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Contract No. DE-AC36-08GO28308

Financing, Overhead, and 

Profit: An In-Depth Discussion 

of Costs Associated with 

Third-Party Financing of 

Residential and Commercial 

Photovoltaic Systems

David Feldman, Barry Friedman, and 

Robert Margolis

National Renewable Energy Laboratory

Technical Report

NREL/TP-6A20-60401

October 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

This report is available at no cost from the National Renewable Energy

Laboratory (NREL) at www.nrel.gov/publications.

Contract No. DE-AC36-08GO28308

National Renewable Energy Laboratory

15013 Denver West Parkway

Golden, CO 80401

303-275-3000 • www.nrel.gov

Financing, Overhead, and 

Profit: An In-Depth Discussion 

of Costs Associated with 

Third-Party Financing of 

Residential and Commercial 

Photovoltaic Systems 

David Feldman, Barry Friedman, and 

Robert Margolis

National Renewable Energy Laboratory

Prepared under Task No. SM13.0530

Technical Report

NREL/TP-6A20-60401

October 2013
NOTICE

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.

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Cover Photos: (left to right) photo by Pat Corkery, NREL 16416, photo from SunEdison, NREL 17423, photo by Pat Corkery, NREL 

16560, photo by Dennis Schroeder, NREL 17613, photo by Dean Armstrong, NREL 17436, photo by Pat Corkery, NREL 17721.

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

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Acknowledgments

The National Renewable Energy Laboratory (NREL) is a national laboratory of the U.S. Department of 

Energy (DOE), Office of Energy Efficiency & Renewable Energy, operated by the Alliance for 

Sustainable Energy, LLC., under Contract No. DE-AC36-08GO28308. 

The authors thank DOE for its sponsorship and direction of this work. We also appreciate the critical 

reviews of the following individuals, which greatly improved and informed the work: 

• David Arfin, First Energy Finance, LLC 

• Mark Bolinger, The Lawrence Berkeley National Laboratory 

• Sean Coletta, Clean Power Finance 

• Jason Coughlin, NREL

• Carolyn Davidson, NREL

• Ammar Qusaibaty, DOE 

• Uday Varadarajan, Climate Policy Initiative

• Jarett Zuboy, Consultant 
iv

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Executive Summary

Previous work quantifying the non-hardware balance-of-system costs—or soft costs—associated 

with building a residential or commercial photovoltaic (PV) system has left a significant portion 

unsegmented in an “other soft costs” category. This report attempts to better quantify the “other 

soft costs” by focusing on the financing, overhead, and profit of residential and commercial PV 

installations for a specific business model. There are many different business models in the PV 

marketplace, with varying cost structures; however, a common model was chosen to gain better 

insight of typical costs within the currently unsegmented “other soft costs” category. 

This report presents results from a bottom-up data-collection and analysis of the upfront costs 

associated with developing, constructing, and arranging third-party-financed residential and 

commercial PV systems. It quantifies the indirect corporate costs required to install distributed 

PV systems as well as the transactional costs associated with arranging third-party financing. It 

accompanies the recent National Renewable Energy Laboratory soft cost benchmarking report 

(Friedman et al. 2013), which quantifies all the non-hardware balance-of-system costs associated 

with building a residential or commercial PV system. 

We conducted in-depth interviews with members of financing departments at large PV 

installation companies on the subjects of third-party financing and overhead costs, and we

collected data from industry participants’ corporate public filings. From these inputs we designed 

and built a model intended to capture all direct and indirect costs of residential and commercial 

installations, using a specific business structure in which there is a power purchase 

agreement/lease customer; engineering, procurement, and construction (EPC) installer; 

developer; and tax-equity provider under a sale-leaseback transaction. This benchmark 

characterizes one of many possible business models—one in which the market participants are 

not vertically integrated but are separate entities.

For this corporate structure, adding all costs and margins together, a residential PV system would 

have had, in 2012, a total price of $4.52/W, and a commercial system would have a price of 

$3.66/W. Third-party-ownership-related costs add $0.78/W to a residential portfolio and 

$0.67/W to a commercial portfolio. However, this ignores three of the main benefits of thirdparty financing arrangements. First, third-party financiers offer additional services not included 

in the upfront cost of direct ownership. Second, while third-party financing costs may increase 

upfront costs, they may effectively lower the levelized cost of energy. Third, third-party 

businesses have gained significant market share in the United States, driving a considerable 

amount of PV demand. Without this volume of third-party customers, businesses are 

significantly less likely to operate efficiently, which would cause overhead costs to increase.
v 

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Table of Contents

1 Introduction ........................................................................................................................................... 1

2 EPC Installer.......................................................................................................................................... 5

3 Developer Costs ................................................................................................................................... 6

4 Transactional Costs ............................................................................................................................. 7

5 Total System Price ............................................................................................................................... 8

6 Margin versus Overhead.................................................................................................................... 10

7 Summary ............................................................................................................................................. 12

8 References .......................................................................................................................................... 15

Appendix A. EPC Installer Direct and Indirect Corporate Costs.......................................................... 16

Appendix B. Developer Direct and Indirect Corporate Costs............................................................... 18

Appendix C. Breakdown of Direct Costs and Margins.......................................................................... 20
vi 

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List of Figures

Figure 1. Organization chart of benchmarked business model............................................................. 3

Figure 2. Third-party residential system direct cost breakdown in 2012.............................................. 8

Figure 3. Third-party commercial system direct cost breakdown in 2012............................................ 9

Figure 4. Segmented residential PV system costs (“other soft costs” broken out).......................... 12

Figure 5. Segmented commercial PV system costs (“other soft costs” broken out)........................ 12

Figure 6. Percentage of residential PV capacity installed as third-party systems in select states . 13

List of Tables

Table 1. Pro-Forma Model Assumptions ................................................................................................ 10

Table 2. Summary of Pro-Forma Cash Flows to Tax-Equity Investor and System Developer.......... 11

Table A-1. Residential EPC Installer Direct and Indirect Corporate Costs in 2012............................ 16

Table A-2. Commercial EPC Installer Direct and Indirect Corporate Costs in 2012........................... 17

Table B-1. Developer Direct and Indirect Corporate Costs in 2012 ..................................................... 18

Table C-1. Breakdown of Direct Costs and Margins in 2012 ................................................................ 20
1 

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at www.nrel.gov/publications.

1 Introduction

The median price of residential and commercial photovoltaic (PV) systems fell in 2012 and has 

fallen 8 of the last 10 years, according to research from the Lawrence Berkeley National 

Laboratory (Barbose et al. 2013). Much of this price reduction has been attributed to reductions 

in hardware costs, such as module price, which has fallen by 78% in the past 10 years (Barbose 

et al. 2013). Non-hardware costs (or “soft costs”) have thus become a larger percentage of total 

system costs, and more efforts have been made to understand and reduce them. In the National 

Renewable Energy Laboratory (NREL) soft cost benchmarking report (Ardani et al. 2012), 55%-

88% of benchmarked 2010 soft costs were categorized in the unsegmented category of “other 

soft costs,” leaving a significant portion not well defined or understood. This report attempts to 

better quantify the “other soft costs” by focusing on financing, overhead, and profit for 

residential and commercial PV installations. The results are incorporated in the second edition of 

the soft cost benchmarking report (Friedman et al. 2013).1 

Financing, overhead, and profit can become particularly complicated when systems are financed 

through a third party, such as through solar leases and power purchase agreements (PPAs), in 

which there are more parties involved in the transaction than are involved in a direct sale. 

Because third-party financing has become the dominant business model in much of the United 

States [responsible for approximately 68% of all U.S. residential systems installed during 2012 

(Kann 2013)], it is even more important to understand the costs associated with this 

business model. 

Before quantifying these costs we will define some financial terms in relation to the cost of a PV 

system; these terms are typically used in financial statements to provide information on the 

financial position of a company.2 PV system costs include costs directly associated with building 

the system and the long-term, total cost that a business incurs related to the system (i.e., all 

indirect costs). The direct costs of a project can be best compared to the “cost of goods sold” 

(COGS) line item in a company’s income statement, or the direct costs attributable to the 

production of goods sold. In the case of a PV system, these costs include the hardware (e.g., 

modules, inverters, and racking) and all labor and other costs associated with building the 

specific project (e.g., installation labor, system design, and permitting). The COGS plus a gross 

margin equals the price of a project, or the revenue a company receives. For example, if the 

COGS of a PV system is $4/W and the gross margin is 25%, the gross profit would be $1/W and 

the system price would be $5/W (or $5/W in total revenue to the company). 

The indirect “operating” fixed costs to a business can be best compared to selling, general, and 

administrative expenses (SG&A).3 SG&A can be defined as the costs of operating a business not 

 

1 Some of the assumptions in this report differ from the assumptions in Friedman et al. (2013), thus the results 

between the two reports are not directly comparable. See Friedman et al. (2013) for an explanation of how the 

numbers in this report were translated into the other report.

2 Many of these terms are defined in the general accepted accounting principles (GAAP), which are a common set of 

accounting principles, standards, and procedures used for U.S. companies in their financial statements. They may 

have slightly different definitions from those above; however, they are generally consistent in spirit. 

3 SG&A, overhead, and non-direct costs are all terms used loosely to describe similar costs on an income statement. 

Generally, although not always, they refer to the ongoing costs of operating a business.
2 

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at www.nrel.gov/publications.

related to the production of a good. Examples of this would include an installer’s office space, 

sales staff, and its human resources (HR) department. In an efficient, long-term business model, 

the margin over COGS should equal SG&A plus a sustainable operating profit.4 Operating profit 

allows a company to return money back to investors or make strategic investments. For example, 

if the gross profit of a PV system is $1/W and a company’s SG&A spread over all its sold 

systems is $0.5/W, then the company would have an operating profit of $0.5/W. 

In growing, hypercompetitive businesses or over short time horizons, a company might not be 

able to fund SG&A through revenue fully; however, if SG&A is not fully funded in the long 

term, such a company would likely go out of business. 

The benchmarking analysis in Friedman et al. (2013) generally includes SG&A and COGS.5 For 

example, an engineer’s time associated with design of a particular system is classified as COGS, 

but not the engineer’s time associated with designing systems that do not move forward. Gross 

profit, or—in the case of a growing or unhealthy company—existing corporate cash, must cover 

SG&A. Therefore, SG&A must be discussed in parallel with gross profit.

To gain a better understanding of all the costs associated with building a PV system, we modeled 

a prevalent business arrangement that captures the direct and indirect costs of a company 

operating a business that installs residential and commercial PV systems. To build the model, we 

conducted in-depth interviews with members of financing departments at large PV installation 

companies on the subjects of third-party financing and overhead costs, and we collected data 

from industry participants’ corporate public filings. There are many different business models in 

the PV marketplace,6 but we chose the business structure in Figure 1 for three primary reasons: 

to show the additional cost categories of third-party installations, to better represent the specific 

costs of each activity by avoiding a vertically integrated structure, and to demonstrate a business 

model that is currently common in the marketplace.

 

4 There are other, non-operating costs to a company that concern the financing and investment of a company. We 

focus only on operating costs.

5 SG&A expenses are ineligible inclusions in the cost basis reported to the Treasury Department or the Internal 

Revenue Service for purposes of the 1603 cash grant or investment tax credit. However, some COGS costs are 

ineligible, such as permanent loan fees, syndication costs, and roof repair. It should be noted that the cost plus 

margin approach detailed in this report is not the only way in which the basis of a project is reported to the Treasury 

Department (e.g., 1603) or the Internal Revenue Service (e.g., ITC), particularly in cases involving related parties. 

As summarized in “Evaluating Cost Basis for Solar Photovoltaic Properties (Treasury 2011),” the Treasury 

Department accepts three different ways of calculating the “fair market value”: the cost approach, “based on the 

actual cost to build the property”; the market approach, “based on sales of comparable properties”; and the income 

approach, “based on the discounted value of future cash flows generated by and appropriately allocable to the 

eligible property.” In the latter two approaches, cash flow is more relevant than cost. 6 For example, SolarCity acts as the lead generator/sales staff, the EPC installer, and the developer, while Clean 

Power Finance works with partners to perform sales and installation, such as Real Goods Solar. There are also 

several different financing models other than the sale leaseback approach, such as the partnership-flip structure and 

the inverted lease structure.
3 

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at www.nrel.gov/publications.

Figure 1. Organization chart of benchmarked business model7

In this business structure, the developer signs a PPA with a building owner, contracts the 

construction of the system with a separate engineering, procurement, and construction (EPC)

installer, and finances a portfolio of systems (we assume 10 MW of residential or commercial 

systems) through a sale-leaseback arrangement with a tax-equity investor. For larger, nonresidential projects, a separate financier may be brought on to fund construction of these assets 

before they are sold to the tax-equity investor at the projects’ placed-in-service dates. Further, 

non-recourse term debt may be raised to fund part of the portfolio, depending largely on the tax 

equity investor’s minimum investment size threshold; in other words, the debt must not exceed 

an amount that would reduce the tax equity portion to a level below that threshold.8

Because some companies currently in the marketplace are vertically integrated, many of these 

functions can be performed by the same participant or handled at different points of the value 

chain. For example, developers may perform lead generation and sales, or the EPC installers may 

accomplish this task. This benchmark attempts to characterize one of many possible business 

models—one in which the market participants are not vertically integrated but are separate 

entities.9

 Inputs to and design of this model are based on discussions from multiple industry 

participants involved in third-party PV financing as well as data from corporate public filings 

and vetting and review by external stakeholders. 

The previously discussed portfolio of assets includes direct costs in three categories: (1) direct 

project costs, such as PV hardware costs, installation labor, and permitting fees; (2) transactional 

costs, which include fees by parties other than the EPC installer or system developer to arrange 

financing; and (3) EPC installer and system developer corporate costs, defined as staff time 

 

7 The labels “up” and “down” represent the direction in which the benefits flow between the relevant two parties. 8 Tax equity investors typically require a higher rate of return when subordinating themselves to debt and making a 

smaller investment. The unlevered (i.e., no debt) rate of return for tax equity is estimated to be between 8% and 

10%, versus a levered financial arrangement in which tax equity requires 10% to 12%.

9

 While there is potential for cost reductions through vertical integration of the EPC installer and integrator, each has 

a separate value proposition. Therefore, if the companies operate efficiently, they should have the same cost 

structure before and after consolidation.

Organization Chart of Benchmarked Business Model

Developer

Down arrow: Purchases solar asset; lease 

agreement to allow use of asset

Up arrow: Sells solar asset; lease payments 

for use of asset

Building Owner / Utility EPC Installer

Down arrow: electricity

Up arrow: PPA payments

Tax Equity Term Debt Construction Debt

Down arrow: Purchase solar asset

Up arrow: PV System

Down arrow: Funds to construct solar asset

Up arrow: principal, interest, and fees

Arrows represent 

transfer of value
4 

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associated with specific projects. Appendix C summarizes these direct costs (plus margin), and 

Appendix A and Appendix B detail the direct corporate costs of the EPC installer and system 

developer, respectively. In addition to direct costs, the EPC installer and system developer have 

indirect costs associated with the previously discussed portfolio of assets. Appendix A and 

Appendix B also summarize these indirect corporate costs (in red), including business expenses, 

such as rent and office supplies and staff time not directly associated with projects. The results 

should be treated as representative of general trends in 2012 and not specific to any company. 

The following sections detail the costs listed in the tables through the following categories: EPC 

installer, developer costs, transactional costs, and total system price. 
5 

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2 EPC Installer

The EPC installer in the model is assumed to build 12 MW of residential or commercial PV 

systems per year (in contrast to the 10 MW10 of systems in the sold portfolio and the 70 MW of 

systems developed by the developer).11 Office rent, equipment and supplies, insurance, taxes, 

vehicles, dues, and memberships, as well as corporate professional services such as accountants 

and lawyers, are estimated as non-staff corporate overhead, a subset of SG&A. In addition, 

estimates are made of staff expenses, such as corporate positions (CEO, HR, legal), sales and 

marketing, design and engineering, and project managers; percentages are also determined to 

proportionally allocate costs between those that are directly and indirectly related to projects.

Finally, a 35% increase is added to base salaries to account for benefits, FICA,12 and salary 

bonuses. These costs for residential systems total $3.2 million, or $0.27/W, of indirect costs (i.e., 

SG&A, overhead) and $2.2 million, or $0.19/W, of direct costs (Appendix A, Table A-1). These 

costs for commercial systems total $2.2 million, or $0.18/W, of indirect costs (i.e., SG&A, 

overhead) and $1.8 million, or $0.15/W, of direct costs (Appendix A, Table A-2). 

 

10 The 2 MW difference between the EPC installer volume of 12 MW and the portfolio size of 10 MW includes 

separate transactions, such as host-owned systems. 11 The sales volume (MW) by EPC installer and integrator, and the size of portfolio, are indicative of companies and 

projects in the underlying data used to generate report. 

12 FICA is the Federal Insurance Contributions Act payroll tax that funds Social Security and Medicare.
6 

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3 Developer Costs

The developer is assumed to install 70 MW of residential or commercial PV systems per year. 

Like the EPC installer, office rent, equipment and supplies, insurance, taxes, vehicles, dues, and 

memberships, as well as corporate professional service such as accountants and lawyers, are 

estimated as corporate overhead. However, it is also assumed that consultants, recruiters, and 

lobbyists are necessary, as well as the cost of purchasing a billing system, which is prorated over 

a 5-year period. 

There are also significantly more operational requirements at the corporate level for a developer 

than an EPC installer. In addition to a larger corporate staff of executives and HR, as well as a 

legal team, there is also a finance team, which handles corporate treasury duties, project finance 

arrangements, compliance, and accounting. There are also sales, marketing, and EPC sales 

management teams that develop PPA customer portfolios. A design and engineering department, 

supply chain management team, rebate interconnection team, and project management team 

shepherd the PV projects from design, procurement of equipment, and construction of project to 

system interconnection to the grid. Finally, once the PV projects are in operation, the software/IT 

department (which also handles general corporate needs and customer acquisition) and the 

customer service department monitor, bill, and interact with customers. Percentages were

determined to proportionally allocate costs directly and indirectly related to projects. A 35% 

increase is again added to salaries to account for benefits, FICA, and salary bonuses. These costs 

total $53.2 million, or $0.76/W, of indirect costs (i.e., SG&A, overhead) and $16.5 million, or 

$0.24/W, of direct costs, for both commercial and residential systems (Appendix B).
7 

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4 Transactional Costs

Structuring financing for a PV asset involves arranging, negotiating, and contracting agreements 

between two or more parties. These transactions are designed to allocate the benefits of a PV 

system to entities that can use them, at the lowest cost possible. The tax-equity investor is 

brought into the deal to utilize the investment tax credit and depreciation benefits; debt is raised 

to fund a portion of the project at a lower cost than the rate of return required for equity; and, in 

the case of large commercial systems with long construction timelines, construction debt is 

raised to minimize risk to the tax-equity investor during construction. All of these companies 

serve a purpose, but they come at a cost.

Before an arrangement can be put in place, the purchasers of the assets (tax-equity) must validate 

what they are buying from the developer.13 It was assumed that an auditor is hired to assess the 

residential portfolio; in a portfolio of commercial systems, use of independent engineers is

assumed. Lawyers on both sides of the transaction (tax-equity and developer) are needed to 

negotiate the necessary contracts, although the developer typically pays both fees. Accountants 

are also often necessary to validate the financial records of a project and/or developer. Our 

modeled results for professional service costs, summarized in Appendix C, yielded $0.05/W for 

residential and $0.06/W for commercial.

Banks that offer term debt typically charge a fee to set up the transaction. In addition, in the case 

of construction debt for commercial projects, an arranging fee is charged as well as interest on 

the loan during construction (which can be added to the cost basis of a project for tax purposes). 

Our modeled results for debt fees (and interest), summarized in Appendix C, yielded $0.04/W 

for residential and $0.08/W for commercial.

There are also provisions that developers must make to minimize the risk to investors and PPA 

customers in the transaction. The value of extended inverter warranties that last the life of the 

contract, and system production guarantees made to the end-user, which are all often necessary 

for third-party ownership, come at a cost.14 In addition, debt providers often require that money 

is set aside to cover payments (debt service reserve) in case of revenue variability, and tax-equity 

investors often require that developers set aside money to cover Operations and Maintenance 

(O&M) costs (O&M reserve). These reserves are not eligible for inclusion in a project’s cost 

basis, but funds are still necessary. Our modeled results for the additional costs (without 

reserves), summarized in Appendix C, yielded $0.12/W for residential and $0.10/W commercial. 

Our modeled results for the capital reserves yielded $0.05/W for both residential and commercial

systems. 

In total, the transaction costs to set up and construct a 10-MW residential portfolio and a 10-MW 

commercial portfolio, summarized in Appendix C, were modeled to be $0.21/W and $0.24/W, 

respectively (excluding capital reserves).

 

13 This model assumes that the integrator, after purchasing the system from the EPC installer, immediately sells the 

system to the tax-equity provider. 14 Some of these costs are also borne when the system is sold directly to the end user.
8 

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5 Total System Price

Project costs such as hardware, construction labor,15 and permitting are based on NREL’s 

bottom-up reported benchmarks, as detailed in Feldman et al. (2013). When added to liability

insurance during construction and the direct EPC installer staff costs summarized above and in

Appendix A, they total $2.92/W for residential PV systems and $2.50/W for commercial systems 

(Appendix C). A margin of 20% is charged for residential systems and 10% for commercial 

systems, making the system price to the developer $3.50/W for residential ($0.58/W margin) and 

$2.76/W for commercial ($0.25/W margin). The margin on a commercial system is typically less 

than that of a residential system as overhead is cheaper on a per watt basis and there is more 

competition, driving prices lower.

The developer also has staff costs directly related to the project, such as design and engineering, 

project management, and sales. Once they have structured the financial transaction, the 

developer sells the system to the tax-equity provider, with a 15% margin on all their direct costs 

associated with the project (including items purchased from the EPC installer).16 For this given 

corporate structure, adding all costs and margins together, a residential PV system would have a 

total system price of $4.52/W, and a commercial system would have a system price of $3.66/W. 

Adding cash reserves of $0.05/W (residential) and $0.05/W (commercial), the amount increases 

to $4.58/W (residential) and $3.71/W (commercial) (Figure 2 and Figure 3).

Figure 2. Third-party residential system direct cost breakdown in 2012

 

15 In Feldman et al. (2013), construction labor’s marked-up costs (to account for FICA, etc.) are included in its 

overhead costs, which are calculated differently in this report. Therefore, this report added an additional 35% lineitem cost to account for this discrepancy.

16 This also may be labeled a “development fee.” The Internal Revenue Service usually allows a development fee at 

a maximum of 15% of the cost of the project to the integrator.

 $2.73 

$0.19 

$0.24 

$0.58 

$0.57 

$0.06 

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

$4.00

$4.50

$5.00

System Cost EPC Transaction Costs Integrator

Cost Per Watt

Capital Reserves

Insurance, Warranties, Etc.

Professional Services

Financier Expenses

Gross Margin

Direct Project Costs (corporate)

Project Costs (material, labor, etc.)

$0.21
9 

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Figure 3. Third-party commercial system direct cost breakdown in 2012

 $2.36 

$0.15 

$0.24 

$0.25 

$0.43 

$0.05 

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

$4.00

$4.50

$5.00

System Cost EPC Transaction Costs Integrator

Cost Per Watt

Capital Reserves

Insurance, Warranties, Etc.

Professional Services

Financier Expenses

Gross Margin

Direct Project Costs (corporate)

Project Costs (material, labor, etc.)

$2.50

$0.24
10 

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6 Margin Versus Overhead

As mentioned previously, overhead costs are typically funded in a company through the margin 

it charges on the cost of its product. In the case of the EPC installer, the profit margins charged 

for residential and commercial systems were $0.58/W and $0.25/W, respectively, for the 

transaction modeled (Appendix C). EPC installer indirect corporate costs (i.e., SG&A) for a 

residential system were calculated in Appendix A to be $0.27/W (the $0.19/W direct costs are 

paid from the sale of the assets), which would provide a positive operating profit of $0.32/W (an 

operating margin of 9%). EPC installer indirect corporate costs (i.e., SG&A) for a commercial

system were calculated in Appendix A to be $0.18/W (the $0.15/W direct costs are paid from the 

sale of the assets), which would provide a positive operating profit of $0.06/W (an operating 

margin of 2%). The lower operating margin for a commercial system can be attributed to the 

necessity of charging a lower system price due to such factors as increased competition and 

lower electricity pricing (compared to the residential market). 

The developer also charges a mark-up in its sale of the asset to the tax-equity investor in a saleleaseback transaction, which was calculated in Appendix C to be $0.57/W for a residential 

system and $0.43/W for a commercial system. These fees are $0.19/W and $0.33/W less than the 

$0.76/W of indirect corporate costs by the developer for residential and commercial systems, 

respectively ($0.24/W of direct costs are paid from the sale of the assets) (Appendix B). 

However, developers typically also receive money after a system is placed in service through 

partial ownership or leasing of the equipment. Therefore, they are more concerned with a PV 

project pro-forma satisfying its requirements to stakeholders than the cost of a project. In other 

words, a developer’s priority is for the PPA revenues and tax benefits (and any other benefits) to 

provide the tax-equity investor, debt holder, and other equity holders with their required returns. 

In order to validate the cost model benchmarks in Appendix C, a pro-forma was created for a 

residential system, with consistent assumptions summarized in Table 1. 

Table 1. Pro-Forma Model Assumptions 

System size 5.1 kWDC

Total system price $4.52/WDC

Term Tax-equity

Capital structure (%) 40% 60%

Capital structure ($/W) $1.81 $2.71

Term debt interest rate 7.0%

Term of loan 12 years

Tax-equity investor required 12.0%

Production factor 1,750 kWh/kW

Annual degradation factor 0.5%

PPA price $0.21/kWh

PPA term 20 years

O&M Costs $23.50/kW per year

PPA and O&M cost escalator 3.5% per annum

ITC Rate 30%

Federal & state depreciation 5 year MACRS

State tax rate 8%
11 

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at www.nrel.gov/publications.

Federal tax rate 35%

Model assumes developer purchases project from taxequity investor in year 6 for 20% of the original system 

price. No assumed state incentives.

The pro-forma modeled cash flows, over the 20-year life of the PPA, to the tax-equity investor 

and the developer are summarized in Table 2. 

Table 2. Summary of Pro-Forma Cash Flows to Tax-Equity Investor and System Developer 

Net present value17 ($/W)

Tax-equity investor (lessor)

Initial investment (Year 0) -$2.71

Lease payments (Y1-Y6) $1.41

Buyout (Y6) $0.46

Total revenue $1.87

Interest (Y1-Y6) -$0.22

State taxes (Y1-Y6) $0.1718

Federal taxes (Y1-Y6) $0.70

Debt principle (Y1-Y6) -$1.18

Total expenses -$0.51

ITC (Y0) $1.36

NPV of after tax cash flow $0.00

After tax IRR 12.0%

Developer (lessee)

Electricity revenue (Y1-Y20) $2.72

Total revenue $2.72

Buyout (Y6) -$0.39

Operating expenses (O&M, insurance, management) (Y1-Y20) -$0.18

Lease payments to tax-equity (Y1-Y6) -$1.30

Total expenses -$1.87

Operating profit (revenue – expense) $0.85

Margin from sale to tax-equity investor (Y0), from Appendix 

 $0.57

Project cash flow (operating profit + margin from sale) $1.43

Developer indirect costs, from Appendix B -$0.76

Total developer cash flow (project cash flow – indirect $0.67

As presented in Table 2, the project modeled in the pro-forma was able to satisfy all debt and 

equity stakeholders and provide the developer with a net present value of $0.85 /W over a 20-

year PPA life (assuming a 15% discount rate). When accounting for both the margin on the sale 

of the asset and the profit from operations, the developer achieves $1.43/W in value, or $0.67/W 

more than all indirect corporate costs.

 

17 The tax-equity investor’s cash flows are discounted to present value at a rate of 12%; the integrator’s cash flows 

are discounted to present value at a rate of 15%. These discount rates are based on the required rate of return 

necessary, as indicated by current market conditions

18 Federal and state tax expenses are positive due to the PV asset’s depreciation schedule and interest expense.
12 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 

at www.nrel.gov/publications.

7 Summary

In this business model, residential systems' “other soft costs” contribute $1.79/W out of a total 

$4.52/W (40%), which is further segmented in Figure 4. Commercial systems' “other soft costs” 

contribute $1.14/W out of a total $3.66/W (36%), which is further segmented in Figure 5. 

Figure 4. Segmented residential PV system costs (“other soft costs” broken out)

Figure 5. Segmented commercial PV system costs (“other soft costs” broken out)

Of the "other soft costs," third-party-ownership-related costs—namely the addition of the 

developer’s margin (which partially covers its indirect costs) and transaction costs—add 

$0.78/W to a residential portfolio ($0.57/W developer margin and $0.21/W transactions costs, 

see Appendix A) and $0.67/W to a commercial portfolio ($0.43/W developer margin and 

Module $1.03 

Inverter 

$0.43 

Instal. materials $0.44 

Instal. labor (fully 

loaded) $0.74 

Permit, intercon. & 

insurance fees $0.09 

EPC direct project costs 

(corporate) $0.19 

Dev. direct project 

costs (corporate) $0.24 

EPC Margin $0.58 

Developer 

Margin $0.57 

Transaction costs $0.21 

Other soft costs 

$1.79 

Module $1.03 

Inverter $0.29 

Instal. materials $0.63 

Instal. labor (fully 

loaded) $0.38 

Permit, intercon. & 

insurance fees $0.03 

EPC direct project costs 

(corporate) $0.15 

Dev. direct project 

costs (corporate) $0.24 

EPC Margin $0.25 Developer 

Margin $0.43 

Transaction costs $0.24 

Other soft costs 

$1.14 
13 

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at www.nrel.gov/publications.

$0.24/W transactions costs, see Appendix A).19 However, this ignores three of the main benefits 

of third-party financing arrangements. First, third-party financiers offer additional services not 

provided by direct ownership. A customer does not have to dedicate the resources to purchasing 

a system, worry about its O&M, or apply for and receive any incentives (ITC, state/regional 

rebates, RECs, etc.). Second, while there are transactional costs associated with multiple parties 

financing projects, this is done to (1) properly allocate the benefits (e.g., a tax-equity provider 

can utilize the tax credits and depreciation deductions) and (2) lower the capital cost (e.g., term 

debt has a lower required rate of return than an equity provider); these effectively lower the cost 

of electricity, which has more economic impact to a consumer than the upfront cost. Third, thirdparty businesses have gained significant market share in the United States, driving a considerable 

amount of PV demand. Figure 6 shows the percentage of PV capacity installed as third-party 

systems in four select states.

Figure 6. Percentage of residential PV capacity installed as third-party systems in select states 

Without this volume of third-party customers, EPC installers are significantly less likely to 

operate efficiently, which will cause overhead costs to increase. For example, in Arizona, 

approximately 90% of the systems installed during 2012 and through the first half of 2013 were 

third-party owned. Without the third-party option, it is likely that fewer customers would be 

willing to purchase PV systems (e.g., due to first cost barriers), and the market would shrink 

considerably, possibly driving up overhead costs to EPC installers on a per-watt basis. The 

model calculates that the indirect overhead for an EPC installer who builds 12 MW of residential 

 

19 The direct costs incurred by the integrator are not included in this calculation because they would also be required 

for a direct sale. In that situation, those activities would most likely be handled by an EPC installer instead. Also, 

while there is potential for cost reductions through vertical integration of the EPC installer and integrator, each has a 

separate value proposition. Therefore, if the companies operate efficiently, they will have the same cost structure 

before and after consolidation.

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Q3 '10 Q4 '10 Q1 '11 Q2 '11 Q3 '11 Q4 '11 Q1 '12 Q2 '12 Q3 '12 Q4 '12 Q1 '13 Q2

'13*

% of Installed Capacity

Residential Systems

AZ CA

MD MA

*Data only captures portion of quarter
14 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 

at www.nrel.gov/publications.

systems a year is $3.2 million, or $0.27/W. If the EPC installer’s sales volume decreased, 

overhead costs could increase dramatically.

20 

As discussed, differences in companies’ sales volume can have a large impact on indirect costs.21

This may partially explain the differences in measurements of system pricing. For example, the 

above model estimates that, in 2012, the installed price of a residential system was $4.52/W, 

compared to the median reported price of $5.22/W calculated by Tracking the Sun VI (Barbose et 

al. 2013) based on installer-reported system prices. If the EPC installer and system developers 

who contributed information to Tracking the Sun VI have median sale volumes that are lower 

than those in the model, but have the same costs, they would have higher costs per watt. Due to 

these higher costs, EPC installers and system developers may need to charge higher gross 

margins, thus raising the system price. In addition, gross margins may be higher than those 

modeled in areas of the United States because of market factors, such as high local electricity 

prices or lack of competition, translating into higher profits to the EPC installer and system 

developers.22 As the industry matures and the U.S. PV market grows (as it is projected to do in 

the next few years), and as companies with uncompetitive business models exit the marketplace, 

overhead costs and margins will come down on their own. However, because of third-party 

ownership’s value propositions, as outlined above, developers may still be a necessary part of a 

transaction, regardless of price.

 

20 Practically speaking, an EPC installer would cut its overhead with a decrease in sales; however, because there are 

large economies of scale in overhead, their costs would most likely still be higher, on a per-watt basis. 21 Sales volume can also impact direct costs through stronger purchasing power. 22 Developers may also be able to charge higher margins based on their method of reporting “fair market value” to 

the IRS or Treasury. In instances in which fair market value is based on the future cash flows of a project, instead of 

the cost, margin is not reported. However, the ability of a developer to charge high margins is still dependent on lack 

of competition, high electricity prices, and related party transactions.
15 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 

at www.nrel.gov/publications.

8 References

Ardani, K.; Barbose, G.; Margolis, R.; Wiser, R.; Feldman, D.; Ong, S. (2012). Benchmarking 

Non-Hardware Balance of System (Soft) Costs for U.S. Photovoltaic Systems Using a DataDriven Analysis from PV Installer Survey Results. NREL/TP-7A20-56806. Golden, CO: 

National Renewable Energy Laboratory. 

Barbose, G.; Darghouth, N.; Wiser, R. (2013). Tracking the Sun VI: An Historical Summary of 

the Installed Cost of Photovoltaics in the United States from 1998 to 2012. Berkeley, CA: 

Lawrence Berkeley National Laboratory.

Feldman D.; Barbose, G.; Margolis, R.; Darghouth, N.; James, T.; Weaver, S.; Goodrich, A.; 

Wiser. R. (2013). Photovoltaic System Pricing Trends: Historical, Recent, and Near-Term 

Projections. 2013 Edition. NREL/PR-6A20-60207. Golden, CO: National Renewable Energy 

Laboratory. 

Friedman, B.; Ardani, K.; Feldman, D.; Margolis, R.; Citron, R.; Zuboy, J. (2013). 

Benchmarking Non-Hardware Balance-of-System (Soft) Costs for U.S. Photovoltaic Systems, 

Using a Bottom-Up Approach and Installer Survey – Second Edition. NREL/TP-6A20-60412. 

Golden, CO: National Renewable Energy Laboratory. 

Kann, S. (2013). U.S. Residential Solar PV Financing: The Vendor, Installer and Financier 

Landscape, 2013–2016. Boston: GTM Research. 

Treasury Department. (June 2011). “Evaluating Cost Basis for Solar Photovoltaic Properties.” 

Accessed August 27, 2013: 

http://www.treasury.gov/initiatives/recovery/Documents/N%20Evaluating_Cost_Basis_for_Sola

r_PV_Properties%20final.pdf.
16 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 

at www.nrel.gov/publications.

Appendix A. EPC Installer Direct and Indirect

Corporate Costs 

Table A-1. Residential EPC Installer Direct and Indirect Corporate Costs in 2012 

Indirect Corporate Overhead

Business Expenses $/year $/W

Rent (98 sq ft/person) $13.75/sq ft $60,420 $0.01

Office expenses (equipment, 

supplies, maintenance, 

phones)

$5,000/person $225,000 $0.02

Corp. professional service (accountants, lawyers) $258,120 $0.02

Insurance $30,000 $0.00

Other (business taxes, bank fees) $20,000 $0.00

Vehicle fees (lease, gas, insurance) $20,000 $0.00

Dues and memberships $20,000 $0.00

Staff Expenses

Base Salary 

(unburdened) 

/ person

# of 

employees

Employe

e per MW 

installed

Time not

assoc. 

w/direct 

proj. cost

(Base 

Salary + 

Benefits) × 

% of time

Corporate (senior) $200,000 2 0.17 100% $540,000 $0.05

Corporate (junior) $55,000 3 0.25 80% $178,200 $0.01

Design and engineering $65,000 12 1.00 50% $526,500 $0.04

Sales and marketing $80,000 24 2.00 50% $1,296,000 $0.11

Project managers $75,000 4 0.33 10% $40,500 $0.00

Total employees 45 3.75 $2,581,200 $0.22

Benefits, FICA, bonus 

(added to base salary) 35%

Total indirect corporate costs (staff + business expenses) $3,214,740 $0.27

Direct Corporate Overhead

Staff Expenses

Base Salary 

(unburdened) 

/ person

# of 

employees

Employe

e per MW 

installed

Time 

assoc. 

w/direct 

proj. cost

(Base 

Salary + 

Benefits) × 

% of time

Corporate (junior) $55,000 3 20% $44,550 $0.00

Design and engineering $65,000 12 50% $526,500 $0.04

Sales and marketing $80,000 24 50% $1,296,000 $0.11

Project managers $75,000 4 90% $364,500 $0.03

Total direct corporate staff costs $2,231,550 $0.19

MW installed by EPC installer per year 12
17 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 

at www.nrel.gov/publications.

Table A-2. Commercial EPC Installer Direct and Indirect Corporate Costs in 2012

Indirect Corporate Overhead

Business Expenses $/year $/W

Rent (98 sq ft/person) $13.75/sq ft $41,586 $0.00

Office expenses (equipment, 

supplies, maintenance, 

phones)

$5,000/person $154,865 $0.01

Corp. professional service (accountants, lawyers) $175,760 $0.01

Insurance $30,000 $0.00

Other (business taxes, bank fees) $20,000 $0.00

Vehicle fees (lease, gas, insurance) $20,000 $0.00

Dues and memberships $20,000 $0.00

Staff Expenses

Base Salary 

(unburdened) 

/ person

# of 

employees

Employe

e per MW 

installed

Time not

assoc. 

w/direct 

proj. cost

(Base 

Salary + 

Benefits) × 

% of time

Corporate (senior) $200,000 3 0.23 100% $760,247 $0.06

Corporate (junior) $55,000 2 0.18 80% $125,441 $0.01

Design and engineering $65,000 7 0.59 50% $308,851 $0.03

Sales and marketing $80,000 8 0.70 50% $456,148 $0.04

Project managers $75,000 11 0.88 10% $106,910 $0.01

Total employees 31 2.58 $1,757,597 $0.15

Benefits, FICA, bonus 

(added to base salary) 35%

Total indirect corporate costs (staff + business expenses) $2,219,808 $0.18

Direct Corporate Overhead

Staff Expenses

Base Salary 

(unburdened) 

/ person

# of 

employees

Employe

e per MW 

installed

Time 

assoc. 

w/direct 

proj. cost

(Base 

Salary + 

Benefits) × 

% of time

Corporate (junior) $55,000 2 20% $31,360 $0.00

Design and engineering $65,000 7 50% $308,851 $0.03 

Sales and marketing $80,000 8 50% $456,148 $0.04

Project managers $75,000 11 90% $962,188 $0.08

Total direct corporate staff 

costs $1,758,547 $0.15

MW installed by EPC installer per year 12
18 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 

at www.nrel.gov/publications.

Appendix B. Developer Direct and Indirect Corporate 

Costs

Table B-1. Developer Direct and Indirect Corporate Costs in 2012

Indirect Corporate Overhead

Business Expenses $/year $/W

Rent (98 sq ft/person) $28.92/sq ft $1,519,262 $0.02

Office expenses (equipment, supplies, 

maintenance, phones) $5,000/person $2,689,928 $0.04

Corp. professional service (accountants, 

lawyers, consultants, recruiting, lobbying) $4,353,589 $0.06

Insurance $30,000 $0.00

Other (business taxes, bank fees) $20,000 $0.00

Vehicle fees (lease, gas, insurance) $913,172 $0.01

Dues and memberships $20,000 $0.00

Billing system (prorated over 5 years) $100,000 $0.00

Staff Expenses

Base Salary 

(unburdened) / 

person

# of 

employee

s 

Employees 

per MW 

installed

Time not

assoc. 

w/direct 

proj. 

cost

(Base 

Salary + 

Benefits) × 

% of time

Corporate - senior (c-level, HR & legal) $185,000 22.5 0.32 100% $5,611,798 $0.08

Corporate - junior (c-level, HR & legal) $75,000 13.8 0.20 100% $1,400,033 $0.02

Finance - senior (treasury, project finance, 

accounting, compliance) $185,000 10.4 0.15 100% $2,590,061 $0.04

Finance - junior (treasury, project finance, 

accounting, compliance) $75,000 34.6 0.49 100% $3,500,082 $0.05

Design and engineering $75,000 66.4 0.95 50% $3,359,415 $0.05

Supply chain $75,000 6.9 0.10 100% $700,016 $0.01

Software/IT $85,000 49.3 0.70 100% $5,656,103 $0.08

Rebate/interconnection $75,000 20.4 0.29 100% $2,065,109 $0.03

Project management $75,000 42.5 0.61 10% $430,231 $0.01

Customer service $75,000 17.0 0.24 100% $1,720,924 $0.02

Sales $75,000 182.6 2.61 50% $9,245,869 $0.13

Marketing $75,000 27.7 0.40 100% $2,808,872 $0.04

EPC sales management $75,000 43.9 0.63 100% $4,447,380 $0.06

Subtotal: employees 538.0 7.69 $43,535,891 $0.62

Benefits, FICA, bonus (added to base salary) 35%

Total indirect corporate costs (staff + business expenses) $53,181,843 $0.76

Direct Corporate Overhead

Staff Expenses

Base Salary 

(unburdened) / 

person

# of 

employee

s

Employees 

per MW 

installed

Time 

assoc. 

w/direct 

proj. 

cost

(Base 

Salary + 

Benefits) × 

% of time

Design and engineering $75,000 66.4 50% $3,359,415 $0.05

Project management $75,000 42.5 90% $3,872,078 $0.06

Sales $75,000 182.6 50% $9,245,869 $0.13
19 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 

at www.nrel.gov/publications.

Total direct corporate staff costs $16,477,362 $0.24

MW installed by developer per year 70
20 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 

at www.nrel.gov/publications.

Appendix C. Breakdown of Direct Costs and Margins

Table C-1. Breakdown of Direct Costs and Margins in 201223

Residential Commercial

($/WDC) ($/WDC)

Average system size (kW)24 5.1 221

Hardware, 

Construction 

Labor, Insurance, 

Permitting &

Interconnection 

fees

Module

NREL Benchmarks

$ 1.03 $ 1.03 

Inverter $ 0.43 $ 0.29 

Installation materials $ 0.44 $ 0.63 

Installation labor $ 0.55 $ 0.28 

Labor Benefits, FICA, bonus 35% of labor costs $ 0.19 $ 0.10 

EPC direct staff costs

From Table A-1 and Table A2 $ 0.19 $ 0.15 

Permitting & interconnection 

fees $430 Res., $5,000 Com. $ 0.08 $ 0.02 

Construction insurance 

0.3% fee on system price to 

integrator $ 0.01 $ 0.01 

Subtotal: EPC Cost $ 2.92 $ 2.50 

EPC margin 

20% of cost res. 10% of cost 

com. $ 0.58 $ 0.25

System Price to Developer $ 3.50 $ 2.76

Direct Staff Costs by Developer From Table B-1 $ 0.24 $ 0.24 

Average transaction size (MW In portfolio) 10 10

Transactional 

Costs Professional Services $/Portfolio

Developer legal fees $ 250,000 $ 0.03 $ 0.03

Tax-equity legal fees $ 250,000 $ 0.03 $ 0.03

Auditor (for residential only) $ 10,000 $ 0.00 N/A

Accountants $ 25,000 $ 0.00 $ 0.00 

Independent engineering (for 

commercial only) $ 75,000 N/A $ 0.01 

Subtotal: Professional Services $ 0.05 $ 0.06

Financier Expenses

Fees from term debt

2.5% fee on loan amount 

(40% of system price to 

developer)

 $ 0.04 $ 0.02 

Fees from construction debt / 

revolving line of credit (for 

commercial only)

1% fee on loan amount (75% 

of system price to developer) N/A $ 0.02 

Interest on loan / line of credit 

(during construction, for 

commercial only)

5% interest rate on loan for 6 

months N/A $ 0.04 

Subtotal: Financier Expenses $ 0.04 $ 0.08

Additional Costs

 

23 Columns may not add due to rounding. 24 System sizes correspond with modeled hardware and labor costs from Feldman et al. (2013).
21 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 

at www.nrel.gov/publications.

Inverter warranties (20 

years) $ 0.10 $ 0.09 

System production 

guarantees $ 0.02 $ 0.01 

Subtotal: Additional Costs $ 0.12 $ 0.10

Subtotal: Transactional 

Costs $ 0.21 $ 0.24

Mark-up to tax equity in sale-leaseback structure 15% of all costs $ 0.57 $ 0.43

Total System 

Price $ 4.52 $ 3.66

Cash Reserves

Debt service reserve

Reserve of 5% interest rate on 

term loan for 6 months (40% 

of total system price)

$ 0.04 $ 0.04 

O&M reserve 6-month reserve of O&M 

costs ($23.5/kW, per year) $ 0.01 $ 0.01 

Total Cash 

Reserves $ 0.05 $ 0.05

Total System Price Plus Cash Reserves $ 4.58 $ 3.71