Minnesota Power’s 2012 SolarSense Program Incentive Levels 

Incentive Level ($/kW) 

Base incentive 2,000 

Non-profit/tax exempt owner 500 

Minnesota-made modules 1,000 

NABCEP certified installers 250 

For the purposes of this analysis, three development scenarios were considered for 

installing a PV system at the site: 

1. DEDA purchase 

2. Private purchase and use 

3. Private development with a PPA. 

For each scenario the project is expected to have a 25-year life, although the systems can 

be reasonably expected to continue operation past this point. The panels are assumed to 

have a 0.5% per year degradation in performance. A system DC-to-AC conversion of 

80% was assumed, which includes losses in the inverter, wire losses, PV module losses, 

and losses due to temperature effects. Inflation is assumed to be 2.5%, and the loan rate is 

assumed to be 6% for each scenario. The O&M expenses are estimated to be 

$30/kW/year during the first 15 years and then $20/kW/year for years 16–25. A fixed 

20°-tilt system was used as a baseline for evaluating the economics of PV at the site. The 

exact system design is beyond the scope of this study and will depend on additional sitespecific analysis and input from stakeholders. The assumptions and inputs for each 

scenario are included in Table 5 with the differences highlighted. 

11 Minnesota Power commercial rates. Accessed August 2012: 

http://www.mnpower.com/customer_service/your_bill/documents/Final_4961a.pdf. 

22 
 

 

 

 

 

Table 5. SAM Inputs and Assumptions 

Parameter DEDA Purchase Private Purchase/PPA 

Analysis period (years) 25 25 

Inflation 2.50% 2.50% 

Real discount rate 3.00% 5.85% 

Federal tax rate 0 35.00% 

State tax rate 0 9.80% 

Insurance (% of installed cost) 0.50% 0.50% 

Property tax 0.00% 0.00% 

Construction loan 0.00% 0.00% 

Loan term (years) 25 15 

Loan rate 6.00% 6.00% 

Debt fraction 100.00% 50.00% 

Minimum IRR n/a n/a / 15.00% 

PPA escalation rate n/a n/a / 1.50% 

Federal depreciation n/a Custom 5-year MACRSa 

State depreciation n/a n/a 

Federal ITC n/a 30.00% 

Capacity-based incentive $2.50/kW $2.00/kW 

Degradation 0.50% 0.50% 

Operational availability 100.00% 100.00% 

Cost - fixed axis per kW $5.79 $5.79 

Grid interconnection cost 0 0 

O&M $30/kW/yr for years 1-15 & $20/kW/yr for years 16-25 

DC-AC derate factor 80.00% 80.00% 

Tilt 20° 20° 

a Modified Accelerated Cost Recovery System 

The PVWatts calculation engine within SAM was used to calculate expected energy 

performance for the system based on system size, configuration, and solar resource. 

System size was calculated from the available land area; this analysis was restricted to the 

2-acre silo site and determined to be 348 kW for a fixed-tilt system and 287 kW for a 

single-axis tracking system. Additionally, this study evaluated smaller residential-scale 

systems, which are favored by the current incentive structure from MP. 

5.2 SAM Forecasted Economic Performance 

Using the inputs and assumptions summarized above, the SAM tool predicts the levelized 

cost of energy (LCOE), payback period, and PPA price for a PV system at the Atlas 

Industrial Park. Table 6 summarizes the results of the economic analysis for the system 

configurations and development scenarios considered in this study. The entire results are 

available in Appendix C. 

23 
 

 

 

 

 

 

 

Table 6. Atlas Industrial Park PV System Summary 

PV System Type System Scale System Sizea Array Tilt Annual Output 

Number of Houses 

Poweredb 

(kW) (deg) (kWh/year) 

Crystalline Silicon (Fixed Tilt) Commercial 348 20.0 423,073 38 

Crystalline Silicon (Fixed Tilt) Residential 10 20.0 12,157 1.1 

Crystalline Silicon (Fixed Tilt) Residential 8 20.0 9,726 0.9 

Development Scenario System Scale - Size System Cost LCOE Real LCOE Nominal Payback Period 

($/kWh) ($/kWh) or PPA Price 

DEDA Purchase Commercial - 348 kW $ 2,014,920 0.34 0.44 >25 years 

Private Purchase Commercial - 348 kW $ 2,014,920 0.15 0.19 >25 years 

Private Purchase with PPA Commercial - 348 kW $ 2,014,920 0.31 0.40 $0.31/kWh 

DEDA Purchase Residential - 8 kW $ 58,880 0.30 0.39 >25 years 

Private Purchase Residential - 10 kW $ 73,600 0.13 0.16 >25 years 

a Data assume a maximum usable area of 2 acres. 

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

In each case the results indicate that the LCOE and PPA price would be significantly 

higher than the retail commercial rate of $0.05/kWh. Although the current CBI and 

incentive cap favor smaller residential-scale systems, the increased cost per watt 

compared to larger commercial-scale systems also limits the economic feasibility of these 

systems. 

Figures 14 and 15 show the optimal size for a residential-scale PV system based on 

current base-level CBIs. The inputs and assumptions were kept the same as the 

commercial-scale system; however, the module cost was increased to $7.36/W, reflecting 

current market data for residential systems. Again, the LCOE for each scenario was 

found to be significantly higher than the current retail commercial electricity rate. The 

optimal system size is 8 kW for the DEDA purchase scenario and 10 kW for the private 

purchase scenario. In each case, adding CBIs would decrease the optimal system size by 

reaching the incentive cap with a smaller system. 

24 
 

LCOE (¢/kWh) LCOE (¢/kWh) 

0 

5 

10 

15 

20 

25 

30 

35 

40 

45 

50 

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 

Nameplate Capacity (kW) 

DEDA Purchase 

LCOE Real 

LCOE Nominal 

Figure 14. Optimal system size for a DEDA-purchased residential-scale system 

0 

5 

10 

15 

20 

25 

30 

35 

40 

45 

50 

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 

Nameplate Capacity (kW) 

Private Purchase 

LCOE Real 

LCOE Nominal 

Figure 15. Optimal system size for a privately purchased residential-scale system 

Due to the uncertainty of future incentives and high LCOE for PV in Duluth, this study 

evaluated grid-parity—the point at which PV might become cost-competitive with gridpurchased electricity. Table 7 summarizes the result of the grid-parity analysis showing 

the module cost at which the real LCOE (without incentives) becomes cost-competitive 

with the current price of electricity. The results indicate that significant decreases in 

module costs would be necessary to compete with grid-purchased electricity. Grid 

parity could occur in Duluth as module costs continue to decline and incentives for PV 

evolve in the coming years. The entire results of this analysis are available in 

Appendix C. 

25 
 

 

 

 

 

Table 7. Predicted Real Module Cost for Grid Parity ($0.05/kWh) 

Module Cost ($/kW) 

DEDA Purchase 0.60 

Private Purchase 1.10 

Private PPA 0.40 

5.3 Job Analysis and Impact 

To evaluate the impact on employment and economic impacts of the PV project 

associated with this analysis, the NREL Jobs and Economic Development Impact (JEDI) 

model was used.

12 The JEDI models are tools that estimate the economic impacts 

associated with the construction and operation of distributed generation power plants. It 

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 the associated construction materials, metal fabrication industry, 

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. 

Table 8 shows the assumed values for the Atlas Industrial Park. 

Table 8. JEDI Analysis Assumptions 

Assumed Value Assumed Value Input Residential Commercial 

Capacity 9 kW 348 kW 

Year Placed In Service 2013 2013 

Installed System Cost $7.36/W $5.79/W 

Location Duluth, MN Duluth, MN 

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. 

12 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 JEDI tool, see http://www.nrel.gov/analysis/jedi/about_jedi.html. 

26 
 

 

 

 

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, 

full-time equivalent (FTE) position. An FTE is defined as one person working 40 hours 

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

positions that exist only during the procurement and construction periods. Table 9 

summarizes the results from the JEDI model analysis. The full results are provided in 

Appendix D. 

Table 9. JEDI Summary Results 

Residential System Commercial System 

Jobs during construction 0.7 18.9 

Wages paid to workers $13,600 $935,500 

Economic output during construction $24,100 $2,326,000 

Jobs during operating years 0.0 0.1 

Earnings per year $200 $7,700 

Economic output per year $300 $13,500 

5.4 Financing Opportunities 

The procurement, development, construction, and management of a successful distributed 

generation facility can be owned and financed a number of different ways. The most 

common ownership and financing structures are described below. 

5.4.1 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 owners’/operators’ assets and 

equity in the project. In addition, private entities can utilize any of federal tax credits 

offered. 

For public entities that choose to finance, own, and operate a solar project, funding can be 

raised 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. Federal qualified energy conservation 

bonds (QECBs)13 can also be used to finance renewable energy as well as energy 

efficiency projects. Certain structures are more common than others and grant programs 

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

13 Department of Energy, Solution Center: Qualified Energy Conservation Bonds. Accessed January 10, 

2013: http://www1.eere.energy.gov/wip/solutioncenter/financialproducts/qecb.html. 

27 
 

 

 

 

 

 

 

 

 

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. 

5.4.2 Third-Party Developers with Power Purchase Agreements 

Because many project site hosts do not 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 PPAs typically varies from 20–25 years. 

5.4.3 Third-Party “Flip” Agreements 

The most common use of a third-party “flip” agreement is a site host working with a 

third-party developer who then partners with a tax-motivated investor in an 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 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 investors’ 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 the investors’ return is met. 

5.4.4 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 hosts. New markets 

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

Denver and Salt Lake City. 

28 
 

 

 

 

 

 

 

 

 

 

 

5.4.5 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 to its treatment 

of tax benefits and the rules limiting federal tax benefit transfers from non-profit to forprofit companies. Under IRS guidelines, municipalities cannot enter capital leases with 

for-profit entities when the for-profit entities capture tax incentives. As a result, a number 

of business models have emerged as a work-around to this issue. One model is the SSA, 

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 non-profit utility typically purchases the solar services with either a onetime up-front payment equal to the turn-key system cost minus the 30% federal tax credit 

or may purchase the services in annual installments. The municipality may buy out the 

system once the third-party has accrued the tax credits, but because of 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.” 

5.4.6 Sale/Leaseback 

In the sale/leaseback model, the public or private entity installs the PV system, sells it to 

a tax investor, and then leases it back. As the lessee, they are responsible for operating 

and maintaining the PV system as well as have the right to sell or use the power. In 

exchange for use of the PV 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. 

5.4.7 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 pro-rated 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 businesses, do not have good solar access at their site, 

or do not want to install a PV system on their facilities. Customer pro-rated 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 pro-rated 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 

29 
 

 

(i.e., 100 kWh per 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 owned solely 

by the utility, owned solely 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 known as solar gardens depending on the location (e.g., Colorado). Solar gardens 

are not currently offered in Minnesota, but if approved by the Minnesota public utility 

commission could be an effective way to make the Atlas site a sustainable office park. 

30 
 

 

 

 

 

 

 

6 Conclusions and Recommendations 

From a technical standpoint, the Atlas Industrial Park is a suitable area in which to 

implement a PV project with an adequate land area and solar resource. However, the 

existing economics specific to Duluth currently limit the feasibility of a PV system there. 

As summarized in Section 5, the economic analysis completed using SAM predicts an 

LCOE significantly higher than the current retail rate, which is approximately half the 

national average.

14 Additionally, MP’s current incentive structure favors smaller systems 

by using a capacity-based approach with a relatively low incentive cap. Based on current 

economics, the most cost-competitive scenario is a privately owned residential-scale 

system used to offset on-site energy use, with larger systems also predicted to have lower 

LCOEs than either the DEDA purchase or PPA scenarios. 

Future changes to electric rates, module costs, and incentives may make PV in Duluth 

cost-competitive with grid-purchased electricity. Continued increases in electric rates 

combined with decreases in module costs will reduce the gap between grid-purchased 

electricity and distributed generation. In addition, changes to MP’s current incentive 

structure or the addition of incentives from the state could further reduce the LCOE of 

PV systems in the future if, for example, a performance-based incentive (PBI) was 

offered. The structure of PBIs typically produces cash flows for the project on an annual 

basis rather than a one-time payment during the construction year, as is the case with 

CBIs. For comparison, Massachusetts, many parts of which have a solar resource similar 

to Duluth, offers a PBI of $0.55/kWh.15 If a similar incentive was available in Duluth, 

either from the state or utility, the LCOE for PV systems would become more 

competitive with retail electric rates. Table 10 shows the predicted economics for PV 

systems in Duluth using PBIs from Massachusetts. 

Table 10. Predicted Real Levelized Cost of Energy Using a Performance-Based Incentive in 

Duluth 

Real Payback Period Debt 

Development Scenario System Scale – Size LCOE or PPA price Fraction 

($/kWh) 

DEDA Purchase Commercial - 348 kW 0.098 9.8 years 100% 

Private Purchase Commercial - 348 kW 0.028 6.6 years 10% 

Private Purchase with PPA Commercial - 348 kW 0.018 $0.021/kWh 40% 

DEDA Purchase Residential - 8 kW 0.186 >25 years 100% 

Private Purchase Residential - 10 kW 0.022 8.6 years 50% 

14 In 2011 the average retail electricity price for commercial customers was $0.103/kWh.
 

Energy Information Administration, Factors Affecting Electricity Prices. Accessed August 2012:
 

www.eia.gov/energyexplained/index.cfm?page=electricity_factors_affecting_prices. 15 For a complete description of incentives available in Massachusetts, see 

http://www.dsireusa.org/incentives/index.cfm?re=0&ee=0&spv=0&st=0&srp=1&state=MA. 

31 
 

 

 

 

 

 

Although the existing economics currently limit the feasibility of PV in Duluth, financing 

options separate from the ones considered in this study may provide DEDA with a viable 

means to implement a PV system at the Atlas Industrial Park. Future site developers may 

in fact be able to install a small or large PV system at a price comparable to retail electric 

rates with a creative financial model and changes to existing economics. Additionally, 

DEDA may be able to facilitate the development of a standalone system using alternative 

financing. For example, a public-private partnership with MP, an energy services 

company, or current/future site developers to create a solar demonstration project could 

be a beneficial arrangement to all stakeholders. By leasing the land for a nominal fee, 

DEDA could provide a developer with a highly visible site to build a large commercialscale ground-mounted PV system. The energy from a PV system could be fed directly 

into MP’s electric grid to satisfy the state’s RES and/or used on-site by IKONICS or 

other site developers. In addition, if VNM becomes an option, a solar garden approach 

could be used whereby off-site electric customers could purchase a stake in the system on 

a per-kilowatt-hour or module basis.16 

It is recommended that DEDA further pursue opportunities for a PV installation at the 

Atlas Industrial Park. A renewable energy project aligns closely with Duluth’s vision for 

the redevelopment of the St. Louis River corridor, and the Atlas Industrial Park in 

particular could provide a valuable opportunity for a highly visible demonstration project 

for the city and solar developer to gain experience with large PV systems. Although this 

report finds that traditional financing opportunities are not economically feasible at this 

time due to existing incentives and low electricity rates, creative partnerships and 

financing may facilitate a PV installation at the Atlas Industrial Park in the short term. 

Additionally, changes in electric rates, incentives, and module costs could make a PV 

system more cost-competitive with grid-purchased electricity in the years to come. 

16 For a list of solar gardens by state, see www.solargardens.org/. 

32 
Appendix A. Solar Access Measurements
 

Figure A-1. Solar access measurements for the Atlas Industrial Park PV site 

33 
 

 

 

 

 

Appendix B. Results from PVWatts 

Table B-1. PVWatts Inputs 

Station Identification 

Cell ID 14913 

State Minnesota 

Latitude 46.83° N 

Longitude 92.18° W 

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 $0.05/kWh 

Table B-2. Performance Results for a 20-Degree Tilt System 

Solar Radiation AC Energy Energy Value Month (kWh/m2

/day) (kWh) ($) 

1 2.49 67 3.35 

2 3.44 83 4.15 

3 4.83 126 6.30 

4 4.99 120 6.00 

5 5.90 140 7.00 

6 6.20 139 6.95 

7 5.97 135 6.75 

8 5.49 126 6.30 

9 4.30 99 4.95 

10 3.31 80 4.00 

11 2.09 50 2.50 

12 1.94 50 2.50 

Year 4.25 1,216 60.80 

34 
Table B-3. Performance Results for a Tilt = Latitude (46.8°) Fixed-Tilt System 

Month Solar Radiation 

(kWh/m2/day) 

AC Energy 

(kWh) 

Energy Value 

($) 

1 3.29 90 4.50 

2 4.27 104 5.20 

3 5.41 141 7.05 

4 4.99 119 5.95 

5 5.42 127 6.35 

6 5.51 122 6.10 

7 5.36 120 6.00 

8 5.26 120 6.00 

9 4.48 102 5.10 

10 3.85 94 4.70 

11 2.61 63 3.15 

12 2.61 69 3.45 

Year 4.42 1,271 63.55 

Table B-4. Performance Results for Zero-Degree Single-Axis System 

Month Solar Radiation 

(kWh/m2/day) 

AC Energy 

(kWh) 

Energy Value 

($) 

1 2.37 64 3.20 

2 3.51 86 4.30 

3 5.38 143 7.15 

4 5.79 142 7.10 

5 7.44 180 9.00 

6 7.99 183 9.15 

7 7.65 177 8.85 

8 6.65 156 7.80 

9 4.91 115 5.75 

10 3.47 86 4.30 

11 2.03 48 2.40 

12 1.80 46 2.30 

Year 4.92 1,427 71.35 

35 
1

2

3

4

5

6

7

8

9

10

11

12

Table B-5. Performance Results for Zero-Degree Double-Axis System 

Solar Radiation AC Energy Energy Value Month (kWh/m2

/day) (kWh) ($) 

3.98 109 5.45 

5.16 126 6.30 

6.67 175 8.75 

6.48 158 7.90 

7.96 192 9.60 

8.46 194 9.70 

8.10 186 9.30 

7.25 168 8.40 

5.70 133 6.65 

4.62 114 5.70 

3.08 76 3.80 

3.14 84 4.20 

Year 5.89 1,714 85.70 

36 
Appendix C.Results of the SAM Analysis

Table C-1, Table C-2, and Table C-3 are summary output tables from SAM that show the 

five scenarios analyzed in this study. 

Table C-1. DEDA Purchase Scenario 

DEDA Purchase - 8 kW DEDA Purchase - 348 kW 

Net Annual Energy 9,726 kWh Net Annual Energy 423,073 kWh 

LCOE Nominal 39.15 ¢/kWh LCOE Nominal 44.16 ¢/kWh 

LCOE Real 30.12 ¢/kWh LCOE Real 33.98 ¢/kWh 

First-Year Revenue without system $0 First-Year Revenue without system $0 

First-Year Revenue with System $0 First-Year Revenue with System $0 

First-Year Net Revenue $0 First-Year Net Revenue $0 

After-Tax Net Present Value -$48,432 After-Tax NPV -$2,376,681 

Payback Period >25 years Payback Period >25 years 

Capacity Factor 13.9% Capacity Factor 13.9% 

First Year kWhAC/kWDC 1,216 First Year kWhAC/kWDC 1,216 

Table C-2. Third-Party Purchase Without PPA 

Third Party - 10 kW Third Party - 348 kW 

Net Annual Energy 12,157 kWh Net Annual Energy 423,073 kWh 

LCOE Nominal 15.88 ¢/kWh LCOE Nominal 18.80 ¢/kWh 

LCOE Real 12.60 ¢/kWh LCOE Real 14.93 ¢/kWh 

First-Year Revenue without system $0 First-Year Revenue without system $0 

First-Year Revenue with System $0 First-Year Revenue with System $0 

First-Year Net Revenue $0 First-Year Net Revenue $0 

After-Tax Net Present Value -$18,991 After-Tax NPV -$782,657 

Payback Period >25 years Payback Period >25 years 

Capacity Factor 13.9% Capacity Factor 13.9% 

First Year kWhAC/kWDC 1,216 First Year kWhAC/kWDC 1,216 

37 
 

 

Table C-3. Commercial-Scale PPA Scenario 

Third Party/PPA - 348 kW 

Net Annual Energy 423,073 kWh 

PPA Price 35.15 ¢/kWh 

LCOE Nominal 39.67 ¢/kWh 

LCOE Real 31.49 ¢/kWh 

After-Tax IRR 15% 

Pre-Tax Min DSCRa 1.25 

After-Tax Net Present Value $185,576 

PPA Price Escalation 1.50% 

Debt Fraction 50% 

Capacity Factor 13.9% 

First Year kWhDC/kWAC 1,216 

a Debt service coverage ratio 

Figure C-1. Module cost versus real levelized cost of energy for grid parity 

0 

2 

4 

6 

8 

10 

12 

14 

16 

18 

20 

0.1 0.3 0.5 0.7 0.9 1.1 1.3 1.5 1.7 1.9 

Real LCOE (

¢/kWh) 

Module Cost ($/kW) 

Module Cost vs. Real LCOE for Grid-Parity 

DEDA 

Private 

PPA 

38 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Appendix D. Results of the JEDI Model 

Table D-1 and Table D-2 are output tables from the JEDI PV model for implementing a 

residential- and commercial-scale PV system in Duluth, Minnesota. 

Table D-1. JEDI Results, Residential-Scale System 

Photovoltaic - Project Data Summary based on model default values 

Project Location Minnesota 

Year of Construction or Installation 2013 

Average System Size - DC Nameplate Capacity (kW) 9 

Number of Systems Installed 1 

Total Project Size - DC Nameplate Capacity (kW) 9 

Small 

System Application Commercial 

Crystalline 

Solar Cell/Module Material Silicon 

System Tracking Fixed Mount 

Base Installed System Cost ($/kWDC) $7,360 

Annual Direct Operations and Maintenance Cost ($/kW) $26.00 

Money Value - Current or Constant (Dollar Year) 2012 

Project Construction or Installation Cost $66,240 

Local Spending $42,955 

Total Annual Operational Expenses $7,918 

Direct Operating and Maintenance Costs $234 

Local Spending $213 

Other Annual Costs $7,684 

Local Spending $0 

Debt Payments $0 

Property Taxes $0 

Local Economic Impacts - Summary Results 

Jobs Earnings Output 

During construction and installation period $000 (2012) $000 (2012) 

Project Development and On-site Labor Impacts
 

Construction and Installation Labor 0.1 $6.0
 

Construction and Installation Related Services 0.2 $7.6 

Subtotal 0.2 $13.6 $24.1 

Module and Supply Chain Impacts 

Manufacturing 0.0 $0.0 $0.0 

Trade (Wholesale and Retail) 0.0 $3.2 $9.2 

Finance, Insurance and Real Estate 0.0 $0.0 $0.0 

Professional Services 0.1 $2.4 $7.5 

Other Services 0.1 $3.8 $12.2 

39 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other Sectors 0.1 $2.5 $6.0 

Subtotal 0.2 $12.0 $34.9 

Induced Impacts 0.2 $7.5 $24.3 

Total Impacts 0.7 $33.1 $83.2 

Annual Annual 

Annual Earnings Output 

During operating years Jobs $000 (2012) $000 (2012) 

On-Site Labor Impacts 

PV Project Labor Only 0.0 $0.1 $0.1
 

Local Revenue and Supply Chain Impacts 0.0 $0.0 $0.1
 

Induced Impacts 0.0 $0.0 $0.1
 

Total Impacts 0.0 $0.2 $0.3 

Notes: 

*Earnings and output values are thousands of dollars in year 2012 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 & Equipment 

Mounting (rails, clamps, fittings, etc.) $2,619 100% N 

Modules $21,010 100% N 

Electrical (wire, connectors, breakers, etc.) $1,685 100% N 

Inverter $3,792 100% N 

Subtotal $29,106 

Labor 

Installation $5,972 100% 

Subtotal $5,972 

Subtotal $35,078 

Other Costs 

Permitting $8,378 100% 

Other Costs $3,420 100% 

Business Overhead $19,364 100% 

Subtotal $31,162 

Subtotal $66,240 

Sales Tax (Materials & Equipment Purchases) $0 100% 

Total $66,240 

40 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

PV System Annual Operating and Maintenance 

Costs Cost Local Share 

Labor 

Technicians $128 100% 

Subtotal $128 

Materials and Services 

Materials & Equipment $106 100% 

Services $0 100% 

Subtotal $106 

Sales Tax (Materials & Equipment Purchases) $0 100% 

Average Annual Payment (Interest and Principal) $7,684 0% 

Property Taxes $0 100% 

Total $7,918 

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) 100% 

Local Property Taxes $0 100% 

Local Sales Tax Rate 6.88% 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 $23.69 45.6% 

O&M Labor 

Technicians $23.69 45.6% 

41 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Table D-2. JEDI Results, Commercial-Scale System 

Photovoltaic - Project Data Summary Based on Model Default Values 

Project Location Minnesota 

Year of Construction or Installation 2013 

Average System Size - DC Nameplate Capacity (kW) 348 

Number of Systems Installed 1 

Total Project Size - DC Nameplate Capacity (kW) 348 

Large 

System Application Commercial 

Crystalline 

Solar Cell/Module Material Silicon 

System Tracking Fixed Mount 

Base Installed System Cost ($/kWDC) $5,790 

Annual Direct Operations and Maintenance Cost ($/kW) $26.00 

Money Value - Current or Constant (Dollar Year) 2012 

Project Construction or Installation Cost $2,014,920 

Local Spending $1,205,084 

Total Annual Operational Expenses $242,779 

Direct Operating and Maintenance Costs $9,048 

Local Spending $8,324 

Other Annual Costs $233,731 

Local Spending $0 

Debt Payments $0 

Property Taxes $0 

Local Economic Impacts - Summary Results 

Jobs Earnings Output 

During construction and installation period $000 (2012) $000 (2012) 

Project Development and On-site Labor Impacts
 

Construction and Installation Labor 3.0 $191.20
 

Construction and Installation Related Services 4.1 $198.10 

Subtotal 7.0 $389.30 $662.40 

Module and Supply Chain Impacts 

Manufacturing 0.0 $0.0 $0.0 

Trade (Wholesale and Retail) 1.5 $101.40 $289.20 

Finance, Insurance, and Real Estate 0.0 $0.0 $0.0 

Professional Services 1.3 $63.60 $194.50 

Other Services 1.4 $99.00 $317.40 

Other Sectors 2.5 $73.50 $185.20 

Subtotal 6.7 $337.50 $986.20 

Induced Impacts 5.2 $208.70 $677.40 

Total Impacts 18.9 $935.50 $2,326.00 

42 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Annual Annual 

Annual Earnings Output 

During operating years Jobs $000 (2012) $000 (2012) 

On-Site Labor Impacts 

PV Project Labor Only 0.1 $5.00 $5.00 

Local Revenue and Supply Chain Impacts 0.0 $1.70 $5.10 

Induced Impacts 0.0 $1.00 $3.30 

Total Impacts 0.1 $7.70 $13.50 

Notes: 

*Earnings and output values are thousands of dollars in year 2012 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 & Equipment 

Mounting (rails, clamps, fittings, etc.) $87,998 100% N 

Modules $730,706 100% N 

Electrical (wire, connectors, breakers, etc.) $61,708 100% N 

Inverter $131,884 100% N 

Subtotal $1,012,295 

Labor 

Installation $191,183 100% 

Subtotal $191,183 

Subtotal $1,203,478 

Other Costs 

Permitting $218,164 100% 

Other Costs $89,047 100% 

Business Overhead $504,231 100% 

Subtotal $811,442 

Subtotal $2,014,920 

Sales Tax (materials and equipment purchases) $0 100% 

Total $2,014,920 

PV System Annual Operating and Maintenance 

Costs Cost Local Share 

Labor 

Technicians $5,429 100% 

Subtotal $5,429 

Materials and Services 

43 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Materials & Equipment $3,619 100% 

Services $0 100% 

Subtotal $3,619 

Sales Tax (materials and equipment purchases) $0 100% 

Average Annual Payment (interest and principal) $233,731 0% 

Property Taxes $0 100% 

Total $242,779 

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) 100% 

Local Property Taxes $0 100% 

Local Sales Tax Rate 6.88% 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% 

44