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

Office of Energy Efficiency & Renewable Energy, operated by the 

Alliance for Sustainable Energy, LLC.

Contract No. DE-AC36-08GO28308

Feasibility Study of Economics 

and Performance of Solar 

Photovoltaics at the Tronox 

Facility in Savannah, Georgia

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

Kosol Kiatreungwattana, Jesse Geiger, 

Victoria Healey, and Gail Mosey

Produced under direction of the Environmental Protection Agency 

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

Interagency Agreement IAG-09-1750 and Task No. WFD6.1001.

Technical Report

NREL/TP-7A30-57958

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

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

Contract No. DE-AC36-08GO28308

National Renewable Energy Laboratory

15013 Denver West Parkway

Golden, CO 80401

303-275-3000 • www.nrel.gov

Feasibility Study of Economics 

and Performance of Solar 

Photovoltaics at the Tronox 

Facility in Savannah, Georgia

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

Kosol Kiatreungwattana, Jesse Geiger, 

Victoria Healey, and Gail Mosey

Prepared under Task No. WFD6.1001

Technical Report

NREL/TP-7A30-57958

March 2013
NOTICE

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

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

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

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

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

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

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

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

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

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

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

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

Acknowledgments

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

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

the assessment team for this project are grateful to the Tronox Facility managers, engineers, and 

operators for their generous assistance and cooperation. 

Special thanks go to Shea Jones, Jessica Trice, Lura Matthews, and Margaret Olson from EPA;

Katie Brown, AAAS Science & Technology Policy fellow hosted by the U.S. EPA; Brian 

Barton, Ronald McGee, and Dale Holloway from Georgia Power; Cristy Lawrence from the City 

of Savannah; and Mark Smith, Jim Brown, Jim McNamara, and Nikki Haborak from State of 

Georgia for hosting the visit. The authors would also like to thank Marc Weinreich from 

Greenfield Environmental Savannah Trust LLC and Phillip Rowland and Joseph Blackmon from 

Savannah Acid Plant for hosting and facilitating the site visit.
iv

Executive Summary

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

America’s Land initiative, selected the Tronox Facility site in Savannah, Georgia, for a 

feasibility study of renewable energy production. The National Renewable Energy Laboratory 

(NREL) provided technical assistance for this project. The purpose of this report is to assess the 

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

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

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

environmental conditions at the site. 

The Tronox site is located at 1 Kerr-McGee Road in Savannah, Chatham County, Georgia. It is 

about 1 mile northeast of the intersection of Kerr-McGee Road and East President Street. Plant 

operations occupy about 250 acres on the north central portion of the approximately 1,480-acre 

facility. The main plant includes former titanium dioxide and sulfuric acid production facilities

and a former wastewater treatment plant, including five effluent settling ponds, a former in-plant 

neutralization basin, and several rail lines. The entire facility is regulated under the Georgia 

Hazardous Site Response Act (State Superfund) for releases of metals, volatile organic 

compounds (VOCs), and semi volatile organic compound (SVOCs) to soil and groundwater and 

also has three Resource Conservation and Recovery Act (RCRA)-regulated units that require 

investigation, corrective action, and closure. A portion of the site, referred to as the Deptford 

Tract, was used by the City of Savannah as an industrial and municipal waste landfill from 1921 

until it was closed in 1953. The Savannah Energy Systems Company operated a municipal solid 

waste incinerator on a leased portion of the facility from 1985 to 2008.

Tronox declared bankruptcy in 2009, and the case was settled in 2011. The case settlement 

includes creation of a custodial environmental trust to provide cleanup for the Savannah facility. 

The current trustee is Greenfield Environmental Savannah Trust LLC; the State of Georgia and 

U.S. Department of Justice are the beneficiaries of the trust. Rather than fencing the Deptford 

Tract and leaving it unused, Georgia Environmental Protection Division (GA EPD) believes that 

this would be a suitable location for a renewable energy project, which will benefit the local 

community in a number of ways.

There are two locations at the Tronox facility that are being proposed for this study as potential 

locations for renewable energy projects, the Deptford Tract and the former Montenay Municipal 

Solid Waste (MSW) incinerator. Both locations are excellent for PV because they are nearly flat, 

have adequate road and solar access, are zoned for industrial use, and have extensive electrical 

distribution (which can be found throughout the whole site). The plan is to construct a solar PV

system on a concrete cap over the former landfill (Areas 1, 2, and 3) and in an area near the 

former incinerator (Area 4). The renewable energy projects would return these lands to 

productive use and more effectively mitigate potential exposure to the waste that remains at the 

landfill. This renewable energy project will perfectly integrate with the need to prevent exposure 

to the waste left in place.

The total Tronox Facility area for this study is approximately 49 acres, divided into four major 

areas. Areas 1, 2, 3, and 4 are approximately 17, 23, 9, and 1 acres, respectively. Areas 1 and 3 

are currently full of vegetation and would require cleanup and site preparation. All areas are 
v

relatively flat, unshaded land, which makes them suitable candidates for a PV system. Because 

these sites are contaminated areas and will be capped with concrete, we do not recommend any 

penetration through the cap. Therefore, the fixed-tilt ballasted PV system is recommended for 

this site. The PV capacity of a fixed-tilt ballasted system estimated for Areas 1, 2, 3, and 4 are 

approximately 2,909 kW; 4,007 kW; 1,456 kW; and 162 kW, respectively. The estimated total 

PV capacity at the Tronox Facility based on the maximum available land area for this study is as 

much as 8,534 kW (8.5 MW).

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

resources, distance to transmission lines, and distance to major roads. The potential closest 

electrical tie-in location is at the Georgia Power substation. Having a substation on site makes it 

an ideal location to tie into a PV system. A detailed interconnection study is recommended and 

will have to be performed through the local electric utility, Georgia Power, to determine the 

feasibility of utilizing the onsite substation as a tie-in point for a PV system. The Tronox Facility 

site is suitable for a large-scale PV system because it is nearly flat, has adequate road and good 

solar access, is zoned for industrial uses, and has extensive electrical distribution to the whole 

site. PV cost for crystalline panels comes down dramatically and becomes competitive with thinfilm technology. Therefore, we assumed crystalline PV panels for this analysis. Estimated PV 

system size and generated electricity is presented in Table ES-1.

Table ES-1. Estimated Electricity Production for Each Area 

Site

Estimated PV Capacity

(kW)

Annual Electricity

Production

(kWh/yr)

Annual Energy Value

($)

Area 1 2,909 3,813,699 324,164

Area 2 4,007 5,253,177 446,520

Area 3 1,456 1,908,816 162,249

Area 4 162 212,382 18,052

Total 8,534 11,188,074 950,986

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

of the assumptions and background information discussed previously as well as a number of 

industry-specific inputs determined by other studies. In particular, this study uses NREL’s

System Advisor Model (SAM). Using varied inputs and the assumptions summarized in 

Section 5 of this report, the SAM tool predicts net present value (NPV), power purchase 

agreements (PPA), and levelized cost of energy (LCOE), among other economic indicators.

According to the modeling software with the given assumptions, every scenario for solar 

development would have a payback.

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

analysis, NREL’s Jobs and Economic Development Impact (JEDI) models are used. JEDI 

estimates 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 
vi

predict, the number of jobs and economic impacts that can be reasonably supported by the 

proposed facility.

There are three scenarios evaluated as part of this PV project analysis. All detailed assumptions 

and results for the analysis can be found in the Appendix. The three scenarios are:

Case 1: Investor owned/PPA with 8.5 MW

This case assumes a third-party investor for the PV system. All generated electricity from Case 1 

is assumed to be sold. The results of this case are used to estimate the electricity rate needed as 

part of a PPA to get an acceptable return on investment (15% internal rate of return). 

Case 2: Developer owned/PPA with 8.5 MW

This case assumes the developer owns the PV system. All generated electricity from Case 2 is 

assumed to be sold to Georgia Power at the avoided cost of $0.08/kWh. 

Case 3: Developer owned/net metering with 100 kW

This case assumes the developer owns the PV system. All electricity from Case 3 is assumed to 

be used on site. 

Results

The three scenarios were run for the Tronox Facility to encompass the options available for this 

site. The independent variables include a third-party developer versus existing site ownership 

and on-site use of electricity versus selling it back to Georgia Power. There are multiple factors 

that go into choosing which scenario to pursue beyond NPV, PPA, and LCOE. Table ES-2 shows 

the modeled results from the different scenarios. 

• Case 1—Investor owned/PPA will be economically feasible if the investor can sell the 

electricity of the PPA at $0.1886/kWh. The retail rate of the electricity at $0.085/kWh is 

lower than a PPA, so the Tronox Facility is not likely to buy this electricity. In addition, 

Georgia Power’s purchase rate is estimated to be approximately $0.080/kWh. Therefore, 

a solar investor is unlikely to invest given current conditions.

• Case 2—Developer owned/PPA has negative NPV and shows the low LCOE of 

$0.089/kWh with a payback period of 24 years. However, further analysis shows that 

NPV becomes positive if the utility purchase price is $0.135/kWh or above. Therefore, 

the project can be viable if the purchase rate is increased or the developer can negotiate 

for that rate.

• Case 3—Economically, a PV system up to 100 kW net metering is the best scenario. It 

has a positive NPV and a payback of approximately 14 years. This system could generate 

up to 132,000 kWh annually. We recommend the 100-kW net-metering project for each 

individual future building/site. 

Results of the JEDI analysis show that the total potential system of 8.5 MW is estimated to 

support 235 direct and indirect jobs per year for the duration of the procurement and construction 

periods. Total wages paid to workers during the construction period are estimated to be 

$10,895,200, and total economic output is estimated to be $27,099,700. The annual O&M of the 
vii

new PV system is estimated to support 3.2 full-time equivalents (FTEs) per year for the life of 

the system. The jobs and associated spending are projected to account for approximately 

$176,200 in earnings and $307,900 in economic activity each year for the next 25 years.

Improvements to the incentives field could change these projects to be very favorable. Such 

incentives would include an increase to the purchase price from Georgia Power; loan guarantees 

with longer repayment periods; and higher REC payments that would apply to larger systems.

A large PV system can be installed at the Tronox Facility site. Finding potential buyers for the 

generated electricity at a reasonable price—whether they are future Tronox industries or a local 

or interstate utility company—will be key to the project’s development. Virtual net metering 

would also be a good option to sell the excess electricity if the state allows. In addition, any 

environmental considerations shall be included in the request for proposals during project 

development.

Table ES-2. PV System Summary 

Investor-Owned Cases

Capacity LCOE 

($/kWh)

NPV 

($)

PPA 

($/kWh)

Payback 

(yr)

Case 1 - Investor owned/PPA 8.50 MW $0.2124 $1,576,988 $0.1882 N/A

Case 2 - Developer owned PPA 8.50 MW $0.1132 ($5,242,793) - 24.4

Case 3 - Developer owned/net metering 100 kW $0.0587 $17,055 - 13.8

Table ES-3. Potential Energy Production and Economic Impacts on Created Jobs

System Type PV System Sizea Array Tilt

Annual 

Output

Number of 

Houses Poweredb

Jobs 

Createdc

Jobs 

Sustainedd

(MW) (deg) (MWh/year) (job-year) (job-year)

Case 1 - Investor owned/ PPA 8.50 20 11,188 1,013 235 3.2

Case 2 - Developer owned/ PPA 8.50 20 11,188 1,013 235 3.2

Case 3 - Developer owned/ net-metering 0.10 20 131 12 13 0.1

System Type System Cost

Case 1 - Investor owned/ PPA $ 29,698,320 

Case 2 - Developer owned/ net-metering $ 29,698,320 

Case 3 - Developer owned/ net-metering $ 348,000 

a Data assume a maximum usable area of 2,000 acres.

b

 Number of average American households that could hypothetically be powered by the PV system assuming 

11,040 kWh/year/household.

d

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

c

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

Table of Contents

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

2 Development of a PV System on Contaminated Lands.................................................................... 5

3 PV Systems ........................................................................................................................................... 7

3.1 PV Overview.................................................................................................................................... 7

3.2 Major System Components.............................................................................................................. 8

3.2.1 PV Module.......................................................................................................................... 8

3.2.2 Inverter.............................................................................................................................. 10

3.2.3 Balance-of-System Components....................................................................................... 11

3.2.4 Operation and Maintenance .............................................................................................. 13

3.3 Siting Considerations..................................................................................................................... 13

4 Proposed Installation Location Information.................................................................................... 14

4.1 Tronox Facility Site PV System .................................................................................................... 14

4.2 Utility-Resource Considerations.................................................................................................... 16

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

4.4 PV Site Solar Resource.................................................................................................................. 16

4.5 Tronox Facility Energy Usage ....................................................................................................... 18

4.5.1 Net Metering..................................................................................................................... 18

4.5.2 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

Case 1: Investor-owned/PPA with 8.5 MW................................................................................... 23

Case 2: Developer-owned/PPA with 8.5 MW ............................................................................... 23

Case 3: Developer-owned/net metering with 100 kW................................................................... 23

5.3 Results............................................................................................................................................ 23

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

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

5.5.1 Owner and Operator Financing......................................................................................... 26

5.5.2 Third-Party Developers with Power Purchase Agreements.............................................. 26

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

5.5.4 Hybrid Financial Structures.............................................................................................. 27

5.5.5 Solar Services Agreement and Operating Lease............................................................... 27

5.5.6 Sales/Leaseback ................................................................................................................ 28

5.5.7 Community Solar/Solar Gardens...................................................................................... 28

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

Appendix A. Assessment and Calculations Assumptions................................................................... 31

Appendix B. Solar Access Measurements ............................................................................................. 32

Appendix C. Results of the JEDI Model.................................................................................................. 33

Appendix D. Assumptions and Results of the System Advisor Model ............................................... 36

Case 1: Investor owned/PPA with 8.5 MW.......................................................................................... 36

Case 2: Developer owned/PPA with 8.5 MW...................................................................................... 36

Case 3: Developer owned/net metering with 100 kW.......................................................................... 36

Assumptions for Inputs (For Case 3 as the best economic results)...................................................... 38

Climate........................................................................................................................................... 38

Utility Rate..................................................................................................................................... 38

Financing ....................................................................................................................................... 39

Tax Credit Incentives..................................................................................................................... 39

Payment Incentives........................................................................................................................ 40

Annual Performance ...................................................................................................................... 40

PV System Costs............................................................................................................................ 41

PVWatts Solar Array ..................................................................................................................... 42
ix

List of Figures

Figure 1. Tronox Facility property line............................................................................................2

Figure 2. Generation of electricity from a PV cell...........................................................................7

Figure 3. Ground-mounted array diagram .......................................................................................8

Figure 4. Mono- and multi-crystalline solar panels.........................................................................9

Figure 5. Thin-film solar panels installed on (left) solar energy cover and (middle/right) fixedtilt mounting system.................................................................................................................10

Figure 6. String inverter.................................................................................................................11

Figure 7. Aerial view of proposed areas for PV projects at the Tronox Facility...........................14

Figure 8. Views of the feasible area for PV at Areas 1 and 3 of the Deptford Tract.....................15

Figure 9. Views of the feasible area for PV at Area 4 of the Montenay Incinerator.....................16

Figure B-1. Solar access measurements for Tronox Facility PV site ............................................32

Figure D-1. PV system output .......................................................................................................37

Figure D-2. Levelized cost of energy ............................................................................................37

Figure D-3. After-tax cash flow.....................................................................................................38

Figure D-4. Climate input..............................................................................................................38

Figure D-5. Utility rate input .........................................................................................................38

Figure D-6. Financing Input ..........................................................................................................39

Figure D-7. Tax credit input ..........................................................................................................39

Figure D-8. Payment incentive input.............................................................................................40

Figure D-9. Annual system performance input..............................................................................40

Figure D-10. PV system costs input ..............................................................................................41

Figure D-11. PVWatts solar array input ........................................................................................42

List of Tables

Table ES-1. Estimated Electricity Production for Each Area..........................................................v

Table ES-2. PV System Summary................................................................................................ vii

Table ES-3. Potential Energy Production and Economic Impacts on Created Jobs..................... vii

Table 1. Energy Density by Panel and System..............................................................................12

Table 2. Area Size for Each Site, Estimated PV Capacity, and Distance to Utility Tie-in ...........15

Table 3. Site Identification Information and Specifications..........................................................17

Table 4. Performance Results for 20-Degree Fixed-Tilt PV .........................................................17

Table 5. Estimated Electricity Production for Each Site ...............................................................18

Table 6. Installed System Cost Assumptions.................................................................................21

Table 7. Summary of Incentives Evaluated ...................................................................................22

Table 8. PV System Summary.......................................................................................................24

Table 9. Potential Energy Production and Economic Impacts on Created Jobs............................24

Table 10. JEDI Analysis Assumptions ..........................................................................................25

Table A-1. Cost, System, and Other Assessment Assumptions ....................................................31

Table C-1. Summary Results of the NREL JEDI Model...............................................................33

Table D-1. Case 3 Results..............................................................................................................36
1

1 Study and Site Background

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

America’s Land initiative, selected the Tronox Facility site in Savannah, Georgia, for a 

feasibility study of renewable energy production. The National Renewable Energy 

Laboratory (NREL) provided technical assistance for this project. The purpose of this 

report is to assess the site for a possible photovoltaic (PV) system installation and 

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

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

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

The Tronox Facility site is located at 1 Kerr-McGee Road, in Savannah, Chatham 

County, Georgia, about 1 mile northeast of the intersection of Kerr-McGee Road and 

East President Street. As of the 2011 census, Savannah has a population of 139,491. 

Savannah usually has warm, and frequently hot, humid weather throughout the year. 

Average high temperature in January is 59.7°F, and the average high is 91.1°F in July. 

The average low temperature in January is 38.1°F, whereas the average low temperature 

in July is 72.4°F. Average total precipitation is 49 inches per year. Summer in Savannah 

tends to be humid with many thunderstorms. However, Savannah has on average 

216 days of sunshine each year. Georgia Power is the utility that provides electricity to 

Tronox; it is a regulated utility.

Plant operations occupy about 250 acres on the north central portion of the larger 

property that covers approximately 1,480 acres. Figure 1 shows the property line of the 

Tronox Facility.

The main plant includes former titanium dioxide and sulfuric acid production facilities

and a former wastewater treatment plant (including five effluent settling ponds, a former 

in-plant neutralization basin, and several rail lines). The entire facility is regulated under 

the Georgia Hazardous Site Response Act (State Superfund) for releases of metals, 

volatile organic compounds (VOCs), and semi volatile organic compounds (SVOCs) to 

soil and groundwater and also has three Resource Conservation and Recovery Act

(RCRA)-regulated units that require investigation, corrective action, and closure. A 

portion of the site, referred to as the Deptford Tract, was used by the City of Savannah as 

an industrial and municipal waste landfill from 1921 until it was closed in 1953. The 

Savannah Energy Systems Company operated a municipal solid waste incinerator on a 

leased portion of the facility from 1985 to 2008.

The Deptford Tract is regulated under the State Superfund and was listed on the Georgia 

Hazardous Site Inventory in 1994 for a release of metals to groundwater and metals, 

VOCs, and SVOCs to soil. The corrective action for the Deptford Tract calls for the 

excavation of limited hot spots, installation of a barrier fence to prevent access, and 

institutional controls. 
2

Figure 1. Tronox Facility property line

Illustration done in Google Earth

Tronox declared bankruptcy in 2009, and the case was settled in 2011. The case 

settlement includes creation of a custodial environmental trust to provide cleanup of the 

Savannah facility. The current Trustee is Greenfield Environmental Savannah Trust LLC. 

The State of Georgia and U.S. Department of Justice are the beneficiaries of the trust. 

Any proceeds from the sale of the site not needed for the Savannah property will be 

distributed to a multi-state trust for cleanup of other Tronox facilities. If funds remain in 

any trust when all environmental actions under all trusts are completed, these funds will 

revert to the USEPA Superfund.

The two main areas of known contamination at the site are the Deptford Tract and the 

main plant area. The Deptford Tract is a former City of Savannah landfill, operated from 

1921–1953. The Deptford Tract has been investigated under the requirements of the 

Georgia Hazardous Site Response Act (HSRA), which is the Georgia State Superfund 

statute, and the rules promulgated pursuant thereto. This site was listed on the Georgia 

Hazardous Site Inventory (HSI) in 1994; the Deptford Tract covers about 60 acres that 

require corrective action for releases of metals to groundwater and metals, VOCs, and 

SVOCs to soil. The main plant area is also listed on the HSI and has a footprint of around 

250 acres. Over 60 acres of the main plant area have a series of ponds formerly used for 

solids settling, with only two of these ponds having freeboard to hold water; the others 

are filled with solids from processes at the site. The main plant area groundwater is 

contaminated with metals and solvents and the soil is contaminated with metals. 
3

The Deptford Tract has been fully investigated and a Corrective Action Plan (CAP) has 

been submitted and approved by Environmental Protection Division (EPD). The CAP 

requires some excavation of highly contaminated areas, restoration of the soil cover, and 

installation of a 5-foot chain link fence and signage to restrict access. Annual 

groundwater monitoring is required to demonstrate that groundwater contamination is not 

increasing or spreading. Quarterly inspection of the soil cover over the landfill is also 

required. A restrictive covenant has been recorded that requires implementation of the 

CAP, maintenance of the fence, and prohibition of drinking water wells.

The main plant area was used from 1955–2009 for production of titanium dioxide 

pigment using both the sulfate and chloride processes. A 300+-ton-per-day sulfuric acid 

plant continues to operate in this area. Within the main plant area, three discrete locations 

have been identified as RCRA-regulated units: the ditch system, the chlorinator brick 

pile, and the washout sump area. All three units have managed releases of low-pH 

wastewaters and require closure. Investigation of these areas is complete, and closure of 

these three areas will be finished in 2013. It is expected that corrective action for these 

areas will consist of excavation. Because previous investigations by former owners of the 

site indicate that groundwater contamination is not solely attributable to these units, upon 

certification of closure the remaining investigation and remediation in the main plant area 

will be conducted under HSRA.

Other environmental concerns at the site include:

• Maintenance of the berms around the ponds adjacent to the Savannah River

• Asbestos siding on the old sulfate plant structure

• Possible contamination at the former Montenay Municipal Solid Waste (MSW)

Incinerator

• Possible contamination at the Kemira Water Solutions area

• Groundwater contamination being remediated by Air Liquide

• Maintenance of storm water controls at gypsum stockpile east of the 

Deptford Tract.

Rather than fencing the Deptford Tract and leaving it unused, Georgia EPD believes that 

this would be a suitable location for a renewable energy project. The renewable energy 

project will benefit the local community in a number of ways. There is a need for this 

facility to be redeveloped to increase the local tax base and provide jobs. The property 

and surrounding area are largely industrial and are expected to grow with continued 

expansion of the Savannah port. Renewable energy development in this area is seen as a 

key inducement for expanding global commerce in this part of Savannah. As a coastal 

community, there is a need to develop energy sources that do not impact the sensitive 

environment and ecosystems. The proposed projects will induce the redevelopment of the 

facility by providing low-cost power, reduce the need for electricity generated by nonrenewable sources, and reduce the environmental impact from current power sources.

The Montenay Incinerator is a former MSW incinerator that consists of two mass-fired 

combustion units. Part of the NREL grant application included evaluating the feasibility 
4

of operating the former Montenay Incinerator as a biopower plant. The facility was 

operated by the Savannah Energy Systems Company from 1985–2008. The facility was 

designed to process 500 tons per day of non-hazardous waste with higher heating value of 

4,500 Btu/lb. The combustion system consists of a Katy-Seghers grate and an underfire 

and overfire air supply system, a charge system, a grate sifting bottom ash removal 

system, and controls. Overhead cranes were used to move waste from storage pits to a 

charging chute. The grate surface of the combustion units can continuously accept waste 

from the charging unit and move it through the combustion unit as it burns. 

During its operation, the plant processed an average of 157,000 tons per year and had a 

boiler efficiency of 67%. Rather than leave this plant idle, the Georgia EPD is interested 

in operating the facility as a biopower plant. In addition to numerous industrial facilities 

in the area that could supply used wooden pallets and other organic industrial debris, 

there are two pulp and paper mills within 50 miles of this location that could provide pulp 

and paper mill residues. With highway, rail, and deep-water river access, there are 

numerous sources of biofuels that could be utilized by this project. While not included as 

part of this project, determining the future feasibility of a biopower plant is 

recommended.

There are two locations at the Tronox Facility that are being evaluated in this study as 

potential locations for PV system projects, the Deptford Tract and the area around the 

former Montenay MSW Incinerator. Both locations are excellent for PV because they are 

nearly flat, have suitable road and solar access, are zoned for industrial use, and have 

extensive available electrical distribution. The plan is to construct a solar PV system on a 

concrete cap over the former landfill and in the area around the former incinerator. The 

renewable energy projects would return these lands to productive use and be a more 

effective method of eliminating potential exposure to the waste that remains at the 

landfill. This renewable energy project will perfectly meet the need to prevent exposure 

to that waste.

In addition, EPD has received a commitment from Georgia Power to purchase any excess 

electricity generated by these projects. Further, Georgia Power is actively working with 

EPD regarding the installation of solar power generating equipment on closed landfills 

and is looking to gain experience through this process in order to apply renewable energy 

projects like this study to other properties.

Feasibility assessment team members from NREL, EPD, and EPA conducted a site visit 

on April 3, 2012, to gather information integral to this feasibility study for solar PV 

systems. The team considered information including solar resource, transmission 

availability, community acceptance, and ground conditions.
5

2 Development of a PV System on Contaminated 

Lands 

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

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

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

• Might 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

• Might 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

(GHGs)].

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.

The Tronox Facility is managed by Greenfield Environmental Savannah Trust LLC, 

which is interested in developing renewable projects on the site. For many contaminated 

land sites, 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 at other similar sites demonstrate the 

potential for PV system development. Due to the contamination with hazardous waste, 

the Tronox site has limited building development opportunities. It is within a location in 

need of locally produced power. Remediation of contamination is at a stage that will

allow for installation of PV systems in the future. PV development that provides 

community energy and jobs may be the highest and best use of the site.1

There are considerations for installation of solar PV system on contaminated lands, 

including potential impacts to the cover system, erosion, storm water management, 

compaction, construction, and vegetation. In addition, financial assurance would be 

required to remove the solar facility and maintain the installed concrete cap at the end of 

the project life. These considerations shall be included in the request for proposals (RFP) 

during project development.

 1 For more information on similar projects, see the RE-Powering America’s Lands website at 

www.epa.gov/oswercpa/.
6

The subject site has potential to be used for other functions beyond the solar PV systems 

proposed in this report. Any potential use should align with the community vision for the 

site and should enhance the overall utility of the property. 

Beyond the financial benefits of installing a large-scale PV system, there are additional 

non-financial benefits in renewable energy deployment. Property owners can consider 

many additional compelling reasons to consider moving toward renewable energy 

sources for power generation instead of fossil fuels, including: 

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

energy portfolio

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

the environment

• Deployment of renewable energy bolsters national energy independence and 

increases domestic energy security 

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

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

• Generating energy without harmful emissions or waste products can be 

accomplished through renewable energy sources.
7

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 easily emit electrons. The 

electric field in the solar cell pulls these electrons to another layer, connecting the cell to 

an external load. This current (movement of charges) can then be used to power the load 

(e.g., light bulb). 

Figure 2. Generation of electricity from a PV cell

Source: EPA

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

series and then in parallel as needed to reach the specific voltage and current 

requirements for the array in which they are arranged. The direct current (DC) electricity 

generated by the array is 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 sizes vary; there are small residential (2–10 kW), commercial (100–500 kW), 

and large utility-scale (10+ MW) sizes. 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

Current flow

-

Solar cell

- - -

Load
8

3.2 Major System Components

Figure 3. 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 in turn 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, which is quite abundant and non-toxic. It 

builds on a strong industry on both the supply (silicon industry) and product sides. This 

technology has demonstrated a consistent and high efficiency of over 30 years in the 

field. The performance degradation, a reduction in power generation due to long-term 

exposure to environment, is under 1% per year. Silicon modules have a lifespan in the 

25- to 30-year range but can keep producing energy beyond this range. 
9

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, the distinction of which indicates the presence of grainboundaries (i.e., multiple crystals) in the cell materials; this is controlled by raw material 

selection and manufacturing technique. Crystalline silicon panels are widely used based 

on deployments worldwide.

Figure 4 shows two examples of crystalline solar panels: mono- and multi-crystalline

installed on tracking mounting systems.

Figure 4. Mono- and multi-crystalline solar panels. Photos by (left) SunPower, NREL 23816 

and (right) SunPower, NREL 13823

3.2.1.2 Thin Film

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

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

a few micrometers thick. Due to 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 between 6% and 8% for a-Si and 11% and 12% 

for CdTe. Figure 5 shows thin-film solar panels. 
10

Figure 5. Thin-film solar panels installed on (left) solar energy cover and (middle/right) 

fixed-tilt mounting system. Photos by (left) Republic Services Inc., NREL 23817, (middle) 

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

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

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

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

3.2.2 Inverter

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

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

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 on the market. Electricity produced from the system 

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

There are two primary types of inverters for grid-connected systems: string and microinverters. Each type has strengths and weakness and may 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, and they also tend to have high 

efficiency and lower operations and maintenance (O&M) costs. String inverters offer 

various sizes and capacities to handle a large range of voltage output. For larger systems, 

string inverters are combined in parallel to produce a single point of interconnection with 

the grid. Warranties typically run between 5 and 10 years, with 10 years being the current 

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

that the expected life of the 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 

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. 
11

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

the entire array production. With micro-inverters, it impacts only that particular shaded 

panel. Figure 6 shows a string inverter.

Figure 6. String inverter. Photo by Warren Gretz, NREL 07985

3.2.3 Balance-of-System Components

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

called BOS components, which include:

• Mounting racks and hardware for the panels

• Wiring for electrical connections.

3.2.3.1 Mounting Systems

The 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 reclaimed mine site or contaminated land applications, 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 reclaimed mine sites and on contaminated lands. 

Fixed-tilt systems have lower maintenance costs but generate less energy (kWh) per unit 

power (kW) of capacity than tracking systems. 

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

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

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

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

day, potentially increasing output up to 35% or more. However, the movable trackers 
12

require more space between roles. System capacity for tracking systems is less than that 

for the fixed-tilt at the same land area. 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. 

Table 1. Energy Density by Panel and System

System Type Fixed-Tilt Energy Density 

(DC-Watts/ft2

)

Single-Axis Tracking Energy 

Density

(DC-Watts/ft2

)

Crystalline Silicon 4.0 3.3

Thin Film 3.3 2.7

Hybrid High 

Efficiency

4.8 3.9

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

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

Contaminated land applications might 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. With 

reclaimed mine sites or contaminated lands, this wiring may be required to run through 

above-ground conduit due to restrictions with cap penetration or other concerns. 

Therefore, developers should consider noting any such restrictions, if applicable, in 

request for proposals (RFPs) 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. 
13

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

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

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

Collection of this basic information is standard for solar systems and 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 required maintenance, 

shade on panels, and accumulating dirt on panels, for example. Monitoring system data 

can also be used for outreach and education (e.g., publicly available online displays, wallmounted systems, or 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 5-year or 10-year warranty (extended warranties available), would be 

expected to last 10–15 years. System performance should be verified on a vendorprovided website. Wire and rack connections should be checked annually. This economic 

analysis uses an annual O&M cost computed as $20/kW/yr, which is based on the 

historical O&M costs of installed fixed-axis grid-tied PV systems. In addition, the system 

should expect a replacement of system inverters in year 15 at a cost of $0.25/W.

3.3 Siting Considerations

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

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

explained above, PV modules are made up of many individual cells that 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, incentives available, and 

utility policy. 
14

4 Proposed Installation Location Information

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

April 3, 2012.

4.1 Tronox Facility Site PV System

The Tronox Facility site is suitable for PV. There are two proposed locations for 

renewable energy projects for this study: the Deptford Tract (Areas 1, 2, and 3) and the 

area around the former Montenay Incinerator (Area 4). All locations are suitable for PV 

because they are nearly flat, have adequate road and solar access, and have extensive 

electrical distribution. Electricity generated at the site can be sold to Georgia Power.

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

whether the site layout can be improved to better incorporate a solar system. If there are 

unused structures, fences, or electrical poles that can be removed, the unshaded area can 

be increased to incorporate more PV panels. Figure 7 shows an aerial view of the Tronox 

Facility sites. The feasible areas for PV are outlined in orange, and the electrical tie-in 

point for the PV system is given. 

Figure 7. Aerial view of proposed areas for PV projects at the Tronox Facility

Illustration done in Google Maps

There are four proposed areas for PV projects for the Tronox Facility. Potential utility tiein for Areas 1, 2, and 3 is at the Georgia Power substation at the southwest corner of the 

site, as shown in Figure 7. For Area 4, the utility tie-in is at the existing Montenay 

Incinerator. Area acreage and distance to utility tie-in was estimated by using Google 

Earth; area size for each site, estimated PV capacity, and distance to utility tie-in are 

presented in Table 2.
15

Table 2. Area Size for Each Site, Estimated PV Capacity, and Distance to Utility Tie-in

Site Acreage

Estimated PV Capacity

(kW)

Distance to Utility Tie-in

(ft)

Area 1 16.7 2,909 600

Area 2 23.0 4,007 2,250

Area 3 8.4 1,456 3,000

Area 4 0.9 162 100

The total Tronox Facility area for this study is approximately 49 acres, divided into four 

major areas. Areas 1, 2, 3, and 4 are approximately 17, 23, 9, and 1 acres, respectively. 

Areas 1 and 3 are currently full of vegetation requiring cleanup and site preparation.

Once the vegetation is cleared, the areas are relatively flat, unshaded land, which make

them a suitable candidate for a PV system. Because Areas 1, 2, and 3 are contaminated 

areas with leftover waste, we do not recommend any ground penetration. Therefore, the 

fixed-tilt ballasted PV system is recommended for this study. The PV capacity of a fixedtilt ballasted system estimated for Areas 1, 2, 3, and 4 are approximately 2,909 kW; 

4,007 kW; 1,456 kW; and 162 kW, respectively. Estimated total PV capacity of the 

Tronox Facility based on maximum available land area for this study is up to 8,534 kW 

(approximately 8.5 MW). 

PV systems are well suited to the Savannah, Georgia, area, where the average global 

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

direct, diffuse, and ground-reflected radiation—is 5.11 kWh/m2

/day. Figures 8 and 9 

show various views of the studied areas at the Tronox Facility.

Figure 8. Views of the feasible area for PV at Areas 1 and 3 of the Deptford Tract. Photos 

by Kosol Kiatreungwattana, NREL
16

Figure 9. Views of the feasible area for PV at Area 4 of the Montenay Incinerator. Photos by 

Kosol Kiatreungwattana, NREL

4.2 Utility-Resource Considerations

The expected electrical tie-in point and inverter for the PV system at the Tronox Facility 

is located at the Georgia Power Station southwest of Area 1. Areas 1, 2, and 3 can tie in 

to 13.2-kV or 115-kV power lines. Area 4 can potentially tie in to the 13.8-kV power line

at Montenay Incinerator. Per conversation with Georgia Power personnel, the power line 

at the Tronox Facility has adequate capacity to accommodate a large PV system. A 

technical analysis of line capacity is recommended. 

4.3 Useable Acreage for PV System Installation 

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

acreage is typically characterized as "flat to gently sloping" with 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. The total of 49 acres (Area 1, 17 acres; Area 2, 23 acres; Area 3,

9 acres; and Area 4, 1 acre) is flat and free of all major shading obstructions after a 

vegetation cleanup.

4.4 PV Site Solar Resource

The Tronox Facility has been evaluated to determine the adequacy of the solar resource 

available using both on-site data and industry tools. 

Currently, Areas 1 and 3 are full of vegetation and require site preparation and vegetation 

cleanup. The assessment team for this feasibility study collected multiple Solmetric 

SunEye data points and found a solar access of 95% or higher. All data gathered using 

this tool are available in Appendix C.

The predicted array performance was found using PVWatts Version 22 for Savannah, 

Georgia. Table 3 shows the station identification information, PV system specifications, 

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

hypothetical 20-degree fixed-tilt 1-kW system was used to show the estimated production 

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

below. It is scaled linearly to match the proposed system size. 

 2 http://www.nrel.gov/rredc/pvwatts/. 
17

Table 3. Site Identification Information and Specifications

Station Identification

City Savannah

State Georgia

Latitude 32.13° N

Longitude 81.20° 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 (retail) $0.085/kWh

Table 4 shows the performance results for a 20-degree fixed-tilt PV system in Savannah, 

Georgia, as calculated by PVWatts. Estimated electricity production and the value of the 

energy for each system at each site are presented in Table 5.

Table 4. Performance Results for 20-Degree Fixed-Tilt PV

Month Solar Radiation

(kWh/m2

/day)

AC Energy

(kWh)

Energy Value

($)

1 3.47 79 6.71

2 4.52 94 7.99

3 5.54 125 10.62

4 6.03 130 11.05

5 6.18 132 11.22

6 5.99 121 10.29

7 6.14 128 10.88

8 5.65 119 10.12

9 5.15 106 9.01

10 4.93 107 9.10

11 4.15 90 7.65

12 3.49 80 6.80

Year 5.11 1,311 111.44
18

Table 5. Estimated Electricity Production for Each Site 

Site

Estimated PV Capacity

(kW)

Annual Electricity

Production

(kWh/yr)

Annual Energy Value

($)

Area 1 2,909 3,813,699 324,164

Area 2 4,007 5,253,177 446,520

Area 3 1,456 1,908,816 162,249

Area 4 162 212,382 18,052

Total 8,534 11,188,074 950,986

4.5 Tronox Facility Energy Usage

The only current activity at the Tronox Facility is the operation of a 300+ ton-per-day 

sulfuric acid plant and its support systems. The monthly average electricity consumption 

is 2,112,000 kWh. The average power cost is around $0.085/kWh with power provided 

by Georgia Power. Significant utility infrastructure exists at the site, minimizing the need 

for significant investment in transmission equipment to sell power for grid distribution. 

Future power needs of the site are unknown at this time, but it is anticipated that 

additional industry will locate on the site to take advantage of the potential renewable 

energy produced.

4.5.1 Net Metering

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

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

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

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

According to Section 1251of the Energy Policy Act of 2005, all public electric utilities 

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

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

request net metering service to any electric consumer that the electric 

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

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

generated by that electric consumer from an eligible onsite 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.

With significant future on-site energy consumption at the Tronox Facility, net metering 

can be a good option for a PV project. Therefore, net metering was included as part of the 

analysis for this study. However, Georgia Power currently allows only up to a 100-kW 

PV system to consist of net metering. This means it will be a suitable option for a single 

small- or medium-sized building/facility in the future.
19

4.5.2 Virtual Net Metering

Some states and utilities allow for virtual net metering (VNM). This arrangement can 

allow certain entities, such as a local government, to install renewable generation of up to 

1 MW at one location within its geographic boundary and to generate credits that can be 

used to offset charges at one or more other locations within the same geographic 

boundary. Unfortunately, Georgia currently does not offer VNM to PV generators.
20

5 Economics and Performance

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

combination of the assumptions and background information discussed previously as well 

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

study uses NREL’s System Advisor Model (SAM).

3

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. The 

model makes performance predictions for grid-connected solar, solar water heating, 

wind, and geothermal power systems. Further, SAM makes economic calculations for 

projects that buy and sell power at retail rates and for power projects that sell power 

through a PPA.

SAM consists of a performance model and a 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; it makes economic estimates for distributed energy and 

central generation projects. The model calculates the cost of generating electricity based 

on information 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

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

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

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

declined from $4.80/W in the first quarter of 2010 to $2.79/W in the first quarter of 2012. 

With an increasing demand and supply, potential further cost reduction is expected as 

market conditions evolve. 

For this analysis, the installed cost of fixed-tilt ground-mounted systems was assumed to 

be $2.79/W. The cost for PV crystalline panels comes down dramatically and becomes 

competitive with thin-film technology. Therefore, we assumed crystalline PV panels for 

this analysis. Because Areas 1, 2, and 3 have waste and will be capped with concrete, we 

do not recommend any penetration through the cap. Although tracking systems can 

produce more electricity, they have a higher cost and may put uneven stress to the 

capping materials. Therefore, the fixed-tilt ballasted PV system is assumed at the 

Tronox Facility. 

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

(recommended for this site). The cost is increased because of ground conditions at the 

 3 For additional information on the System Advisor Model, see https://sam.nrel.gov. 
21

site, which place limitations on design and construction methods. Such limitations 

include restrictions on stormwater 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 are 

summarized in Table 6.

Table 6. Installed System Cost Assumptions

System Type Fixed Tilt

($/Wp)

Baseline System 2.79

With Ballast 0.70

Total Installed Cost 3.49

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

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

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

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

and panel tilt and orientation. 

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

entities. It is important to consider all applicable incentives or grants to make PV as costeffective as possible. If the PV system is owned by a private tax-paying entity, this entity 

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

can be worth about 30% of the initial capital investment. In fact, the total potential tax 

benefits to the tax-paying 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. 

Future land use and the power demands of any potential reuse are unknown at this time, 

but if there is excess electricity, Georgia Power has a number of options through which it 

can purchase renewable energy. More specifically, customers who generate electricity 

from solar facilities may sell some or all of that electricity back to Georgia Power via the 

following programs:

• Small generators (≤100 kW) are eligible to sell their electricity under the 

Renewable & Non-Renewable Tariff (RNR-7) and the Solar Purchase Tariff 

(SP-1)

o Customers preferring a bi-directional metering option will participate in 

the RNR-7 Tariff. Under the RNR-7 Tariff, energy produced by the solar 

system will offset kilowatt-hours at the facility and any excess kilowatthours generated will be purchased at Georgia Power’s avoided energy 

cost. More information regarding the RNR-7 Tariff can be found at 

www.georgiapower.com/green/rnr_tariff.asp.
22

o Customers interested in selling all of the energy produced by a solar 

facility can participate in the SP-1 Tariff. Under the SP-1 Tariff, all energy 

produced by the facility will be purchased at $0.17/kWh. More 

information regarding the SP-1 Tariff can be found at 

www.georgiapower.com/green/solar_purchase_tariff.asp.

• Larger customers (≤80 MW) could sell their energy as a qualifying facility (QF). 

Under the QF agreement, all energy produced by the facility will be purchased at 

Georgia Power’s avoided energy cost. More information regarding QFs can be 

found at: www.georgiapower.com/smallpowerproducers.asp.

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

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

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

at a 7% interest rate and 80% debt fraction. The panels are assumed to have a 1% per 

year degradation in performance. The O&M expenses are estimated to be $20/kW/yr for 

the life of the system. In addition, it is expected that there will be a $250/kW charge to 

O&M in year 15 to replace the inverters associated with the system. A system DC-to-AC 

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

module losses, and losses due to temperature effects. PVWatts Version 2 was used to 

calculate expected energy performance for the system. 

Georgia Power buys energy from solar resources to supply the Green Energy Program 

through the Solar Purchase Tariff (SP-1). Qualifying customers can sell all of the energy 

produced from solar installations (≤100 kW in size) to Georgia Power at $0.17/kWh. 

However, the program is fully subscribed and is not accepting new customers into the 

program at this time. For small installations (≤100 kW in size), the selling rate was 

assumed at $0.12/kWh for the analysis. With large systems, Georgia Power currently 

buys the electricity back at their avoided generation cost of $0.075–$0.12/kWh with 

capacity credit. The actual buy-in rate is determined on a case-by-case basis. For this 

analysis, we used the price of $0.08/kWh. The electricity retail price was modeled as 

$0.085/kWh. PVWatts Version 2 was used to calculate expected energy performance for 

the system. The list of incentives used in this study can be found in Table 7.

Table 7. Summary of Incentives Evaluated

Incentive Title Modeled Value Expected End

Clean Energy Tax 

Credit (Corporate)

Renewables: 35%; 

Maximum Incentive: 

PV: $500,000 12/31/2014

Net Metering $0.085/kWh For ≤100-kW System
23

5.2 SAM Forecasted Economic Performance

Using varied inputs and the assumptions summarized in Section 5.1, the SAM tool 

predicts NPV, PPA, and LCOE, among other economic indicators. According to the 

modeling software with the given assumptions, every scenario for solar development 

would have a payback. 

The LCOE (in cents per kilowatt-hour) accounts for a project’s installation, financing, 

tax, and operating costs and the quantity of electricity it produces over its life. The LCOE 

makes it possible to compare alternatives with different project lifetimes and performance 

characteristics. Analysts can use the LCOE to compare the option of installing a 

residential or commercial project to purchasing electricity from an electric service 

provider or to compare utility and commercial PPA projects with investments in energy 

efficiency, other renewable energy projects, or conventional fossil fuel projects. The 

LCOE captures the trade-off between typically higher-capital-cost, lower-operating-cost 

renewable energy projects and lower-capital-cost, higher-operating-cost fossil-fuel-based 

projects.

The PPA price is the first-year price that electricity could be sold to the property owner 

allowing the developer to own a certain internal rate of return. For this analysis, the 

required internal rate of return used was 15%, and the first-year PPA price escalates at 

1.5% per year.

There are three scenarios for the analysis. All detailed assumptions and results for the 

analysis can be found in Appendix D.

Case 1: Investor-owned/PPA with 8.5 MW

This case assumes a third-party investor for the PV system. All generated electricity from 

Case 1 is assumed to be sold. The results of this case are used to estimate the needed 

electricity rate as part of a PPA to achieve acceptable return on investment (15% internal 

rate of return). 

Case 2: Developer-owned/PPA with 8.5 MW

This case assumes the developer owns the PV system. All generated electricity from 

Case 2 is assumed to be sold to Georgia Power at the avoided cost at $0.08/kWh. 

Case 3: Developer-owned/net metering with 100 kW

This case assumes the developer owns the PV system and that all electricity is assumed to 

be used on site. 

5.3 Results

The three above scenarios for the Tronox Facility encompass the options available to this 

site. The independent variables include: third-party developer versus existing site 

ownership and on-site use of electricity versus selling it back to Georgia Power. Beyond 

NPV, PPA, and LCOE, there are multiple factors that go into selecting a scenario. 

Table 8 shows the modeled results from the different scenarios. The entire results and 

summary of inputs to SAM is available in Appendix E.
24

• Case 1 will be economically viable if the investor can sell the electricity of the 

PPA at $0.1886/kWh. Because the retail rate of the electricity at $0.085/kWh is 

lower than PPA, the Tronox Facility is not likely to buy electricity at this rate. In 

addition, Georgia Power’s purchase rate is estimated to be approximately 

$0.080/kWh. Therefore, a solar investor is unlikely to invest given current 

conditions.

• Case 2 has negative NPV and shows the low LCOE of $0.089/kWh. LCOE is 

slightly higher than Georgia Power purchase price of $0.08/kWh. Although the 

case is not economically preferable based on negative NPV, further analysis 

shows that this case would be economically viable if the utility had a purchase 

price of $0.135/kWh or higher. 

• Case 3 offset the on-site electricity consumption at retail electricity rate of 

$0.085/kWh. The analysis shows a positive NPV and feasible payback of 

13.8 years. Therefore, Case 3 has the best economic scenario.

Table 8. PV System Summary

Investor-Owned Cases Capacity 

LCOE 

($/kWh)

NPV 

($)

PPA 

($/kWh)

Payback 

(yr)

Case 1 - Investor owned/PPA 8.50 MW $0.2124 $1,576,988 $0.1882 N/A

Case 2 - Developer owned/PPA 8.50 MW $0.1132 ($5,242,793) - 24.4

Case 3 - Developer owned/net metering 100 kW $0.0587 $17,055 - 13.8

Table 9. Potential Energy Production and Economic Impacts on Created Jobs

System Type PV System Sizea Array Tilt

Annual 

Output

Number of 

Houses Poweredb

Jobs 

Createdc

Jobs 

Sustainedd

(MW) (deg) (MWh/year) (job-year) (job-year)

Case 1 - Investor owned/ PPA 8.50 20 11,188 1,013 235 3.2

Case 2 - Developer owned/ PPA 8.50 20 11,188 1,013 235 3.2

Case 3 - Developer owned/ net-metering 0.10 20 131 12 13 0.1

System Type System Cost

Case 1 - Investor owned/ PPA $ 29,698,320 

Case 2 - Developer owned/ net-metering $ 29,698,320 

Case 3 - Developer owned/ net-metering $ 348,000 

a Data assume a maximum usable area of 2,000 acres.

b

 Number of average American households that could hypothetically be powered by the PV system assuming 

11,040 kWh/year/household.

d

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

c

 Job-years created as a result of project capital investment including direct, indirect, and induced jobs.
25

5.4 Job Analysis and Impact

To evaluate employment and economic impacts of the subject PV project, NREL’s Jobs 

and Economic Development Impact (JEDI) models are used.

4 JEDI estimates 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. 

JEDI represents the entire economy, including cross-industry or cross-company 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 JEDI does not predict or incorporate any displacement of related economic activity 

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

results are considered gross estimates as opposed to net estimates. 

For the Tronox Facility, the values in Table 9 were assumed for the 8.5-MW system.

Table 10. JEDI Analysis Assumptions

Input Assumed Value

Capacity 8.5 MW

Placed In Service Year 2013

Installed System Cost $29,698,320

Location Savannah, Georgia

Using these inputs, JEDI estimates the gross direct and indirect jobs, associated earnings, 

and total economic impacts supported by the construction and continued operation of the 

proposed PV system.

The estimates of jobs associated with this project are presented as either constructionperiod jobs or sustained operations jobs. Each job is expressed as a whole, or fraction, 

full-time equivalent (FTE) position. An FTE is defined as 40 hours per week for one 

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

positions that exist only during the procurement and construction periods. 

 4 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 more 

information on JEDI, see http://www.nrel.gov/analysis/jedi/about_jedi.html.
26

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

proposed system of 8.5 MW is estimated to support 235 direct and indirect jobs per year 

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

during the construction period are estimated to be $10,895,200, and total economic 

output is estimated to be $27,099,700. The annual O&M of the new PV system is 

estimated to support 3.2 FTEs per year for the life of the system. The jobs and associated 

spending are projected to account for approximately $176,200 in earnings and $307,900 

in economic activity each year for the next 25 years. 

5.5 Financing Opportunities

The procurement, development, construction, and management of a successful utilityscale distributed generation facility can be financed a number of different ways. The most 

common ownership and financing structures are described below. 

5.5.1 Owner and Operator Financing

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

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

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

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

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

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

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

Project debt is typically issued as a loan based on each owner’s/operator’s 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; or 

through a tax-exempt lease structure, bank financing, grant and incentive program, 

internal cash; or some combination of the above. Certain structures are more common 

than others and grant programs for solar programs are on the decline. Regardless, as taxexempt entities, public entities are unable to benefit directly from the various tax-creditbased incentives available to private companies. This has given way to the common use 

of third-party financing structures, such as the PPA. 

5.5.2 Third-Party Developers with Power Purchase Agreements

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

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

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

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

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

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

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

The PPA typically will be an agreement 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. 
27

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

PPA or land lease revenues for making the site available to the solar developer through 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. This arrangement allows public entities to utilize the benefits of 

the tax credits (low PPA price, higher lease payment) while not directly receiving them. 

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

5.5.3 Third-Party “Flip” Agreements

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

who then partners with a tax-motivated investor in a special purpose entity (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 investor’s interest in the 

project at the fair market value of the tax investor’s remaining interest. 

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

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

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

5.5.4 Hybrid Financial Structures

As the solar market has evolved, hybrid financial solutions have been developed in order 

to finance solar projects under certain circumstances. 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. 

5.5.5 Solar Services Agreement and Operating Lease

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

predominately used in the municipal and cooperative utility markets due to their 

treatment of tax benefits and the rules limiting federal tax benefit transfers from nonprofit to for-profit companies. Under IRS guidelines, municipalities cannot enter capital 

leases with 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 usually purchases the solar services 

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

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

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

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

cannot be used as a vehicle for a sale and must be a separate transaction).
28

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 “sales/leaseback.” Under 

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

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

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

fair market value.

5.5.6 Sales/Leaseback

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

the PV system, sell it to a tax investor, and then lease it back. As the lessee, the public or 

private entity would be responsible for operating and maintaining the solar system as well 

as have the right to sell or use the power. In exchange for use of the solar system, the 

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 as well as the lease payments. 

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

the tax benefits are exhausted. 

5.5.7 Community Solar/Solar Gardens

With the concept of “community solar,” 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 that 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 solar 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, customers receive billing credits for the number of 

kilowatt-hours their pro-rated shares of the solar project produce each month; this is also 

known as VNM. Under the customer subscription option, customers typically pay a set 

price for a block of solar energy (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 gardens and customer subscription-based projects can be solely owned 

by the utility, solely owned by third-party developers with facilitation of billing provided 

by the utility, or be a joint venture between the utility and a third-party developer leading 

to eventual ownership by the utility after the tax benefits have been absorbed by the thirdparty developer.
29

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). However, 

Georgia currently does not allow community solar or VNM. It would be a great 

opportunity to policy development in the community solar garden or VNM in the future.

Therefore, nearby communities or towns can take advantage of the solar PV project.
30

6 Conclusions and Recommendations 

The feasibility of installing a PV system is highly impacted by the available area for an 

array, solar resource, distance to transmission lines, and distance to major roads. The 

potential closest electrical tie-in location is at the Georgia Power substation at the 

southwest corner of the Deptford Tract. Having a substation on site makes it an ideal 

location for a PV system to tie into. The Tronox Facility site is a suitable location for a 

large-scale PV system because it is nearly flat, has adequate road and good solar access, 

is zoned for industrial uses, and has extensive electrical distribution to the whole site.

From the SAM analysis:

Case 1—Investor-owned/PPA will work if the investor can sell the electricity of the PPA 

at $0.1886/kWh. Because the retail rate of the electricity at $0.085/kWh is lower than 

PPA, the Tronox Facility is not likely to buy this electricity. In addition, Georgia Power’s 

purchase rate is estimated to be approximately $0.08/kWh. Therefore, a solar investor is 

unlikely to invest given current conditions.

Case 2—Developer-owned/PPA has negative NPV and shows the low LCOE of 

$0.089/kWh and payback period of 24 years. However, further analysis shows that NPV 

becomes positive if the utility has a purchase price of $0.135/kWh or above. Therefore, 

the project can be viable if the purchase rate is increased or the developer can negotiate 

for that rate.

Pursuing Case 3—PV system up to 100 kW, net-metering case is the best scenario 

economically. It has a positive NPV and a payback of approximately 14 years. This 

system could generate up to 132,000 kWh annually. We recommend the 100 kW netmetering project for each individual future building/site. 

Results of the JEDI analysis show that the total potential system of 8.5 MW is estimated 

to support 235 direct and indirect jobs per year for the duration of the procurement and 

construction period. Total wages paid to workers during the construction period are 

estimated to be $10,895,200, and total economic output is estimated to be $27,099,700. 

The annual O&M of the new PV system is estimated to support 3.2 FTEs per year for the 

life of the system. The jobs and associated spending are projected to account for 

approximately $176,200 in earnings and $307,900 in economic activity each year for the 

next 25 years.

Improvements to the incentives field could change these projects to very favorable. Such 

incentives would include an increase to the purchase price from Georgia Power, loan 

guarantees with longer repayment periods, and higher REC payments that would apply to 

larger systems.

A very large PV capacity can be installed at the Tronox Facility. Finding potential buyers 

for the generated electricity at a reasonable price, whether they are future Tronox 

industries or a local or interstate utility company, will be key to the project’s 

development. VNM would also be a good option to sell the excess electricity if the state 

allows. In addition, any environmental considerations shall be included in the RFP during 

project development.
31

Appendix A. Assessment and Calculations 

Assumptions

Table A-1. Cost, System, and Other Assessment Assumptions

Cost Assumptions

Variable Quantity of 

Variable

Unit of Variable

Cost of Site Electricity (buyback/retail) 0.080/0.085 $/kWh

Annual O&M (fixed) 20 $/kW/year

System Assumptions

System Type Annual energy 

kWh/kW

Installed Cost 

($/W)

Energy Density 

(W/sq. ft.)

Fixed-Tilt Ballasted System 1,311 $3.49 4.0

Other Assumptions

1 acre 43,560 ft2

1 MW 1,000,000 W

Ground utilization 90% of available 

area
32

Appendix B. Solar Access Measurements

Figure B-1. Solar access measurements for Tronox Facility PV site
33

Appendix C. Results of the JEDI Model

Table C-1. Summary Results of the NREL JEDI Model

Project Descriptive Data

Project Location Georgia

Population (only required for county/region analysis)

Year of Construction or Installation 2013

System Application Utility

Solar Cell/Module Material Crystalline Silicon

System Tracking Fixed Mount

Average System Size - DC Nameplate Capacity (kW) 8,500.0

Number of Systems Installed 1.0

Total Project Size - DC Nameplate Capacity (kW) 8,500.0 

Base Installed System Cost ($/kWDC) $3,490

Annual Direct Operations and Maintenance Cost ($/kW) $25.00

Money Value (Dollar Year) 2012

Local Economic Impacts - Summary Results

Jobs Earnings Output

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

Project Development and On-Site Labor Impacts

Construction and Installation Labor 41.7 $2,703.00

Construction and Installation Related Services 50.4 $2,303.40

Subtotal 92.2 $5,006.40 $8,239.90

Module and Supply Chain Impacts

Manufacturing Impacts 0.0 $0.00 $0.00

Trade (Wholesale and Retail) 9.9 $572.00 $1,648.10

Finance, Insurance, and Real Estate 0.0 $0.00 $0.00

Professional Services 14.3 $614.60 $2,075.10

Other Services 24.8 $1,662.10 $5,759.50

Other Sectors 35.2 $810.00 $1,717.90

Subtotal 84.2 $3,658.60 $11,200.60

Induced Impacts 59.0 $2,230.10 $7,659.30

Total Impacts 235.4 $10,895.20 $27,099.70
34

Annual Annual

Annual Earnings Output

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

On-Site Labor Impacts

PV Project Labor Only 2.0 $118.40 $118.40

Local Revenue and Supply Chain Impacts 0.7 $36.20 $115.40

Induced Impacts 0.6 $21.60 $74.10

Total Impacts 3.2 $176.20 $307.90

Notes: Earnings and output values are thousands of dollars in year 2012 dollars. 

Construction and operating period jobs are FTE 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 Georgia

Purchased Manufactured

Installation Costs Cost Locally (%) Locally (Y or N)

Materials and Equipment

Mounting (rails, clamps, fittings, etc.) $1,081,817 100% N

Modules $11,881,001 100% N

Electrical (wire, connectors, breakers, etc.) $1,233,455 100% N

Inverter $1,766,918 100% N

Subtotal $15,963,191

Labor

Installation $2,703,021 100%

Subtotal $2,703,021

Subtotal $18,666,212

Other Costs

Permitting $124,903 100%

Other Costs $2,760,355 100%

Business Overhead $8,113,529 100%

Subtotal $10,998,788

Subtotal $29,665,000

Sales Tax (materials and equipment purchases) $638,528 100%

Total $30,303,528
35

PV System Annual Operating and Maintenance Costs

Cost Local Share Locally (Y or N)

Labor

Technicians $127,500 100%

Subtotal $127,500

Materials and Services

Materials and Equipment $85,000 100% N

Services $0 100%

Subtotal $85,000

Sales Tax (materials and equipment purchases) $3,400 100%

Average Annual Payment (interest and principal) $3,441,140 0%

Property Taxes $0 100%

Total $3,657,040

Other Parameters

Financial Parameters

Debt Financing

Percentage Financed 80% 0%

Years Financed (term) 10

Interest Rate 10%

Tax Parameters

Local Property Tax (percent of taxable value) 0%

Assessed Value (percent of construction cost) 0%

Taxable Value (percent of assessed value) 0%

Taxable Value $0

Property Tax Exemption (percent of local taxes) 0%

Local Property Taxes $0 100%

Local Sales Tax Rate 4.00% 100%

Sales Tax Exemption (percent of local taxes) 0%

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%
36

Appendix D. Assumptions and Results of the 

System Advisor Model

Case 1: Investor owned/PPA with 8.5 MW

This case assumes a third-party investor for the PV system. All generated electricity from 

Case 1 is assumed to be sold. The results of this case are used to estimate the needed 

electricity rate as part of a PPA to get acceptable return on investment (15% internal rate 

of return). 

Case 2: Developer owned/PPA with 8.5 MW

This case assumes the developer owns the PV system. All generated electricity from 

Case 2 is assumed to be sold to Georgia Power at the avoided cost at $0.08/kWh. 

Case 3: Developer owned/net metering with 100 kW

This case assumes the developer owns the PV system; all electricity is assumed to be 

used on site.

Table D-1. Case 3 Results
37

Figure D-1. PV system output

Figure D-2. Levelized cost of energy
38

Figure D-3. After-tax cash flow

Assumptions for Inputs (For Case 3 as the best economic 

results)

Climate

Figure D-4. Climate input

Utility Rate

Figure D-5. Utility rate input
39

Financing

Figure D-6. Financing Input

Tax Credit Incentives

Figure D-7. Tax credit input
40

Payment Incentives

Figure D-8. Payment incentive input

Annual Performance

Figure D-9. Annual system performance input
41

PV System Costs

Figure D-10. PV system costs input
42

PVWatts Solar Array

Figure D-11. PVWatts solar array input