Non-Hardware (“Soft”) CostReduction Roadmap for 

Residential and Small 

Commercial Solar 

Photovoltaics, 2013-2020 

Kristen Ardani1, Dan Seif2, Robert Margolis1, 

Jesse Morris2, Carolyn Davidson1, Sarah Truitt1, 

and Roy Torbert2 

1

National Renewable Energy Laboratory

2

Rocky Mountain Institute 

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. 

Technical Report 

NREL/TP-7A40-59155 

August 2013 

Contract No. DE-AC36-08GO28308 
 

 

 

 

 

 

 

National Renewable Energy Laboratory 

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Non-Hardware (“Soft”) CostReduction Roadmap for 

Residential and Small 

Commercial Solar 

Photovoltaics, 2013-2020 

Kristen Ardani1, Dan Seif2, Robert Margolis1, 

Jesse Morris2

, Carolyn Davidson1, Sarah 

Truitt1

, and Roy Torbert2 

1

National Renewable Energy Laboratory

2

Rocky Mountain Institute 

Prepared under Task No. SM13.0530 

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. 

Technical Report 

NREL/TP-7A40-59155 

August 2013 

Contract No. DE-AC36-08GO28308 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NOTICE 

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Acknowledgments 

The authors would like to thank the following individuals and organizations for their contributions to 

and review of this work: Barry Cinnamon (Cinnamon Solar), Douglas Fabini (U.S. Department of 

Energy Solar Energy Technologies Program [SETP]), David Feldman (National Renewable Energy 

Laboratory [NREL]), Benjamin Foster (Optony), Joshua Huneycutt (SETP), Joachim Seel (Lawrence 

Berkeley National Laboratory [LBNL]), Jason Keyes (Keyes, Fox & Wiedman LLP), Kelly Knutsen 

(SETP), Katherine Liu (University of California Berkeley), Michael Mendelsohn (NREL), Christina 

Nichols (SETP), John Rethans (Clean Power Finance [CPF]), James Tong (CPF), Elaine Ulrich (SETP), 

Ryan Wiser (LBNL), and Jarett Zuboy (consultant). 

List of Acronyms 

ABS asset-backed securitization 

AHJ authorities having jurisdiction 

BDC/RIC business development companies/registered investment 

companies 

BOS balance of system 

bps basis points 

CPI Consumer Price Index 

CRO cost-reduction opportunities 

DC direct current 

DG distributed generation 

DOE U.S. Department of Energy 

FHA Federal Housing Authority 

FHFA Federal Housing Financing Authority 

HELOC home equity line of credit 

HUD U.S. Dept. of Housing and Urban Development 

IOU investor-owned utility 

IPO initial public offering 

IPP independent power producer 

ITC investment tax credit 

ITRPV International Technology Roadmap for Photovoltaics 

ITRS International Technology Roadmap for Semiconductors 

JOBS Act Jumpstart Our Business Startups Act 

LCOE levelized cost of energy 

LTV loan to developer equity value 

M&A merger and/or acquisition 

MLP master limited partnership 

MUSH municipal (state/local government), universities, K-12 

schools, and hospitals 

NREL National Renewable Energy Laboratory 

O&M operations and maintenance 

PACE property assessed clean energy 

PII permitting, inspection, and interconnection 

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PUC public utility commission 

PV photovoltaics 

R&D research and development 

REIT real estate investment trusts 

RPS renewable portfolio standard 

SEC Securities and Exchange Commission 

SIA Semiconductor Industry Association 

SREC solar renewable energy certificate 

VC/PE venture capital and private equity 

VDC volt direct current 

WACC weighted average cost of capital 

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Executive Summary 

Non-hardware (soft) costs have become a major driver of U.S. photovoltaic (PV) system prices, and 

aggressive soft-cost-reduction pathways must be developed to achieve the U.S. Department of Energy 

(DOE) SunShot Initiative’s PV price targets. 

This report roadmaps the cost reductions and innovations necessary to achieve the SunShot soft-cost 

targets by 2020, focusing on advances in four soft-cost areas: (1) customer acquisition; (2) permitting, 

inspection, and interconnection (PII); (3) installation labor; and (4) financing. A fifth soft-cost 

category—“other soft costs,” which includes profit and overhead—was not explicitly benchmarked by 

past survey efforts and is not roadmapped here. Exploring ways to reduce this “other soft costs” 

category will be a subject of future research. 

In 2010, U.S. PV soft costs totaled $3.32/W1 for 5-kW residential systems and $2.64/W for small 

commercial systems (250 kW and smaller), representing approximately 50% of the total installed 

residential PV system price ($6.60/W) and 44% of the total installed small commercial system price 

($5.96/W). The SunShot Initiative aims to reduce the installed-system price contribution of total soft 

costs to approximately $0.65/W for residential systems and $0.44/W for commercial systems by 2020, 

with total installed system prices of $1.50/W and $1.25/W, respectively. 

To create the roadmaps, we adapted the methodologies used in the Semiconductor Industry 

Association’s International Technology Roadmap for Semiconductors and the SEMI PV Group’s 

International Technology Roadmap for Photovoltaics. We gathered granular and sector-specific data 

through literature reviews, National Renewable Energy Laboratory and Rocky Mountain Institute data, 

and over 70 in-depth PV industry interviews with financiers, analysts, utility representatives, residential 

and commercial PV installers, software engineers, industry organizations, and others. The roadmaps 

draw on industry expertise to plot conceivable courses to achieving the residential and small commercial 

2020 SunShot targets, and they suggest the level of effort that might be required to achieve SunShotlevel cost reductions in specific soft-cost areas. 

We used survey data and market analysis to derive baseline values (2012 for financing, 2010 for all 

other cost categories2

) for residential and small commercial PV system prices and their soft-cost 

components. We then assigned corresponding target (2020) values based on DOE’s SunShot Vision 

Study to evaluate the level of cost reduction needed to achieve SunShot targets (DOE 2012). We defined 

the path from the 2010/2012 baseline values to the 2020 target values in terms of solution sets, each of 

which contains one or more specific cost-reduction opportunities (CROs), such as innovative 

technologies, business models, financial structures, regulatory changes, and industry best practices. We 

asked interview and survey participants to estimate soft-cost reductions—in terms of maximum costreduction potential and market penetration—through 2020 based on the PV industry’s current trajectory 

of advancements and expectations. We then re-reviewed research sources, followed up with original 

interviewees, and directly inquired with additional interviewees to determine the most likely further cost 

reductions from the current trajectory to the roadmap targets. 

We estimated the uncertainty of achieving each CRO by calculating the cost-reduction difference 

between the current-trajectory CRO values and the roadmap CRO values. We translated these uncertainties 

1 Per watt direct current. Expressed as “$/W” throughout report.
	 2 2010 selected as baseline year for all costs measured in $/W to correspond with beginning of SunShot Initiative.
	

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into a color code, or “readiness factor,” that indicates the level of research, development, and precommercialization needed to achieve the roadmap targets—similar to the International Technology 

Roadmap for Semiconductors (ITRS) and International Technology Roadmap for Photovoltaics 

(ITRPV) coding system. In our system, red denotes the lowest level of readiness/certainty; specifically, 

it indicates that for a given CRO, the market penetration required to achieve a roadmap target in any 

year is more than 25% higher than the current trajectory. Orange indicates a deviation in market 

penetration of 10%–25%, while yellow indicates a deviation in market penetration of up to 10%. Green 

denotes the highest level of readiness/certainty and that the roadmap target is realizable under the 

current trajectory. Results indicate that at both the residential and small commercial scales, the currenttrajectory case does not achieve SunShot targets by 2020. Table ES-1 shows the readiness factor legend 

with color codes. 

Table ES-1. Readiness Factor Legend 

For some cost areas, the resulting roadmap identifies reasonable, yet substantive, advances that reduce 

soft costs to target levels by 2020. For other cost areas, there is less certainty about the emergence—and 

elements—of specific solution sets and CROs required to reach the targets. In these cases, the roadmap 

incorporates future deployment of innovations with greater cost-reduction potential, referred to as 

“undefined” solution sets and CROs. 

The residential PV roadmap shows a challenging path to SunShot soft-cost targets (Table ES-2). 

Additional reductions of $0.46/W and 1.6% weighted average cost of capital (WACC) beyond the 

current-trajectory reductions are required. Overall, customer acquisition costs have the highest 

likelihood of decreasing to 2020 target levels,3 although the implementation of several individual siteassessment-software and consumer-targeted CROs is highly uncertain. Financing has the next-mostcertain cost-reduction pathway; the primary challenge is developing scalable homeowner financing 

products, for which the homeowner maintains equity control. In contrast, the pathways for PII and 

installation labor are highly uncertain. Because achieving the required PII cost target is nearly 

impossible with a piecemeal approach, an undefined solution set is introduced that may represent the 

3 Preliminary NREL 2012 benchmarking data made available shortly before release of this report show residential customer 

acquisition costs averaging below 2013 current trajectory values. Friedman et al 2013 “Second Annual Benchmarking NonHardware Balance-of-System (Soft) Costs for U.S. Photovoltaic Systems, Using a Bottom-Up Approach and Installer 

Survey”. Forthcoming. 

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combination of unknown regulatory mechanisms that enable wider-scale uniformity across authorities 

having jurisdiction (AHJs), a market-wide average fee of $100 [instead of $250 (i.e., in the lower 

permitting fees solution set)], and streamlined inspection. Similarly, an undefined solution set is required 

to achieve the installation labor target, which could entail a combination of additional equipment 

standardization and classification and/or reduced through-roof penetration. 

Table ES-2. Residential PV Soft-Cost Reduction Roadmap 

The commercial PV roadmap offers a more certain path to SunShot soft-cost targets (Table ES-3). 

Additional reductions of $0.11/W and 1.1% WACC beyond the current-trajectory reductions are 

required. Overall, customer acquisition has a relatively certain path, although reaching the 2020 target 

hinges on the highly uncertain market penetration of improved site assessment and design CROs, in 

addition to advanced customer acquisition tools that couple well with market-expanding (“new 

markets”) innovative finance. In the area of installation labor, commercial PV is more amenable than 

residential PV to streamlined installation practices, thus achieving the SunShot target by 2020 is more 

certain; the near-universal adoption of integrated racking provides one plausible cost-reduction pathway. 

Commercial financing exhibits a similar level of challenge to reach the roadmap WACC target as 

residential financing. However, the commercial financing path requires the highly uncertain 

implementation of an undefined host-finance CRO (e.g., special rooftop property rights/easements or 

energy service agreements) as well as highly uncertain expansions of green bond programs and 

commercial property assessed clean energy (PACE) financing. Though we do not develop a commercial 

PII roadmap, our findings suggest that streamlining the interconnection process could reduce the major 

PII cost component substantially. 

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2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Customer Acquisition 

($/W) $0.67 — — $0.53 $0.49 $0.45 $0.41 $0.36 $0.28 $0.19 $0.12

PII ($/W) $0.20 — — $0.18 $0.16 $0.15 $0.13 $0.11 $0.10 $0.06 $0.04

Installation Labor ($/W) $0.59 — — $0.51 $0.46 $0.42 $0.36 $0.30 $0.24 $0.19 $0.12

Other Soft Costs ($/W) $1.86 — — $1.30 $1.14 $0.97 $0.82 $0.68 $0.56 $0.48 $0.37

Financing (WACC %-real) — — 9.9% 9.4% 8.8% 8.2% 7.7% 7.7% 4.8% 3.4% 3.0%

Total Soft Costs ($/W) $3.32 — — $2.52 $2.25 $1.99 $1.72 $1.45 $1.18 $0.92 $0.65

Total System Costs ($/W) $6.60 — — $4.99 $4.49 $3.99 $3.49 $3.00 $2.50 $2.00 $1.50
Table ES-3. Commercial PV Soft-Cost Reduction Roadmap 

Regardless of the specific path taken to achieve the SunShot targets, the concerted efforts of numerous 

PV market actors and stakeholders will be required. We illustrate how the required participation of each 

type varies substantially by soft-cost category while noting that roles and responsibilities will be 

complementary and evolve over time. This report is the first of a series that will track soft-cost 

reductions and quantify the impacts of innovations. Future work will elaborate and refine soft-cost 

benchmarks, cost-reduction strategies, and the distinctions among the nation’s geographically diverse 

PV markets with the goal of tracking—and helping enable—progress toward SunShot targets. 

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Table of Contents 

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

2 Roadmap Methodology ........................................................................................................................3
 

3 Customer Acquisition...........................................................................................................................8
 

3.1 Residential Customer Acquisition Roadmap ................................................................................. 9
	

3.2 Commercial Customer Acquisition Roadmap ............................................................................. 13
	

4 Permitting, Inspection, and Interconnection....................................................................................16
 

4.1 Residential Permitting, Inspection, and Interconnection Roadmap............................................. 16
	

4.2 Commercial Permitting, Inspection, and Interconnection ...........................................................20
	

5 Installation Labor ................................................................................................................................20
 

5.1 Residential Installation Labor Roadmap......................................................................................21
	

5.2 Commercial Installation Labor Roadmap ....................................................................................24
	

6 Financing .............................................................................................................................................27
 

Methodology......................................................................................................................................... 27
	

6.1 Residential Financing Roadmap .................................................................................................. 29
	

6.1.1 Third-Party Finance ........................................................................................................ 30
	

6.1.2 Utility Finance ................................................................................................................ 31
	

6.1.3 Homeowner Finance....................................................................................................... 31
	

6.1.4 Community Solar............................................................................................................ 31
	

6.2 Commercial Financing Roadmap ................................................................................................35
	

6.2.1 Third-Party Finance ............................................................................................................ 36
	

6.2.2 Utility Financing................................................................................................................. 36
	

6.2.3 Host Finance ................................................................................................................... 36
	

6.2.4 Community Solar............................................................................................................ 37
	

7 Key Actors and Stakeholders ............................................................................................................40
 

7.1 Customer Acquisition .................................................................................................................. 40
	

7.1.1 Developers/Installers ...................................................................................................... 40
	

7.1.2 Service Providers............................................................................................................ 40
	

7.1.3 Other Stakeholders.......................................................................................................... 41
	

7.2 Permitting, Inspection, and Interconnection ................................................................................ 41
	

7.3 Installation Labor.........................................................................................................................42
	

7.4 Financing ..................................................................................................................................... 43
	

8 Conclusions, Limitations, and Future Research .............................................................................45
 

References .................................................................................................................................................48
 

Appendix A: Supplemental Data Tables..................................................................................................51
 

Appendix B. Example Interview and Survey Questions ........................................................................58
 

Appendix C: Solution Set and Cost-Reduction Opportunity Descriptions .........................................62
 

Customer Acquisition ...........................................................................................................................62
	

Permitting, Inspection, and Interconnection .........................................................................................64
	

Standardization of Requirements................................................................................................. 64
	

Transparency of Requirements .................................................................................................... 64
	

Online Permitting.........................................................................................................................64
	

Lower Permitting Fees................................................................................................................. 64
	

Interconnection Best Practices ..................................................................................................... 64
	

Undefined Solution Set................................................................................................................ 64
	

Installation Labor.......................................................................................................................................64
 

Integrated Racking.......................................................................................................................65
	

Module Integrated Electronics..................................................................................................... 65
	

Prefabrication...............................................................................................................................65
	

Plug and Play (Residential).......................................................................................................... 65
	

Solar-Ready Homes (Residential)................................................................................................65
	

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Undefined Solution Set (Residential) ..........................................................................................65
	

Power Electronics (Commercial)................................................................................................. 66
	

Financing .............................................................................................................................................. 66
	

Residential ................................................................................................................................... 66
	

Utility Finance .............................................................................................................................67
	

Homeowner Finance ....................................................................................................................68
	

Community Solar.........................................................................................................................69
	

Commercial........................................................................................................................................... 69
	

Third-Party Financing.................................................................................................................. 69
	

Community Solar.........................................................................................................................71
	

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List of Figures 

Figure 1. Total PV system prices and SunShot targets.................................................................................. 2
	

Figure 2. 2011 ITRS lithography technology requirements .......................................................................... 4
	

Figure 3. Residential PV customer acquisition costs: Current trajectory and roadmap ..............................12
	

Figure 4. 2020 residential PV customer acquisition cost reductions: Current trajectory and roadmap.......12
	

Figure 5. Commercial PV customer acquisition costs: Current trajectory and roadmap ............................15
	

Figure 6. 2020 commercial PV customer acquisition cost reductions: Current trajectory and roadmap ....15
	

Figure 7. Residential PV permitting, inspection, and interconnection costs: Current trajectory and 

roadmap .................................................................................................................................. 19
	

Figure 8. 2020 residential PV permitting, inspection, and interconnection cost reductions: Current
	

trajectory and roadmap ........................................................................................................... 19
	

Figure 9. Residential PV installation labor costs: Current trajectory and roadmap ....................................23
	

Figure 10. 2020 residential PV installation labor cost reductions: Current trajectory and roadmap...........23
	

Figure 11. Commercial PV installation labor costs: Current trajectory and roadmap................................. 26
	

Figure 12. 2020 commercial PV installation labor cost reductions: Current trajectory and roadmap.........26
	

Figure 13. Residential PV WACC: Current trajectory and roadmap ..........................................................34
	

Figure 14. 2020 residential PV WACC reduction: Current trajectory and roadmap................................... 34
	

Figure 15. 2020 commercial PV WACC reduction: Current trajectory and roadmap ................................39
	

Figure 16. 2020 commercial PV WACC reduction: Current trajectory and roadmap ................................39
	

Figure 17. Customer acquisition actors and stakeholders ........................................................................... 41
	

Figure 18. Permitting, inspection, and interconnection actors and stakeholders......................................... 42
	

Figure 19. Installation labor actors and stakeholders ..................................................................................43
	

Figure 20. Finance actors and stakeholders................................................................................................. 45
	

List of Tables 

Table ES-1. Readiness Factor Legend.......................................................................................................... vi
	

Table ES-2. Residential PV Soft-Cost Reduction Roadmap...................................................................... vii
	

Table ES-3. Commercial PV Soft-Cost Reduction Roadmap ................................................................... viii
	

Table 1. Baseline and Roadmap Targets for Residential and Commercial PV System Costs and WACC...6
	

Table 2. Readiness Factor Legend................................................................................................................. 8
	

Table 3. Residential Customer Acquisition Roadmap................................................................................. 11
	

Table 4. Commercial Customer Acquisition Roadmap............................................................................... 14
	

Table 5. Residential Permitting, Inspection, and Interconnection Roadmap............................................... 18
	

Table 6. Residential Installation Labor Roadmap .......................................................................................22
	

Table 7. Commercial Installation Labor Roadmap .....................................................................................25
	

Table 8. Residential Financing Roadmap.................................................................................................... 33
	

Table 9. Commercial Financing Roadmap .................................................................................................. 38
	

Table 10. Residential PV Soft-Cost Reduction Roadmap........................................................................... 46
	

Table 11. Commercial PV Soft-Cost Reduction Roadmap ......................................................................... 46
	

Table A-1. Residential Customer Acquisition Market Penetration and Maximum Cost-Reduction 

Potential.................................................................................................................................. 51
	

Table A-2. Commercial Customer Acquisition Market Penetration and Maximum Cost-Reduction 

Potential.................................................................................................................................. 52
	

Table A-3. Residential, Inspection, and Interconnection Market Penetration and Maximum
	

Cost-Reduction Potential ........................................................................................................ 53
	

Table A-4. Residential Installation Market Penetration and Maximum Cost-Reduction Potential ............54
	

Table A-5. Commercial Installation Labor Market Penetration and Maximum Cost-Reduction Potential 55
	

Table A-6. Residential Financing Market Penetration and Maximum Cost-Reduction Potential ...............56
	

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Table A-7. Commercial Financing Market Penetration and Maximum Cost-Reduction Potential ............ 57 
	

Table B-1. Example Interview Questions.................................................................................................... 58
	

Table B-2. Example Survey Instrument (Residential PII)........................................................................... 60
	

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1 Introduction 

The objective of this analysis is to roadmap the cost reductions and innovations necessary to achieve the 

U.S. Department of Energy (DOE) SunShot Initiative’s total soft-cost targets by 2020. The roadmap 

focuses on advances in four soft-cost areas: (1) customer acquisition; (2) permitting, inspection, and 

interconnection (PII); (3) installation labor; and (4) financing. Financing cost reductions are in terms of 

the weighted average cost of capital (WACC) for financing PV system installations, with real-percent 

targets of 3.0%4 (residential) and 3.4%5 (commercial). A fifth soft-cost category—“other soft costs,” 

which includes profit and overhead—was not explicitly benchmarked by past survey efforts and is not 

roadmapped here. Exploring ways to reduce this “other soft costs” category will be a subject of 

future research. 

With global photovoltaic (PV) module prices declining rapidly, non-hardware PV costs have accounted 

for a significant and increasing portion of average installed U.S. PV system prices (Barbose et al. 2012). 

Therefore, it is critical to understand non-hardware costs—also referred to as “non-hardware balance of 

system (BOS),” “business process,” or “soft” costs—such as permitting, inspection, interconnection, 

profit, overhead, installation labor, customer acquisition, and financing. Non-hardware costs are both a 

major challenge and a major opportunity for reducing PV system prices and stimulating SunShot-level 

PV deployment in the United States. 

Results from a 2010 installer survey and cost-modeling analysis indicate that in 2010 soft costs, 

including profit and overhead, totaled $3.32/W6 for 5-kW residential systems and $2.64/W for small 

commercial systems (≤250 kW) (Ardani et al. 2012; Feldman et al. 2012; Goodrich et al. 2012). This 

represented approximately 50% of 2010 U.S. total installed residential PV system price ($6.60/W) and 

44% of total installed small commercial system price ($5.96/W) (Ardani et al. 2012; Barbose et al. 

2012). DOE’s SunShot Initiative aims to reduce the installed-system price contribution of total soft costs 

to approximately $0.65/W for residential systems and $0.44/W for commercial systems by 2020, with 

total installed system prices of $1.50/W and $1.25/W, respectively (DOE 2012). Figure 1 depicts 

benchmark PV system prices, total soft costs, and SunShot targets for residential and commercial PV. 

Of the $3.32/W in residential soft costs, specifically surveyed costs total $1.46/W7 in the categories of 

customer acquisition (including system design and marketing); permitting, inspection, and 

interconnection (including typical delays and an assumed permitting fee of $450); and installation labor 

4 Derived from NREL’s SolarDS modeling basis for the SunShot Vision Study (DOE 2012)at 80%–100% debt and 

homeowner’s equity at 0%–20%. For the purposes of this report, this debt was calculated based on 2010-to-2012 average 30-

yr $30,000 home equity loans (2.9%-real) at 80% and homeowner’s equity at 20% at 3.1%-real based on the 30-yr (to 

January 2013) Standard &Poor’s 500 real compound annual growth rate. 5 Derived from NREL’s SolarDS modeling basis for the SunShot Vision Study (DOE 2012)at 60% debt and company equity 

at 40%. For the purposes of this report, the debt rate came from 2010-to-2012 average Moody’s Baa bond ratings (2.9%-real) 

and U.S. corporate WACC from New York University (NYU) Stern 

(http://pages.stern.nyu.edu/~adamodar/New_Home_Page/datafile/wacc.htm; data as of January 2013) of 6.8%-nominal 

(corrected to 4.2%-real).

6 $/W measured in $/WDC unless otherwise noted. 7 This value is $1.50/W in Ardani et al. (2012). We use $1.46/W in this report because we do not include the cost of 

arranging third-party financing ($0.02/W) or incentive application costs ($0.02/W). In this report, we include these in “other 

soft costs” because we do not roadmap fixed financing costs (this is the subject of ongoing NREL research) and the SunShot 

2020 targets do not include incentives. 

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(Ardani et al. 2012).8 Assuming the surveyed soft costs’ proportional shares of total soft costs remains 

constant through 2020, achieving the SunShot residential aggregate target of $0.65/W requires an 80% 

reduction in total surveyed costs from $1.46/W to $0.28/W. 

Of the $2.64/W in small commercial soft costs, specifically surveyed soft costs total $0.98/W,9 or 17% 

of the total system price (Ardani et al 2012).10 Assuming the surveyed soft costs’ proportional shares of 

total soft costs remains constant through 2020, achieving the SunShot aggregate commercial target of 

$0.44/W requires an 85% decrease in surveyed costs from $0.98/W to $0.13/W. 

Figure 1. Total PV system prices and SunShot targets 

The remainder of this report is structured as follows. Section 2 describes the roadmap data collection 

and analysis methodology we used. Sections 3 through 6 present roadmap data collection and analysis 

findings for residential and small commercial PV systems by cost category: customer acquisition 

(Section 3); permitting, inspection, and interconnection (Section 4); installation labor (Section 5); and 

8 Customer acquisition costs account for $0.67/W; permitting, inspection, and interconnection $0.20/W; and installation labor 

$0.59/W.

9 This value is $0.99/W in Ardani et al. (2012). We use $0.98/W in this report because we do not include the cost of 

arranging third-party financing ($0.02/W; this only reduces the value by $0.01/W because of rounding). In this report, we 

include these in “other soft costs” because we do not roadmap fixed financing costs (this is the subject of ongoing NREL 

research).

10 Customer acquisition costs account for $0.19/W; permitting, inspection, and interconnection (including an assumed 

permitting fee of $25,000) $0.37/W; and installation labor $0.42/W. Commercial soft costs are median values unless 

otherwise stated. Given the relatively small sample of commercial installers (n = 17), the median was deemed more 

meaningful than a simple or capacity-weighted average (as was used for residential PV, n = 80). 

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financing (Section 6). Section 7 addresses the key actors and stakeholders whose participation is 

required to achieve the roadmap targets. Section 8 discusses conclusions, study limitations, and 

directions for future research. Appendix A contains our underlying data used for calculations. 

Appendix B provides our interview and survey questions. Appendix C expands the definitions of the 

cost-reduction opportunities. 

2 Roadmap Methodology 

To roadmap soft-cost reductions through 2020, we adapted the methodology used in the Semiconductor 

Industry Association’s (SIA) annual International Technology Roadmap for Semiconductors (ITRS) 

(http://www.itrs.net/). Through numerous working groups producing annual updates or full revisions, 

the ITRS summarizes the technical capabilities that must be developed for the industry to advance; it 

provides a 15-year outlook on major trends and outlines clear targets for researchers in the outer years. 

After demonstrating a significant industry impact for nearly 20 years, the SIA roadmapping 

methodology was adapted by the SEMI PV Group Europe (a group of European solar energy 

manufacturers) in 2010 to develop the International Technology Roadmap for Photovoltaics (ITRPV) 

(http://www.itrpv.net/). The ITRPV provides a long-term trajectory for advancements in the 

manufacture of crystalline silicon PV and defines the improvements necessary to advance along the PV 

learning curve. 

The ITRS and ITRPV include tables focused on specific technical areas, listing solution pathways in the 

far left column with targets and associated metrics to track progress over time in corresponding rows. 

The ITRS and ITRPV use a color-coded scale to depict the certainty of a solution being realized and 

distinguish the level of research needed to achieve targets. In the ITRS, white indicates the highest level 

of certainty (solutions exist and are being optimized), while red indicates that significant research 

breakthroughs are needed or that solutions are unknown. Intermediate levels of certainty and research 

requirements are designated with yellow and yellow stripes. Figure 2 provides an example from the 

2011 ITRS, illustrating this color coding and methodology for lithography. 

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Source: http://www.itrs.net/Links/2011ITRS/2011Tables/Litho_2011Tables.xlsx (accessed 3/28/13) 

Figure 2. 2011 ITRS lithography technology requirements 

Our soft-cost roadmap follows the general ITRS/ITRPV methods with some key differences. Unlike the 

ITRS and ITRPV, our roadmap addresses multi-stakeholder, multi-business aspects of PV and is not 

limited to technical issues. In addition, this roadmap tracks progress in terms of cost reduction— 

measured in $/W and WACC—rather than technical nodes. Our sources of information and industry 

expertise are different as well. Where the ITRS approach employs industry working groups, we gathered 

granular and sector-specific data through literature reviews, National Renewable Energy Laboratory 

(NREL) and Rocky Mountain Institute data, and in-depth interviews. Over 70 interview participants 

included financiers, analysts, utility representatives, residential and commercial PV installers, software 

engineers, industry organizations, and others. Appendix B contains the interview questions. 

To create our roadmaps, we used survey data and market analysis to derive baseline values (2012 

WACC for financing; 201011 $/W for all other cost categories) for residential12 and small commercial13 

PV system prices and their soft-cost components. The residential baseline values are $6.60/W for the 

system, $3.32/W for total soft costs, and 9.9% for WACC14 (Barbose et al. 2011; Ardani et al. 2012; 

Feldman et al. 2012; Goodrich et al. 2012). Within the soft costs, baseline values are as follows: 

$0.67/W customer acquisition, $0.20/W PII, $0.59/W installation labor, and $1.86/W “other soft costs” 

(Ardani et al. 2012). The small commercial baseline values are $5.96/W for the system and $2.64/W for 

total soft costs (Barbose et al. 2011; Ardani et al. 2012; Feldman et al. 2012; Goodrich et al. 2012) and 

8.6% for WACC. Within the soft costs, baseline values are as follows: $0.19/W customer acquisition, 

11 2010 was selected as the baseline year for all costs measured in $/W to correspond with the beginning of the SunShot
	

Initiative.
	 12 For the purposes of this study, residential systems are installed on single-family residences.
	 13 For the purposes of this study, commercial systems include systems of 250 kW or smaller installed on commercial, 

municipal, university, school, hospital, and multi-family residential buildings, unless otherwise noted.

14 For this study, a combination of in-depth interviews and public and private reports was used to benchmark the WACC in
	

late 2012 and early 2013. Thus, WACC benchmarks reflect recent and more ITC-monetizing, tax-equity-dependent data, with
	

2011 data used in some cases. 

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$0.42/W installation labor, and $2.03/W “other soft costs.” For commercial PV, we included PII in the 

“other soft costs” category because no comprehensive data exists for benchmarking interconnection 

study costs and permitting fees in the commercial sector. Anecdotally, interconnection study costs are 

reported to vary substantially—from $2,500 to more than $30,000—depending on PV penetration rates 

in a given utility service territory and system size. Due to the lack of existing data, this study 

quantitatively roadmaps cost reductions for residential PV only and assesses commercial-scale PII based 

on qualitative data and interview findings. Collecting comprehensive PII cost data for commercial PV 

systems remains an area for future research. 

We next assigned target (2020) values for residential and commercial PV system prices and their softcost components based on the SunShot Vision Study (DOE 2012). The residential baseline values are 

$1.50/W for the system, $0.65/W for total soft costs, and 3.0% for WACC. Because of data limitations, 

we set the specific soft-cost target values by assuming the cost in each category decreases 

commensurately based on its proportion of 2010 soft costs: $0.12/W customer acquisition, $0.04/W PII, 

$0.12/W installation labor, and $0.37/W “other soft costs.” The commercial baseline values are $1.25/W 

for the system, $0.44/W for total soft costs, and 3.4% for WACC, with the following specific soft-cost 

targets: $0.03/W customer acquisition, $0.07/W installation labor, and $0.34/W “other soft costs” 

(including PII). Refining 2020 soft-cost values to account for different rates of cost reduction across 

categories has been identified as an important area for future research. 

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Table 1. Baseline and Roadmap Targets for Residential and Commercial PV System Costs and WACC 

*

The baseline is 2012 for WACC and 2010 for all other cost categories. **For commercial PV, the other soft-cost category includes PII. 

We defined the paths between the 2010 baselines and the 2020 targets in terms of solution sets, each of 

which contains one or more specific cost-reduction opportunities (CROs), such as innovative 

technologies, business models, financial structures, regulatory changes, and industry best practices. For 

example, the residential customer acquisition roadmap has a solution set called “consumer targeting 

strategies,” which includes four CROs: marketing programs and partnerships, lead qualification and 

generation programs, referral programs, and consumer awareness campaigns. The finance section CROs 

were limited to financial structures, but other CRO elements (e.g., improvement in business models and 

expanded financial data) were assumed to support specific structures. Each CRO has two major 

attributes: 

1.		 Maximum cost-reduction potential: The estimated amount by which each CRO could reduce its 

corresponding soft-cost baseline value, measured in $/W for all soft-cost areas except for 

finance, which is measured in WACC percent.15 

15 We assumed that maximum cost-reduction potential is the same in both the current-trajectory and roadmap cases. Market 

penetration varies. 

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2.		 Market penetration: The estimated annual market penetration rate of each CRO by 2020, as a 

percentage of each sector’s total annual installed PV capacity. All finance-related CROs are 

assumed to be mutually exclusive, while some CROs in other soft-cost areas could be deployed 

concurrently. 

To derive a roadmap from the 2010 baseline to 2020 target values, we primarily used information 

provided by interview participants, supplemented with literature and data from the following sources: 

Ardani et al. (2012); Barbose et al. (2011); Bony et al. (2010); Brooks (2011); Bromsley (2012); Bullard 

(2012); Bullock et al. (2012); Coughlin and Cory (2009); DOE (2012); Feldman et al. (2012); Goodrich 

et al. (2012); GTM-SEIA (2012); GTM-SEIA (2013); Hubbell et al. (2012); Linder and Di Capua 

(2012); Mendelsohn et al. (2012); Pitt (2008); Rose et al. (2011); Schwabe et al. (2012); Seel et al. 

(2012); Smith and Shaio (2012); Sunrun (2011); Tong (2012); Vote Solar (2012); and Woodlawn 

Associates (2012). 

For PII, labor, and customer acquisition, we first asked interview participants to estimate soft-cost 

reductions—in terms of maximum cost-reduction potential and market penetration—through 2020 based 

on the PV industry’s current trajectory of advancements and expectations. Similarly for financing, we 

asked participants how they envisaged WACC changing over time for specific CROs, what additional 

CROs should be considered, and what CRO penetrations they expected from 2013 to 2020.16 These 

responses produced our current-trajectory case. 

We then re-reviewed research sources, followed up with original interviewees, and directly inquired 

with additional interviewees to determine the most likely further cost reductions from the current 

trajectory to the roadmap targets. In some cases, the authors arbitrated between CROs, particularly when 

mutually exclusive market penetration conditions existed (e.g., in the financing section, the sum of CRO 

penetrations must always equal 100% in any year). This included lowering the penetration of certain 

CROs in the roadmap compared with the current trajectory. This lowering of CRO market penetration 

was necessary to allow for higher penetration of other CROs that enable roadmap target achievement by 

2020. However, arbitration between CROs is not a zero-sum exchange. The roadmap assumes a larger 

overall future market, due to lower cost. Thus, for a given CRO, reducing the market penetration in the 

roadmap compared with the current trajectory might actually result in an absolute increase in project 

development employing the “reduced” CRO. 

For some cost areas, the resulting roadmap identifies reasonable, yet substantive, advances that reduce 

soft costs to target levels by 2020. For other cost areas, there is less certainty about the emergence—and 

elements—of specific solution sets and CROs required to reach the targets. In these cases, the roadmap 

incorporates future deployment of innovations with greater cost-reduction potential, referred to as 

“undefined” solution sets and CROs.17 

We estimated the uncertainty of achieving each CRO by calculating the cost-reduction difference 

between the current-trajectory CRO values and the roadmap CRO values. We translated these certainties 

into a color code, or “readiness factor,” that indicates the level of research, development, and pre16 Interviewees often made qualitative statements about the penetration of CROs, such as "a lot," "most," "not that much," and
	

"a minority." Although the interviewees were asked to reframe such responses quantitatively, they did not always do so. In
	

addition, clear annual resolution between 2013 and 2020 was not always provided. In such cases, we assigned quantitative,
	

annual-resolution values based on interview outcomes, relative to one another.

17 Over time, we will track progress toward the roadmap targets and will work with stakeholders to identify specific solution
	

sets and CROs in place of the “undefined” solution sets and CROs.
	

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production needed to achieve the roadmap targets—similar to the ITRS/ITRPV coding system. In our 

system, red denotes the lowest level of readiness/certainty; specifically, it indicates that for a given 

CRO, the market penetration required to achieve the roadmap target in any year is more than 25% higher 

than the current trajectory. Orange indicates a deviation in market penetration of 10–25%, while yellow 

indicates a deviation in market penetration of up to 10%. Green denotes the highest level of 

readiness/certainty and the roadmap target is realizable under the current trajectory. Table 2 shows the 

readiness factor legend with color codes. White is not shown in the color code but denotes a PII, labor, 

or customer acquisition CRO that may have no or low penetration and offers very minimal (less than 

$0.01/W) or no cost-reduction benefits. For financing, white represents no meaningful (less than 1%) 

penetration. 

Table 2. Readiness Factor Legend 

In this report, readiness factor is provided for each CRO and summarized for each soft-cost category.
	

For PII, labor, and customer acquisition, the cost category summary readiness factor is determined from 

a cost reduction weighted average of the products of the $/W cost reduction enabled by each CRO, 

multiplied by its readiness factor (1 = green, 2 = yellow, 3 = orange, 4 = red). The financing summary
	

readiness factor is determined via a market penetration weighted average of the products of the readiness 

factor number (again, 1 through 4) of each CRO multiplied by its penetration.
	

3 Customer Acquisition 

The cost to acquire a customer is influenced by several factors, including market maturity, installer 

business model, and system financing options available to the end user. Innovative financing offerings, 

including third-party ownership, have been cited in connection with significant decreases in customer 

acquisition costs but higher transaction costs. For example, companies offering no-money-down leases 

can more easily attract customers, but those same projects incur upfront and continuous costs of 

financing. Quantitatively roadmapping this dynamic is outside the scope of this analysis. Rather, 

innovative financing, as it relates to WACC, is discussed in the financing section (see Section 6). 

The traditional sales model for PV installers often begins with an initial phone conversation with the 

potential customer to prescreen for project viability. Typical items discussed include current monthly 

electricity expenditures, property ownership status, and customer credit quality. After this initial 

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screening, an in-person visit is completed to assess the installation site. After the installer gathers the 

necessary site specifications and consults with the property owner, a PV system engineer back in the 

office designs the system as part of a bid package. Once the bid is complete, the sales person presents it 

to the potential customer, usually requiring a second visit to the site. For many PV installation firms, this 

work is completed at risk, without a contract in place. Through technological advancements, this model 

is evolving to a less labor-intensive process. High-volume installers in particular have begun to employ 

computer-generated modeling to prequalify properties, even before the customer is contacted. 

Homeowners and businesses considering the purchase of a PV system have many factors to consider, 

including identifying a reputable installation company, gaining familiarity with manufacturers’ and 

installers’ warranties, selecting the most suitable financing option, and understanding the overall 

customer economics of the system. Increased consumer awareness and retailer-installer partnerships can 

streamline the purchasing decision process and increase an installer’s customer base. While most 

installers we interviewed consider customer acquisition activities to be a necessary cost of doing 

business, they also indicated that reducing expenses related to lead generation, bid and pro-forma 

preparation, contract negotiation, and system design can significantly reduce system prices offered to 

potential customers and enable broader PV deployment. 

3.1 Residential Customer Acquisition Roadmap 

Average 2010 customer acquisition costs for residential PV systems totaled $0.67/W18: $0.11/W for 

system design, $0.33/W for marketing and advertising, and $0.23/W for all other customer acquisition 

costs19 (Ardani et al. 2012). Achieving the SunShot price target of $1.50/W requires an 80% decrease in 

total customer acquisition costs from $0.67/W to $0.12/W. 

Our findings suggest three solution sets that can decrease residential customer acquisition costs: (1) 

software tools,20 which reduce total time spent on site; (2) design templates, which reduce system design 

costs; and (3) consumer-targeting strategies, which increase the number of leads generated. Table 3 

shows the residential PV customer acquisition roadmap, including the solution sets and corresponding 

CROs, the market-wide cost reductions ($/W) enabled by each CRO through 2020, the sum of cost 

reductions for all CROs combined, and the resulting average cost target from the 2010 baseline. For 

instance, under the software tools solution set, one CRO is remote site assessment tied to bid-preparation 

software. Sungevity is an example of a company that uses satellite imagery, aerial photographs, and 

commercially available software to gather information necessary for bid preparation, which is then 

transmitted to design engineers. Potential customers receive free, customized project quotes within 24 

hours of inputting their street address to the Sungevity Web platform. 

Compared with the current-trajectory case (in which customer acquisition costs decline to $0.25/W by 

2020), achieving the customer acquisition roadmap target requires additional cost reduction of $0.13/W 

by 2020 (see Figure 3 and Figure 4).Two CROs require no additional market penetration in the roadmap 

18 Interviewees indicated that employee or contractor sales commissions typically range from 3%–7% of system cost and up 

to 10% for high margin sales. These costs were not specifically surveyed for prior benchmarking analyses and are thus 

included in the “all other soft costs” category.

19 All installer survey results and cost benchmarks are based on PV systems installed in 2010. “All other customer acquisition 

costs” include sales calls, site visits, travel time to and from the site, contract negotiation with the system host/owner, and 

bid/pro-forma preparation but exclude marketing/advertising and system design.

20 The software tools CROs reduce costs in two customer acquisition categories, sales calls (included in “all other customer 

acquisition costs”) and system design. Therefore, the total cost reductions are greater than 100% of the system design costs. 

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beyond the current trajectory: (1) standardized system designs and (2) marketing programs and 

partnerships. In other words, the readiness/certainty of deploying these two CROs at the levels required 

to reach the roadmap target is high through 2020. Thus, additional cost reductions of $0.13/W from the 

remaining CROs are needed (Figure 3). 

In the 2020 roadmap, additional cost reductions of $0.03/W and ~$0.10/W are achieved through 

increased market penetration of software tools (remote system design/bid prep and next-generation site 

assessment) and consumer targeting strategies, respectively. Specifically, for the solution set of 

consumer targeting strategies, the CRO of lead qualification/generation programs captures 30% more of 

the market by 2020 than anticipated in the current-trajectory case (see Appendix A), reducing costs by 

an additional ~$0.03/W. Increased diffusion of referral programs (18% more of the market) and 

consumer awareness campaigns (10% more of the market) yield an additional cost reduction of $0.03/W 

each. For these CROs, readiness/certainty is higher through 2017 but then declines; all have the lowest 

level of readiness/certainty by 2020. 

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SOFTWARE 

TOOLS 

DESIGN 

TEMPLATES 

CONSUMERTARGETING 

STRATEGIES 

prep on initial site 

Standardized 

system designs 

Marketing 

SUM OF COST REDUCTIONS 

($/W)* 

RESULTING AVERAGE COST ($/W) 

*For any given year, equal to [2010 baseline of $0.67/W]- (sum of cost reductions] 

•Individual values may not add up to totals 

ow ing to rounding 

D ROAD MAP TARGET • REALIZABLE MEDIUM UNCERTAINTY 

LOW UNCERTAINTY • HIGH UNCERTAINTY 

Table 3. Residential Customer Acquisition Roadmap 

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Figure 3. Residential PV customer acquisition costs: Current trajectory and roadmap 

Figure 4. 2020 residential PV customer acquisition cost reductions: Current trajectory and roadmap 

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3.2 Commercial Customer Acquisition Roadmap 

Median 2010 customer acquisition costs total $0.19/W for small commercial PV systems: $0.10/W for 

system design, $0.01/W for marketing and advertising, and $0.08/W for all other customer acquisition 

costs (Ardani 2012). Achieving the SunShot price target requires a decrease in total customer acquisition 

costs from $0.19/W to $0.03/W. 

Our findings suggest four solution sets that can decrease commercial customer acquisition expenditures: 

(1) software tools, which reduce total time spent on site; (2) design templates, which reduce system 

design costs; (3) consumer-targeting strategies, which increase the number of leads generated; and (4) 

new markets, which increase bid success rate as financing becomes available to new customers. Table 4 

shows the commercial customer acquisition roadmap. Compared with the current-trajectory case (in 

which customer acquisition costs decline to $0.09/W by 2020), achieving the roadmap target requires an 

additional cost reduction of ~$0.06/W by 2020 (see Figure 5 and Figure 6). In the roadmap, cost 

reductions from lead qualification and generation programs are in line with the current trajectory, though 

increased market penetration of software tools (specifically, next-generation site assessment) and 

standardized design templates provides one potential pathway to enabling additional cost reductions 

market wide. 

The major roadmap improvements are achieved through the new markets solution set. Financing 

innovations that expand PV deployment to lower building owner credit classes21 and/or to real estate 

properties in which solar misaligns with investor’s interests (e.g., split incentives on energy savings with 

utility-bill-paying tenants and misaligned investment time horizon) have the potential to unlock the 

future commercial PV market. Three financing innovations/CROs that might expand the commercial PV 

market in this way are green bonds, commercial PACE, and the “undefined” CRO (further explained in 

Section 6.2 and Appendix C). 

Innovative financing might enable solar PV projects where capital was otherwise unavailable. However, 

financing solutions may be insufficient to drop average customer acquisition costs below $0.19/W by 

themselves. For example, interviewees cited numerous customer acquisition problems with existing 

commercial PACE programs. One issue is customer drop-outs as potential customers go through the 

process of getting their mortgage lender to allow subordination to the PACE loan, which often results in 

a refusal by the mortgage lender if that lender is not one and the same as the PACE lender. 

Thus, the slight increase in customer acquisition costs from 2017 to 2020 in the current trajectory arises 

from the conservative assumption that new financial models do not improve against the 2010 $0.19/W 

customer acquisition cost baseline. The roadmap target of $0.03/W is only achieved when these innovative 

financial models are combined with new, customer acquisition advancements (together the "undefined" 

CRO within the “new markets” solution set). 

21 Most small commercial PV financing is made available to high credit quality corporations and MUSH entities (less than 

10% of available commercial rooftop space). In addition, many real estate companies intend to sell building assets within 5 to 

7 years, which does not align with much longer duration (10 to 25 years) solar PV leases and PPA contracts. Other 

commercial building assets are held real estate entities, such as REITs, that are challenged to monetize tax benefits (see 

“Third-party with REIT” in Appendix C for further discussion). In addition, many real estate investment entities do not 

pursue solar because they consider it an atypical asset or income stream for other business-related reasons. 

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SOFTWARE 

TOOLS 

DESIGN 

TEMPLATES 

CONSUMERTARGETING 

STRATEGIES 

assessment tied to 

bid prep software 

Next Gen: site 

assessment plus 

on-location bid 

prep on initial site 

Standardized 

system designs 

Marketing 

programs 

& partnerships 

(e.g., Solar City, 

Home Depot) 

Lead qualification 

& generation 

programs 

Consumerawareness 

campaigns 

(including online 

outreach) 

Undefined 

(includes 

innovative 

financing to open 

ENABLED REDUCTION FROM 2010 BASELINE ($0.19/W) 

2014 2015 2016 2017 2018 2019 2020 

NEW MARKETS new markets $0.00 $0.00 $0.00 $0.00 

coupled with 

new customer 

acquisition 

advancments) 

SUM OF REDUCTIONS ($/W)* $0.04 $0.06 $0.09 $0.11 

RESULTING AVERAGE COST ($/W) 

*For any given year, equal to (2010 baseline of $0.19/W]- (sum of cost reductions] 

· Individual values may not add up to totals 

owing to rou nding 

D ROADMAP TARGET • REALIZABLE MEDIUM UNCERTAINTY 

LOW UNCERTAINTY • HIGH UNCERTAINTY 

Table 4. Commercial Customer Acquisition Roadmap 

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Figure 5. Commercial PV customer acquisition costs: Current trajectory and roadmap 

Figure 6. 2020 commercial PV customer acquisition cost reductions: Current trajectory and roadmap 

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4 Permitting, Inspection, and Interconnection 

Germany has an approximately $2.00/W PV price advantage over the United States. While this cost 

differential can be attributed, in part, to variation in federal policies, greater U.S. permitting, inspection, 

and interconnection costs contribute as well. German permitting requirements are minimal compared to 

many parts of the United States. The feed-in tariff registration form, which enables grid-connected solar 

residences to receive federal incentives, is the only German paperwork required for PV systems. 

Typically, this form takes as little as five minutes to fill out and is conveniently submitted online. In 

contrast, most U.S. AHJs require a combination of engineering drawings, building permit, electrical 

permit, design reviews, and multiple inspections before approving a PV installation. A recent study by 

Clean Power Finance (Tong 2012) found that 36% of installers limit or avoid sales efforts in certain 

jurisdictions due to cumbersome permitting processes. This impedes overall market growth, while 

decreasing competition, thereby increasing system prices in these areas. Moreover, the lack of 

standardization in permitting and regulatory requirements across the country’s more than 18,000 AHJs 

and more than 5,000 utility service territories adds considerable time and cost to project completion, as 

installers expend resources determining the specific requirements of each AHJ and utility. As a result, it 

takes on average only five labor hours for German installers to complete the permitting, inspection, and 

interconnection process for residential PV, compared to 19 labor hours for U.S. installers (Seel et al. 

2012). 

At the commercial scale, interconnection procedures can be especially costly and can deter project 

completion entirely. However, for commercial PV, we included PII in the “other soft costs” category 

because no comprehensive data exists for benchmarking interconnection study costs and permitting fees 

in the commercial sector. Anecdotally, interconnection study costs are reported to vary substantially— 

from $2,500 to more than $30,000—depending on PV penetration rates in a given utility service 

territory and system size. Due to the lack of existing data, this study quantitatively roadmaps cost 

reductions for residential PV only and assesses commercial-scale PII based on qualitative data and 

interview findings. Collecting comprehensive PII cost data for commercial PV systems remains an area 

for future research. 

4.1 Residential Permitting, Inspection, and Interconnection Roadmap 

Average 2010 PII labor costs total $0.11/W for residential PV systems, including typical delays, travel 

time, and paperwork completion related to permit preparation ($0.05/W), permit package submittal 

($0.02/W), permitting inspection ($0.03/W), and interconnection ($0.01/W). An assumed average 

permitting fee of $430 adds $0.09/W (Sunrun 2011) for a total of $0.20/W, although permitting fees 

vary widely across jurisdictions (Vote Solar 2012). Achieving the SunShot price target requires a 

reduction in total PII labor costs and fees from $0.20/W to $0.04/W.22 Note: PII cost benchmarks are for 

completed installations and do not include the cost of projects which fail due to regulatory and policy 

hurdles. Quantifying the impact of these market barriers would likely add to total PII costs, but is 

outside the scope of this analysis. 

Our findings suggest five solution sets that can decrease residential PII expenditures: (1) standardization 

of requirements (2) transparency of requirements, both of which reduce the time installers spend 

determining jurisdiction specific permitting processes; (3) online permit application submittal, which 

reduces travel and wait time at the permitting office; (4) lowering market-wide average permitting fees 

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from $430 to $250, which decrease fixed permitting costs; and (5) interconnection best practices, which 

reduce labor by lowering application expense and wait time. Beyond these, a sixth, undefined solution 

set is included to meet the PII cost target of $0.04/W. Vermont’s PV registration model, for installations 

of 10 kW and smaller, exemplifies a standardized, streamlined PII process. An installer or homeowner in 

Vermont can apply for all necessary permits with a single registration form that specifies system 

components, configuration, and compliance with interconnection requirements. If no opposition or 

interconnection concerns are raised within 10 days of registration, a Certificate of Public Good is 

granted and the project is considered approved. 

Table 5 shows the SunShot residential PII roadmap. Compared with the current-trajectory case (in which 

PII costs decline to $0.14/W by 2020), achieving the roadmap target requires additional cost reductions 

of $0.10/W by 2020 (see Figure 7 and Figure 8). A plausible cost-reduction pathway for achieving the 

roadmap PII target is not immediately apparent, for even when assuming near-universal adoption of at 

least two of the four labor-saving CROs across AHJs, total PII costs miss the 2020 target by at least 

$0.03/W. The roadmap therefore includes an undefined solution set that likely combines unknown 

regulatory mechanisms that enable wider-scale uniformity across AHJs, an average fee of $100 [instead 

of $250 (i.e., in the lower permitting fees solution set)], 23 and streamlined inspection. In most 

jurisdictions, finalizing a PV installation requires at least two inspections, one by either the city or 

county and another by the utility. Increased coordination between the utility and the city/county 

inspectors and combining multiple inspections into a single, streamlined process would enable time and 

cost savings. However, because reducing PII costs to target levels depends on regulatory and policy 

reform, reaching the roadmap PII target is highly uncertain. Additional PV cost reductions will likely 

need to be achieved in other soft-cost areas to meet aggregate SunShot targets. 

23 Assumes sufficient efficiency improvements in municipal permit processing to ensure an average fee of $100 covers AHJ 

costs 

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Table 5. Residential Permitting, Inspection, and Interconnection Roadmap 

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at www.nrel.gov/publications.
 

 

 

Figure 7. Residential PV permitting, inspection, and interconnection costs: Current trajectory and 

roadmap 

Figure 8. 2020 residential PV permitting, inspection, and interconnection cost reductions: Current 

trajectory and roadmap 

19
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4.2 Commercial Permitting, Inspection, and Interconnection 

Because no comprehensive cost data exists for commercial PV interconnection studies and permitting 

fees, we quantitatively roadmap cost reductions for residential PV only and assess commercial-scale PII 

based on qualitative data and interview findings. 

Interconnection costs typically consist of an interconnection agreement application fee, labor for 

agreement application completion, engineering labor for supplemental documentation (such as line 

drawings, output calculations, and an energy audit), wait time for application processing, equipment 

costs (such as an external disconnection switch or transformer), and labor costs for final inspection. For 

proposed PV systems that pass initial review screens and are connected to an existing load base feeder, 

interconnection costs are relatively predictable. In contrast, for PV systems that do not pass initial 

review screens, utilities generally require at least two additional interconnection studies, and costs vary 

widely. For most interconnection screening procedures, projects in an area of high distributed generation 

(DG) penetration (above 15% of peak load) trigger the need for these supplemental studies at an average 

cost of $25,000. Typical turnaround times vary; interviewees cited a range of eight weeks to four months 

but also noted that when supplemental studies are required the review process rarely has a defined 

timeline, which can lead to project delay and cancellation. 

While detailed studies are most commonly required for systems larger than 250 kW, the initial screening 

criteria and 15% threshold apply to systems of all sizes, and even residential systems proposed in areas 

of high DG penetration have been quoted supplemental interconnection study fees of $25,000. Overall, 

interview findings indicate that implementing interconnection best practices has the greatest potential to 

reduce commercial-scale PII costs, including setting minimum response and review times for 

interconnection applications and supplemental studies, defining an interconnection approval process for 

systems generating above 15% peak load, and streamlining administrative requirements. 

Emerging bulk transmission and distribution load-flow software, which enables the utility to model grid 

impacts of proposed PV based on total DG penetration rather than feeder by feeder, also could 

significantly reduce commercial PII costs. These programs can reduce interconnection study fees paid 

by the developer from $25,000 down to $5,000 and reduce turnaround time for initial determination to 

15 days or less. In the long term, linking load-flow program data with an online permitting and 

inspection interface could further enable PII cost reductions to SunShot target levels. 

5 Installation Labor 

Installing a PV system requires both electrician and non-electrician labor and includes assembling the 

module, racking and mounting it to the roof (or ballasting for commercial systems), mounting PV 

panels, running conduit, and connecting the inverter, meter, and disconnect. In the United States, 

streamlining residential rooftop installations is complicated by the heterogeneity of installation 

platforms, roof materials, electric systems, and utility requirements. Customer preferences also vary 

drastically. Optimizing the system typically requires customizing both system design and installation 

and incorporating shading, roof obstructions, and load limitations. As a result, it is difficult for installers 

to standardize processes and challenging for technology manufacturers to further integrate hardware 

without compromising needed system flexibility. 

For the commercial sector, we limit this analysis to roof-mounted commercial applications, which are 

usually, but not always, flat roofs. Relative to residential, usable roof space is typically less constrained 

20
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by shading, enabling more design options. Flat roof structure enables lower labor costs by facilitating 

movement of workers and often by enabling systems to be ballasted, avoiding the additional step of roof 

penetration. Given the large size of these systems, commercial systems benefit from economies of scale 

in installation labor as crews gain efficiency, and electrician labor makes up a smaller portion of overall 

labor hours. 

Inherently, integrators and installers pursue efficiencies wherever possible. While some interviewees 

indicated few additional technology or process efficiencies were possible, many suggested that further 

installation labor cost reductions can be achieved by focusing on increasing labor efficiency or reducing 

the steps required to install a PV system via hardware innovation. 

5.1 Residential Installation Labor Roadmap 

Average 2010 labor costs for residential PV systems total $0.59/W—$0.33/W for roofer labor and 

$0.26/W for electrician labor. The cost associated with roofer labor is greater because the higher 

respective labor requirements (49 hours per installation for roofers versus 26 hours for electricians) more 

than offset the lower roofer wages ($40.49/hr for roofers versus $60.12/hr for electricians). Achieving 

the SunShot price target requires a reduction in total installation labor costs from $0.59/W to $0.12/W. 

Our findings suggest five solution sets that can decrease residential labor expenditures: (1) integrated 

racking, (2) module-integrated electronics, (3) prefabrication, (4) plug and play, and (5) solar-ready 

homes. Beyond these, a sixth, undefined solution set is included to meet the installation labor cost target 

of $0.12/W. Table 6 shows the residential PV installation labor roadmap. Compared with the currenttrajectory case (in which labor costs decline to $0.38/W by 2020), achieving the roadmap target requires 

additional cost reduction of $0.26/W by 2020 (see Figure 9 and Figure 10). This could be achieved 

through increased market penetration of Generation 1 plug-and-play systems (combined integrated 

racking and AC modules) and earlier commercialization of a transformative, off-the-shelf system such 

as Generation 2 plug-and-play. Generation 2 plug-and-play has 0% market penetration by 2020 in the 

current-trajectory case, compared to 20% in the roadmap. An increase in either plug-and-play solution 

would reduce the required penetration of more piecemeal CROs, such as AC modules and integrated 

racking. However, for both Generation 1 and 2 plug-and-play, reaching roadmap market penetration 

levels is uncertain. Thus, an undefined solution is included, which could entail a combination of 

additional equipment standardization and classification and/or reduced through-roof penetration. 

Further, additional labor cost reductions may be achieved via increased business process efficiency, such 

as a steadier pipeline (less idle time/overtime), reduced hours spent on reworking errors, and/or more 

efficient crew routing. Because the precise combination of mechanisms of this solution is undefined, this 

is considered highly uncertain. 

21
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INTEGRATED 

RACKING 

MODULE 

INTEGRATED 

ELECTRONICS 

PLUG AND PLAY 

SOLAR-READY 

HOMES 

UNDEFINED 

*For any given year, equal to [2010 baseline of $0.59/W]- [sum of cost reductions] 

• REALIZABLE MEDIUM U NCERTA INTY 

' Individual values may not add up to totals ow ing to ro unding D ROADMAP TARGET • HIGH UNCERTAINTY 

Table 6. Residential Installation Labor Roadmap 

22
	 This report is available at no cost from the 

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at www.nrel.gov/publications.
 

 

Figure 9. Residential PV installation labor costs: Current trajectory and roadmap 

Figure 10. 2020 residential PV installation labor cost reductions: Current trajectory and roadmap 

23
	 This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 

at www.nrel.gov/publications.
 

 

5.2 Commercial Installation Labor Roadmap 

Median 2010 labor costs for commercial PV systems of 250 kW or smaller total $0.42/W—$0.32/W for 

roofer labor and $0.10/W for electrician labor (8 hours of installation labor per kilowatt). Achieving the 

SunShot price target requires a decrease in total installation labor costs from $0.42/W to $0.07/W. 

Our findings suggest four solution sets that can decrease commercial installation labor costs: (1) 

integrated racking, which reduces balance of system hardware; (2) module-integrated electronics, which 

reduces cable runs; (3) prefabrication, which streamlines installation; and (4) 1,000-volt direct current 

(DC), which enables more modules wired together per string. Table 7 shows the SunShot commercial 

installation labor costs roadmap. The commercial rooftop market is generally better poised to take 

advantage of streamlining solutions than the residential rooftop market due to more homogenous roof 

space and fewer design constraints. Even at a current-trajectory pace, the market is well positioned to 

move toward large-scale adoption of installation-labor-saving CROs. Thus, under the current trajectory, 

installation labor costs decline to $0.12/W by 2020, and achieving the roadmap target requires additional 

cost reductions of $0.05/W by 2020 (see Figure 11 and Figure 12). Near-universal adoption of integrated 

racking (90% market penetration in the roadmap) provides one possible path to this needed, additional 

cost reduction. While higher-than-anticipated market penetration of the other CROs would also enable 

installation labor costs to decline to target levels, the near-universal adoption of integrated racking is 

more plausible, albeit uncertain. 

24
	 This report is available at no cost from the 

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INTEGRATED 

RACKING 

MODULE INTEGRATED ELECTRONICS 

1,000- VOLT DC 

*For any given year, equal to [2010 baseline of $0.42/W]- [sum of cost reductions] 

'Individual values may not add up to totals 

owing to rounding 

D ROADMAP TARGET • REALIZA BLE MEDIUM UNCERTAINTY 

LOW UNCERTAINTY • HIGH UNCERTAINTY 

Table 7. Commercial Installation Labor Roadmap 

25
	 This report is available at no cost from the 

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Figure 11. Commercial PV installation labor costs: Current trajectory and roadmap 

Figure 12. 2020 commercial PV installation labor cost reductions: Current trajectory and roadmap 

26
	 This report is available at no cost from the 

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6 Financing 

Financing strategies play a significant role in reaching SunShot targets. For the financing roadmaps, we 

interviewed more than 40 industry experts. On average, interviewed experts foresaw substantial 

lowering of financing cost of capital between 2013 and 2020. Specifically, the current trajectory could 

lead to an average decrease of 5.3% [~530 basis points (bps)] for residential and 4.7% (~470 bps) for 

commercial by 2020. 

The projected improvement does not happen “on its own.” The decreases are expected to result from the 

effects of all known and predicted consortia, governmental, corporate, entrepreneurial, and nonprofit 

actions targeted at improving finance for distributed solar. In early 2013 these actions were considerable 

and varied. Achieving goals set forth in the roadmap case would require all known actions plus 

additional and different actions. 

The residential and, to a lesser degree, commercial markets have experienced a boom in tax-equitybacked, third-party finance. Industry data suggest third-party finance supported nearly half of installed 

residential systems in 2011, and about three-quarters in 2012. While important for customer uptake and 

rapid market growth, this type of financing has a high cost of capital, which could impede the 

competitiveness of PV. 

According to many interviewees, the limited supply of tax-equity participants is a key contributor to 

high third-party financing costs. Still, tax equity remains a prevalent source of financing because of the 

ability to monetize the federal investment tax credit (ITC) and accelerated depreciation. 

As a result of third-party financing growth, customer facing costs of distributed PV are now measured in 

cents per kilowatt-hour and dollars per month, rather than dollars per watt. Cost of capital can have a 

substantial influence on customer-facing costs. Reducing either the cost of capital or the “other soft 

costs” (inclusive of finance transaction costs) to roadmap targets, while holding the other constant, 

results in nearly identical reductions in the cost of solar PV, as measured in cents per kilowatt-hour.

24 

Achieving cost reductions on a dollar-per-watt basis for “other soft costs,” including the cost of 

transactions, such as legal fees, and ongoing asset management costs, such as fund administration, is 

believed to be critical to the continued growth of the distributed PV market. This report, however, 

benchmarks only cost of capital. 

Methodology 

All estimates of WACC reduction were assumed to be nominal, and most source data on investment 

return rates were given in nominal terms. All nominal rates were corrected downward by an inflationary 

rate of 2.6% to arrive at an approximate real rate. 25 

24 Lowering cost of capital for residential PV from 9.9%-real. (2012 average) to 3.0%-real (2020 Roadmap Case target) 

without any reduction in the $1.86/W other/profit cost category (so $2.99/W total cost in 2020) produces roughly the same 

2020 LCOE as 9.9%-real and $1.50/W (roadmap target) total cost. In making this statement, it is assumed for calculation 

simplicity purposes that there is full tax-benefit capture in both cases.

25 The 3-year (2010 to 2012) compounded annual growth rate of the Consumer Price Index (CPI) from the U.S. Bureau of 

Labor Statistics was 2.61%. This inflationary rate was chosen because it is representative of recent macroeconomic 

conditions. 

27
	 This report is available at no cost from the 

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at www.nrel.gov/publications.
 

 

 

 

 

 

 

 

 

All WACC values26 in this report are defined as synonymous with “minimum expected returns.”In 

circumstances of high market inefficiency, returns may be significantly higher than the minimum 

expected returns. However, we deemed WACC a reasonable metric for assessing the minimum expected 

returns of an investment class, assuming PV assets are sufficiently low risk to merit capital at or close to 

that WACC. 

CROs in the roadmap are named to highlight their unique attributes, but these solutions are all complete 

financing vehicles employing one to three distinct products, such as developer equity, homeowner 

equity, commercial host equity, tax equity, utility equity, other equity sources, and debt products. . 

Markets were segmented into 12 residential and 15 commercial CROs that sufficiently cover average 

market characteristics and reflect interviewee expectations that finance CROs would be highly variable. 

This variation is due to the diverse interests of residential customers and commercial real estate types. 

Additional variety is due to state and utility territory regulatory dynamics, investment appetites of 

different and competing investment sources, and degree of utility engagement in solar PV. Appendix C 

provides extended descriptions of the CROs. 

Not all CROs reduce the cost of capital. Some, like asset-backed securitization (ABS) for subprime 

residential customers, increase the cost of capital but expand the market. Thus, this roadmap was 

constructed with an eye toward the changes likely to occur as businesses work to expand the solar 

market, not just reduce cost of capital. 

We did not directly consider asset backed securities (ABS) and yieldCos or similar structures which 

provide capital to projects years after completion. However, we did consider those structures if they 

provided capital at project initiation or shortly after project completion. In addition, we indirectly 

considered the role of viable secondary financing in enticing initial sources of capital. 

26 All estimates of WACC reduction impact for a given solution, cited by interviewees, were assumed to be nominal, and 

most source data on investment return rates were found in nominal terms. Many interviewees indicated the nominal nature of 

their responses by stating that their estimates of cost of capital were predicated on continued, historically low, “risk free” 

rates, such as short-term Treasury notes, LIBOR, and EURIBOR. It is recognized that a nominal rate is a real rate plus 

inflation, not a real rate plus risk-free rate. However, U.S. inflation has held a strong correlation factor with nominal Treasury 

rates when viewed over several decades, albeit multi-year periods of deviation from the correlation have occurred. Due to this 

generally close inflation to risk-free rate correlation over longer periods of time, constant inflation adjustments were made 

between nominal and real throughout the roadmap 2013-to-2020 period. 

28
	 This report is available at no cost from the 

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at www.nrel.gov/publications.
 

 

 

 

 

 

 

 

 

 

 

 

 

 

In this report, “utility finance” is reserved for utilities financing within a regulated territory, whether it 

be via equity, debt, or a utility’s direct role in bringing financing to their customers. Conversely, utilities 

acting as independent power producers (IPPs) are considered developers rather than utilities, and when 

IPPs use tax equity, the financing is considered “standard third party.” Unregulated utility affiliates can 

also take tax-equity positions, which are treated like any other tax-equity investor within the third-party 

finance solution set. 

Ultimately, levelized cost of energy (LCOE) is a more indicative metric of the economic viability of 

solar PV than cost of capital. However, due to great variation in interviewee future expectations for the 

industry to capture tax benefits, particularly with innovative financing products [e.g., crowdsourced 

funding, yieldCos, real estate investment trusts (REITs)], LCOE is not presented in this report. Taxcapture capabilities currently have major impacts on LCOE and will continue to be meaningful when the 

ITC is lower (10% instead of the current 30%) for years 2017 to 2020, as accelerated depreciation has no 

expiry. In the absence of LCOE determinations, the solution sets hold significant implications for the 

monetization of tax benefits.27 

As to changes in federal legislation and regulation, only tax-advantaged entity reclassifications, such as 

master limited partnerships and REITs, were considered. Other federal programs capable of lowering 

renewable projects’ costs of capital (e.g., New Market Tax Credits and Clean Renewable Energy Bonds) 

were not considered. At the state and local level, we excluded additional incentive programs, such as 

direct rebates, debt for solar renewable energy certificates (SRECs), grants, and other upfront 

governmental funding, from the analysis. 

A finance expert review panel was assembled to review the aggregation of data from interviews and 

additional research. More information on the panel is found in Appendix C. 

6.1 Residential Financing Roadmap 

Third-party financing has transformed the residential solar PV market. The long-standing discussion 

around years of payback on a solar system has become moot for most home installations today. Instead, 

the savings are immediate. Solar leases and PPAs cost less than the homeowners’ prior utility rates from 

day one, and homeowners frequently incur no out-of-pocket expenses to initiate the lease or power 

purchase agreement (PPA). Customers appear to value these and other advantages provided by thirdparty financing. However, due to cost of capital, homeowners may find equivalent or lower LCOE by 

purchasing a system. 

The average 2012 residential WACC benchmark was 9.9% in real terms. The benchmark was derived 

from values that were approximately three-quarters third-party financing (GTM-SEIA 2012),28 one-sixth 

cash purchases, and about 7% of other homeowner financing vehicles, including property-assessed clean 

27 For example, third-party finance = high tax benefit capture ; homeowner finance = moderate-to-high ITC benefit capture, 

no accelerated depreciation capture; utility finance = investor-owned utilities have high tax benefit capture but with the ITC 

normalized over rate-basing periods (except on-bill financing which has similar tax benefit captures as homeowner finance); 

commercial host finance = high tax benefit capture; community solar = tax benefit capture dynamics mixed between those of 

utility and third-party finance depending on the financing source

28 Based on the market report, GTM-SEIA (2012) indicated about two-thirds third-party financing in the first half of 2012 

with a steadily upward trend in market penetration for Colorado, Arizona, California, and Massachusetts toward three-fourths 

for a full-year average. 

29
	 This report is available at no cost from the 

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at www.nrel.gov/publications.
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

energy (PACE) loans, mortgages on new-build homes with PV, and specialty loan products, such as the 

Federal Housing Authority (FHA) PowerSaver. Community solar29 and utility on-bill financing 

accounted for about 1% of the 2012 new-build market. Third-party financing was split roughly evenly 

into two CROs: (1) “standard third-party,” involving only developer equity and tax equity and (2) “thirdparty with debt/ABS,” involving debt (as bank loans or securitized debt) as well as developer equity and 

tax equity. In 2012, developers were commonly backed by high cost of capital sources, such as venture 

capital and private-equity (VC/PE), with a notable transition away from these sources in the initial 

public offering (IPO) of SolarCity in December of 2012. Total cost of capital for standard third-party 

financing deals held a WACC of about 14%-real. Achieving the SunShot target requires reducing 

average residential WACC from 9.9%-real to 3.0%-real by 2020 (DOE 2012).30 

Back-leveraging (debt provided at a holding company level above a portfolio fund) was regularly cited 

by interviewees as occurring for at least a couple of third-party financing companies with high market 

share, with a loan to developer equity value (“LTV”) of approximately 0.5. Debt, at about 6%-real, was 

estimated to lower project WACC by about 300 bps below standard third-party financing without debt. 

Such debt was available only for “prime” financing, where credit quality of the project hosts were high 

(FICO score > 680). Though rare in terms of the number of third-party financing companies, 

interviewees considered the share of “third-party with debt/ABS - prime” financing in 2012 relatively 

common in terms of installed capacity. Thus, we estimate that half of the third-party financing in 2012 

benefited from such debt (although the debt in 2012 was considered to be mostly or entirely bank debt, 

not ABS. ) 

Our findings suggest four solution sets that can decrease residential WACC: (1) third-party finance, (2) 

utility finance, (3) homeowner finance, and (4) community solar. Table 8 shows the residential solution 

sets and corresponding CROs. 

6.1.1 Third-Party Finance 

In the context of solar finance, third parties are entities other than a utility or homeowner that provide 

financing for a project, typically with investment cash flows captured via an operating lease or PPA and 

with tax benefits primarily accruing to tax-equity investors. All CROs for third-party finance in this 

report involve external tax-equity partnerships except for “corporate on-balance sheet,”31 which 

describes companies, most likely larger corporations, placing the entire financing (so no tax equity 

partnership) on their balance sheet. A number of innovative—or at least new-to-distributed solar— 

financing products can potentially fit into third-party finance, including direct investment by 

institutional equity and yieldCos. CROs covering a number of variations of third-party financing are 

explained in Appendix C. 

29 Community solar projects generally are not built on residential or commercial building rooftops. However, community 

solar is included in this report due to its unique features including virtual net metering provisions and cash flow dependencies 

on a range of subscribing residential and commercial customers. Classification of community solar into residential or 

commercial markets is based on proportions of subscribers from these two markets.

30 The 2020 target was partially derived from NREL’s SolarDS modeling assumptions for the DOE SunShot Vision Study. 

SolarDS modeling used financing assumptions of mortgage and home equity debt at 80% and homeowner’s equity at 20%. 

For the purposes of this report, debt was calculated at 2.3%-real based on a 50/50 ratio of the 2010-2012 averages of 30-yr 

mortgages (1.7%-real) and 30-year amortization $30,000 home equity loans (2.9%-real). Homeowner’s cost of equity was 

3.1%-real. 

31 Calculation of WACC for CROs with external tax equity assumes a long-term hold by the tax-equity participant for WACC 

calculation simplicity purposes. 

30
	 This report is available at no cost from the 

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at www.nrel.gov/publications.
 

 

 

 

 

 

 

 

 

 

 

6.1.2 Utility Finance 

“On-bill financing/repayment” is the only utility-finance CRO for the residential market considered in 

this report32. While on-bill financing is technically homeowner finance (debt provided to homeowner), 

and on-bill “repayment” can involve repayment of an equity purchase by a third- party, these solutions 

were included in the utility finance solution set because of the active and supportive role of the utility. 

6.1.3 Homeowner Finance 

The homeowner finance solution set includes debt products and standard cash purchases. These CROs 

are expected to become more important if the federal ITC decreases from 30% to 10% as scheduled in 2017. 

They do compete against leases and PPAs today. This competition is partially based upon considerations 

beyond LCOE, such as some homeowner preference for ownership over leasing. CROs in the homeownerfinance set also help homeowners attain solar in regulated utility states that do not allow third-party 

ownership. 

The roadmap case identifies a potential 1.6% (~160 bps) cost of capital reduction over the current 

trajectory. This reduction is primarily achieved through an increase in debt provision to homeowners. 

Refined offerings of specialized solar or bundled distributed energy solution loans, and in particular, 

inclusion of solar in standard real estate lending, could have considerable market impact in the post30%-ITC period. In the roadmap, the two CROs within the homeowner finance solution set that could 

benefit most from this market transition are “mortgage—new build” and “solar loans.” The “solar loans” 

CRO, particularly in the 2017–2020 period, is inclusive of an advancement in home equity loans that 

include PV within the property appraisal value. Achieving the targets for these two CROs by 2020 is 

highly uncertain. 

To allow for the roadmap increase in homeowner finance, all third-party finance CROs, except for 

“corporate on-balance sheet,” featured lower-or-equal penetration than in the current trajectory case. 

A few interviewees anticipate that “cash purchases” will rebound. If roadmap targets are realized, the 

cost of a residential system in 2020 will be $1.50/W (adjusted for inflation against 2010). If a system 

costs ~ $7,500 in 2010 dollars,33 or ~$10,000 in 2020-dollars,34 these interviewees believe fewer people 

will need financing. However, no participants on the expert review panel indicated market penetrations 

above 5% for outright cash purchases in 2020. 

6.1.4 Community Solar 

Finally, the community solar solution set applies to PV projects with virtual net metering. Community 

members subscribe to a commercial-sized PV system located locally but not on their residence premises 

yet receive net-metering benefits. Community solar projects are generally financed through other 

solution sets, namely third-party or direct utility finance, but we separately categorized community solar 

32 Interviewees found only residential debt financing through on-bill financing to be likely, although minority opinions
	

strongly believed in substantial utility residential PV full ownership by 2020. Whether considered likely or unlikely, many
	

interviewees and recent solar conference speakers stated that utilities are the most natural owners of PV systems. However,
	

many interviewees believed utilities will be resistant to equity positions until public utility commissions and state legislatures 

allow for new utility business models.

33 Assumes a 5-kW average system size.
	 34 Assumes consistent inflation rates witnessed from 2010 to 2012 (2.61% per annum).
	

31
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at www.nrel.gov/publications.
 

 

 

 

 

 

 

 

 

 

because it entails unique investment risks and opportunities, utility value propositions and challenges, 

and policy treatment.35 

Table 8 shows the SunShot residential finance roadmap. Compared with the current trajectory case, 

which reduces average WACC to 4.6%-real by 2020, achieving the roadmap target requires an 

additional reduction in WACC of 1.6% (~160 bps) by 2020 to achieve a WACC of 3.0%-real (see 

Figure 13 and Figure 14). 

35 Community solar can benefit from subscriber-sourced financing models (small cooperative investments or broader,“crowdsourced financing,” the latter of which is discussed in the commercial finance section). Direct subscriber financing has been 

limited due to concerns around the federal Securities and Exchange Commission’s (SEC’s) and states’ securities regulations. 

SEC promulgation of rules (still ongoing as of July 2013) stemming from the 2012 Jumpstart Our Business Startups Act 

(JOBS Act) may alleviate these concerns. Crowdsourced funding is sometimes called “community solar,” but for the purpose 

of this report the term “community solar” is reserved for the financing of projects, however achieved, with virtual net 

metering (or comparable) opportunities. 

32
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THIRD-PARTY 

FINANCE 

Third Party with 

Debt!ABS - Prime 

Third Party with 

Debt/ABSSubprime 

Corporate OnBalance Sheet 

Third Party with 

YieldCo 

Third Party with 

Institutiona l Equity 

UTILITY FINANCE On-Bill Financing/ 

Repayment 

HOMEOWNER 

FINANCE 

COMMUNITY 

SOLAR 

Cash Purchase 

Solar Loans 

Mortgage-New 

Build 

Residential PACE 

Community Solar 

SUM OF REDUCTIONS (%-R 

ENABLED REDUCTION FROM 2010 BASELINE (9.9%-REAL) 

2014 2015 2016 2017 2018 2019 2020 

4.8% 4.2% 3.4% 

*For any given year, equal to [2010 baseline of 9.9%]- [sum of cost reductions] 

•individual values may not add up to totals 

owing to rounding 

D ROAD MAP TARGET • REALIZABLE MEDIUM UNCERTAINTY 

LOW UNCERTAINTY • HIGH UNCERTAINTY 

Table 8. Residential Financing Roadmap 

33
	 This report is available at no cost from the 

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Figure 13. Residential PV WACC: Current trajectory and roadmap 

Figure 14. 2020 residential PV WACC reduction: Current trajectory and roadmap 

34
	 This report is available at no cost from the 

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6.2 Commercial Financing Roadmap 

About 0.6 GW36 of small (250 kW or smaller) commercial PV cumulative capacity existed in the United 

States as of the end of 2012, less than 10% of cumulative U.S. solar capacity. Where references existed 

that addressed this small market segment, 250 kW or smaller was not the consistent market descriptor. 

Because clear penetration rates of prevailing finance solutions for this small market segment were not 

attainable, we relied on general commercial market insights and derived resolution on this smaller 

segment when possible. 

Only some interviewees distinguished between large and small commercial projects. However, the 

interviewees made clear that one-off financings with tax equity, bank loans, or bonding are rare for 250 

kW or smaller commercial projects. Transaction costs are often prohibitively high for these small deals 

when evaluated as singular investment opportunities. As with residential projects, third-party financing 

for small commercial projects is through portfolio funds that apply standard leasing criteria to a set of 

projects. However, for small commercial projects, portfolio fund approaches are more challenging than 

residential when trying to tie in a diversity of project hosts. This challenge is partly due to the lack of a 

standard credit review system for entities owning commercial buildings.

Our research yielded an average 2012 WACC of 9.2%-real, with small commercial PV financed 

approximately 42% from third-party finance, 9% from utility finance, 47% from host (typically building 

owner) equity, and 2% from community solar. 

Third-party finance was dominated (roughly five-sixths) by “standard third-party” financing—the 

pairing of developer equity with tax equity at a WACC of about 15%-real. The remaining third-party 

finance in 2012 involved private debt associated with a portfolio fund37 at a WACC of about 13%-real 

and the coupling of municipal bonds with third-party portfolio funds on MUSH38 buildings (9%-real). 

For host finance, cash purchases constituted nearly 90%, and the remainder included low levels of real 

estate investment trust (REIT) financing,39, commercial PACE, and municipal bonding for MUSH 

projects. Solutions undefined to the authors are assumed to have achieved about 1% penetration, and are 

included in a broad “undefined solution” CRO. Achieving the SunShot target requires reducing 

commercial WACC from 9.2%-real to 3.4%-real by 2020. 

36 NREL’s Open PV Project (openpv.nrel.gov/search) lists 428 MW of PV projects nationwide as fo December 31, 2012, 

between 20 kW and 250 kW. In this capacity range, projects would likely be commercial or, more likely, single-family 

residential. It should be noted that NREL’s Open PV Project depends on voluntary reporting of projects, and thus not all 

projects are recorded.

37 Such as SolarCity and Bank of America-Merrill Lynch’s “SolarStrong” program on multi-family buildings. 38 MUSH stands for municipal (state/local government), universities, K-12 schools and hospitals. 

39 Most interviewees cited that favorable IRS letter rulings, which had not occurred, would be necessary to enable REIT solar 

financing. However, several conference panelists cited that start-up solar-REIT companies are “active” in deal financings. 

This “active” description might have referred to non-REIT companies that hoped to become REITs upon receipt of positive 

IRS letter rulings. Following the interview period, Greentech Media posted that Hannon Armstrong Sustainable Infrastructure 

Capital had received a private letter ruling (not made public by the IRS as of June 16, 2013) in February 2013 in relation to 

REIT finance in renewable energy (Trabish 2013). Hannon Armstong made an initial public offering as a REIT on April, 

17, 2013, but at that time it remained unclear if their intended financing activities in solar qualified as “good” income or 

assets for REIT- status, or if these activities were permitted under the minority “bad” income and asset ownership allowances 

for REIT- status. 

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Our findings suggest four solution sets that have the potential to decrease commercial WACC: (1) thirdparty finance, (2) utility finance, (3) host finance, and (4) community solar. 

6.2.1 Third-Party Finance 

Third-party finance for commercial PV involves financing by an entity other than a utility or building 

owner (host). Tax benefits for CROs in the third-party finance solution set primarily accrue to outside 

tax-equity investors except for “corporate on-balance sheet.” Modeling of solutions with external tax 

equity assumes a long-term hold by the tax-equity participant for simplicity. Another CRO in 

commercial financing similar to residential financing is “third-party with debt/ABS,” though 

interviewees only saw a market opportunity for high credit quality MUSH and business offtakers. In 

other words, no “subprime” equivalent was suggested for commercial third-party financing. 

Interviewees also cited “third-party with crowdsourced funding” and “MUSH: muni bonds + thirdparty.” Both involve specialized debt instruments that interviewees thought were better suited for the 

commercial market. See Appendix C for expanded CRO descriptions. 

Yield-oriented investment vehicles were separated into two solutions for the commercial market: “thirdparty with yieldCo” and “third-party with REIT.” Many interviewees believed REITs would emerge as a 

significant financing source for commercial solar. Because of this clarity, the REIT solution was broken 

out. See Appendix C for further explanation. 

6.2.2 Utility Financing 

Utilities expressed more interest in financing commercial projects than residential projects. Both 

municipal and investor-owned utilities (IOUs) have fully financed (i.e., for IOUs this means “ratebased”) commercial PV systems in their service territories, and utilities may be able to bring in external 

tax equity while holding developer equity positions themselves. The latter partnership scenario (“utility 

equity and tax equity”) has been practiced in IPP investing for utility-scale projects. The authors are not 

aware of these partnership investments in regulated territories for small commercial PV, and enabling 

them might require public utility commission (PUC40) regulatory changes. 

In the roadmap case, full utility ownership achieves 14% market penetration in 2020, up modestly from 

13% in the current-trajectory case. Commercial PACE achieves 9% market penetration in 2020, up from 

5% in the current-trajectory case. 

6.2.3 Host Finance 

Host finance describes ownership by the host and includes direct cash purchases of PV systems by hostsite companies and loans to host companies. Host finance is likely the greatest opportunity for financing 

innovation for small commercial PV. Short investment time horizons, perceptions of solar as a non-core 

business activity, and split incentives for energy cost savings between building owners and tenants may 

hinder innovations in host-finance solutions. 

40 All primary regulatory commissions governing utility activity within states are called “PUCs” in this report. It is 

recognized that some state regulatory commissions are actually called a PUC, such as the California and Colorado Public 

Utility Commissions, several others are called Public Service Commissions, such as the Maryland and Florida Public Service 

Commissions, and others have names unique to the state. Two examples are the Connecticut Siting Council and the Nebraska 

Power Review Board. Texas has multiple entities holding responsibilities usually housed in a single state PUC. 

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Commercial PACE is a structured solution that can solve several misalignments and credit concerns. 

However, interviewees had divergent views on commercial PACE penetration. Only a few indicated 

market penetration would be considerable. In the current trajectory, PACE penetration is 5%. In the 

roadmap case, penetration is nearly double that at 9%. Even at 9% penetration, availability of host 

finance may not meet demand. 

To achieve the additional 1.1% (~110 bps) reduction from the current trajectory to meet the roadmap 

target, we assumed an undefined host finance CRO with a low WACC of 1.9%-real is required. 

Penetration of the undefined host finance CRO would need to meet approximately a quarter of the 

market’s financing needs. This undefined CRO, likely to actually be a mixture of CROs, must include 

financing innovations that overcome challenged credit conditions of building owners and a number of 

real estate investor misalignments. This undefined CRO may involve special rooftop property 

rights/easements, nuanced energy service agreements, or lending products that include energy savings in 

the appraised value of the real estate. 

A number of other CROs contribute to the host finance solution set in the roadmap case. “Green bonds” 

(state- and local-government-enabled specialty bonds and loan guarantees with an estimated WACC of 

1.7%-real) achieve 3% market penetration in 2020, up from 0% in the current-trajectory case. 

6.2.4 Community Solar 

Finally, the community solar solution set applies to PV projects with virtual net metering. Community 

solar power is generally offered through a contracted subscription program to multiple power offtakers. 

Though in some locations, such as in Pennsylvania, commercial PV can be aggregated with geographic 

and site ownership limitations, providing virtual net metering for a single commercial customer. 

Table 9 shows the commercial finance roadmap. Compared with the current-trajectory case (which 

reduces average WACC to 4.4%-real by 2020), achieving the roadmap target requires an additional 

reduction in WACC of 1.1% (~110 bps) by 2020 to reach 3.4%-real.

41 

To allow for the increased roadmap CRO penetrations addressed above, most notably the new undefined 

solution(s) for host finance, several CROs had their penetrations decreased in the roadmap from the 

current trajectory. All of the third-party CROs had their penetrations decreased except for “corporate onbalance sheet.” Other CROs (MUSH with debt/bonds, cash purchase, and community solar) were 

decreased because their WACCs were deemed too high in light of competition against the emerging 

undefined solution at 1.9%-real. 

41 The difference between the current trajectory (4.4%-real) and roadmap case (3.4%) is 1.1%—not 1.0%—due to significant 

figures not shown. 

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THIRD-PARTY 

FINANCE 

HOST 

FINANCE 

COMMUNITY 

SOLAR 

ENABLED REDUCTION FROM 2010 BASELINE (9.2%-REAL) 

2014 2015 2016 2017 2018 2019 2020 

5.1% 4.4% 4.0% 3.4% 

*For any given year, equal to [2010 baseline of 9.2%]-[sum of cost reductions] 

' Individual values may not add up to totals 

owing to rounding 

D ROADMAP TARGET • REALIZABLE MEDIUM UNCERTAINTY 

LOW UNCERTAINTY • HIGH UNCERTAINTY 

Table 9. Commercial Financing Roadmap 

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Figure 15. 2020 commercial PV WACC reduction: Current trajectory and roadmap 

Figure 16. 2020 commercial PV WACC reduction: Current trajectory and roadmap 

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7 Key Actors and Stakeholders 

This section discusses the actions required by the multiple market actors and stakeholders involved in 

realizing the roadmap targets. “Radar charts” illustrate findings on the required level of engagement 

related to customer acquisition, PII, installation labor, and financing. In these charts, a more outwardfrom-center intersection with the stakeholder axis represents greater needed/anticipated action. First, we 

assigned stakeholder impact levels on a 0 to 4 scale (0 = lowest impact, 4 = highest impact) for each 

CRO based on interview findings. These impact levels were then multiplied by the cost reductions 

enabled by 2020 ($/W or WACC) in the roadmap and summed for all CROs for that stakeholder type. 

Each chart is normalized to the largest stakeholder’s impact for each of the four soft-cost areas. 

For example, in Figure 18 (customer acquisition), developers/installers and service providers are 

identified as the most active stakeholders in achieving the roadmap cost reductions, while the required 

level of engagement from the federal government and the financial community is lower. The charts 

represent total action between 2013 and 2020—not the difference in action between the currenttrajectory case and the roadmap. The current trajectory requires considerable stakeholder action, and 

much of that activity is embedded in the overall action required for the roadmap case. For simplicity, 

residential and commercial market actor/stakeholder burdens are combined with equal weighting. 

As the following discussion shows, actors and stakeholders participating to achieve cost reductions vary 

substantially by category. Achieving roadmap reductions will require further leveraging of key 

stakeholders. While categories are intended to be mutually exclusive, in reality the functions of various 

actors/stakeholders are continuously evolving and may overlap with other categories. Furthermore, no 

actor/stakeholder works in a silo, and achieving an objective will often require the engagement of other 

groups. 

7.1 Customer Acquisition 

7.1.1 Developers/Installers 

The greatest engagement in customer acquisition is required from developers/installers (see Figure 17). 

Installers often create a suite of standard system designs to apply to sites with common parameters, 

which decreases costs, especially when designing systems for leads that are not yet sold. Most installers 

interviewed considered this a sound business practice that will become more prevalent. In addition, 

when developers reach out to and partner with big-box retailers and national corporations, such as 

Lowes and Home Depot, mainstream consumers become increasingly exposed to PV. Corporations and 

national organizations, such as Honda and NREL, are beginning to include PV options as benefits 

(SolarBenefits Colorado; Honda-SolarCity partnership) to their employees and customers. 

7.1.2 Service Providers 

The next-highest required engagement is from service providers.42 Information technology and software 

development companies are developing tools to reduce customer acquisition costs. The DOE SunShot 

Incubator Program is supporting multiple projects to develop tools that reduce these costs, including an 

online quoting system (EnergySage.com), advanced siting tools (simuwatt), and sales process software 

(Genability). 

42 Services are often provided by installers, but in this section they are assumed to be provided by separate, non-installer 

entities. 

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7.1.3 Other Stakeholders 

Among the actors/stakeholders with lower required engagement, utilities and PUCs as well as state and 

local governments determine the business models (such as virtual net metering, community solar, and 

third-party ownership) that are allowed in a region, which affects customer acquisition. Real estate and 

construction companies play a role in opening access to new customers. State and local governments 

(e.g., the City of Portland) and non-profit organizations (e.g., SmartPower) can administer group PV 

purchasing, or “solarize,” programs, which provide a trusted venue for consumer education in addition 

to customer acquisition. The federal government plays a role providing research and development 

(R&D) to support innovative, game-changing technologies that help reduce soft costs, as seen with 

information technology/software product development through the DOE SunShot Incubator Program. 

State and Local
 

Government
 

Equipment Providers Developers / Installers and Standards Orgs 

Federal Government 

Utlities and PUCs Service Providers 

Real Estate and 

Construction 

Companies 

Financial Community 

Figure 17. Customer acquisition actors and stakeholders 

7.2 Permitting, Inspection, and Interconnection 

State and local governments have the biggest role in improving PII processes and reducing associated 

costs (see Figure 18). They are faced with the challenge of streamlining bureaucratic hurdles and 

reducing fees to cost recovery levels, while ensuring safety and reliability. Similarly, because utilities 

and PUCs oversee interconnection requirements and processes, their participation is needed to overcome 

interconnection challenges and reduce costs. While the federal government cannot establish regulations 

directly, it can play a key role by supporting regulatory jurisdictions via funding, research, and 

suggested guidelines. 

Developers and installers have an active role to play in improving process inefficiencies because they 

are the main stakeholder group to interface with regulatory bodies. For example, installer participation is 

key to the penetration of innovations, such as a permitting database. 

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State and Local
 

Government
 

Equipment Providers Developers / Installers and Standards Orgs 

Federal Government 

Utlities and PUCs Service Providers 

Real Estate and 

Construction 

Companies 

Financial Community 

Figure 18. Permitting, inspection, and interconnection actors and stakeholders 

7.3 Installation Labor 

Equipment providers play a critical role in reducing installation labor costs by offering innovative laborsaving products (see Figure 19). Providers of different components must collaborate, particularly to 

develop streamlined/integrated systems that can provide a competitive advantage. Equipment providers 

are also responsible for ensuring product marketability. 

Developers and installers must continually study, refine, and optimize interfaces between project 

elements and minimize business process inefficiencies. For example, developing a steady pipeline and 

routing crews effectively can reduce idle crew time. Large volume installers, in particular, are already 

implementing needed business process improvements. 

The financial community is important as well. Private equity plays a key role in providing early-stage 

capital to new technologies that can reduce labor costs. Project financiers, particularly tax-equity 

investors, play a gatekeeper role in enabling the adoption of new technologies in new projects. This is 

currently evident in that module-level electronics have not been deployed on third-party-owned systems 

because they do not yet have an extensive track record. 

State and local governments can enable labor-saving technologies by supporting solar-ready legislation, 

while utilities and PUCs must be informed of new products that affect compliance or present innovative 

configurations. The federal government can provide R&D to support innovative, game-changing 

technologies and improve installer efficiency through support for workforce development and training. 

Real estate and construction companies can play a key role in voluntarily implementing solar-ready 

building practices. 

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State and Local
 

Government
 

Equipment Providers Developers / Installers and Standards Orgs 

Federal Government 

Utlities and PUCs Service Providers 

Real Estate and 

Construction 

Companies 

Financial Community 

Figure 19. Installation labor actors and stakeholders 

7.4 Financing 

Naturally, the financial community has a large role to play in reducing financing costs (see Figure 20). 

Banks must provide securitized debt offerings, institutional investors must participate in direct financing 

or securities purchases, and the real estate lending financial ecosystem—particularly underwriters (e.g., 

Fannie Mae and Freddie Mac)—must allow and help facilitate PV value to be included in appraised 

value and be part of common real estate lending products. This underwriting is perceived to be key to 

the greater penetration of mortgages and home equity loans for solar PV. In addition, large public 

corporations must move into direct, full residential project third-party financing, likely through mergers 

and acquisitions of existing successful PV development companies. Financial community funding 

efforts also include advancement of crowdsourced funding and increased financing of community solar. 

Lastly, a reconceptualization of offtaker (e.g., PPA or lease counterparty) credit and/or new financial 

structures may be needed to enable the undefined commercial solution and realize roadmap targets. 

Whether the credit reconceptualization and/or new structures focus on meter payment history, real estate 

value and tenancy dynamics, and/or other longer-term credit elements is not certain. 

The service provider intersection in Figure 20 is middle-level, as operations and maintenance (O&M) 

and system performance data providers are critical to providing reliable system performance, necessary 

in enticing a lower cost of capital financing. This role is similar to that of equipment manufacturers and 

standard organizations, which can work to make the quality of PV equipment and systems increasingly 

clear to the financial community. 

Real estate and construction companies have a strong voice within the real estate finance community. 

Demand for appraisal value to include PV could go a long way to realizing standard mortgages and 

home equity loans inclusive of PV value. In addition, providing solar-ready homes can increase the 

opportunity set for mortgages to cover PV capital cost. 

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Developers, such as SolarCity, Verengo, and Sungevity, along with lease/PPA-provision companies, 

such as Clean Power Finance and SunRun, have led the transition to third-party financing. Further action 

is required in the following areas: standardization of contracts, greater availability of payment 

performance/default and technical performance data, and standardization of project credit reviews. 

These will support a transition to ABS. These third-party financiers also play a key role in opening up 

the lease and PPA market to subprime credit customers who, today, are usually unable to receive 

financing. 

Utilities and PUCs enable the business models that are allowed in a region, notably third-party finance, 

but they also enable new utility business models that can improve utilities’ desires to participate in 

distributed PV. Perhaps most importantly, they can influence the rate for solar power sold on the grid, 

such as innovative rates that move beyond simple net energy metering and capture the value of the solar 

power for the utility and the broader grid. These rates play a profound effect on the economic 

proposition and therefore also the desire for the customer to attain solar financing or pursue solar at all. 

State and local governments also play a significant role, directly in the case of state “green” bonding 

programs or municipal bonding on MUSH buildings, as well as through collaborative actions between 

municipalities and their municipal utilities, such as community solar. State legislatures can also enact 

some policies that would otherwise be handled by PUC discretion. 

The federal government’s role can enable yieldCo opportunities through legislation [e.g., master limited 

partnership (MLP)] or regulatory (e.g., IRS letter rulings for REITs) actions. Another opportunity for the 

federal government exists around broader tax benefit monetization rule clarity, providing a stable 

accounting foundation underneath third-party financing. Considering the dynamism of solar business 

models and technology, continuous improvement on tax benefit monetization clarity will likely be 

critical to many solar business activities beyond today’s third-party financiers. Also, the federal 

government can play a role in enabling residential solar loans through standard real estate lending 

vehicles in light of the conservatorship role the federal government holds over underwriters Fannie Mae 

and Freddie Mac. 

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State and Local
 

Government
 

Federal Government 

Equipment Providers Developers / Installers and Standards Orgs 

Utlities and PUCs Service Providers 

Real Estate and 

Construction...

Financial Community 

Figure 20. Finance actors and stakeholders 

8 Conclusions, Limitations, and Future Research 

Non-hardware (soft) costs have become a major driver of PV system prices. As a result, aggressive softcost-reduction pathways must be developed to achieve the SunShot PV price targets. The roadmaps 

detailed in this report offer such pathways. They are neither prescriptions nor projections. Rather, they 

draw on industry expertise to plot conceivable courses to the residential and commercial PV soft-cost 

reductions required to achieve the 2020 SunShot targets. They identify specific CROs, quantify the 

potential cost reduction associated with each, and estimate the certainty of achieving these cost 

reductions in relation to expert judgment of the reductions likely to result from today’s current soft-costreduction trajectory. The resulting roadmaps suggest the level of effort that may be required to achieve 

SunShot-level cost reductions in specific soft-cost areas. 

The residential PV roadmap shows a challenging path to the SunShot soft-cost targets (see Table 10). 

Additional reductions of $0.46/W and 1.6% (~160 bps) WACC beyond the current-trajectory reductions 

are required. Overall, customer acquisition has the most certain pathway to its target, although the 

required implementation of several individual site-assessment software and consumer-targeted CROs is 

highly uncertain. Financing has the next-most-certain cost-reduction pathway; the primary challenge is 

enabling low cost of capital and otherwise desirable homeowner financing (i.e., homeowner maintains 

equity, so is not a “third party”). In contrast, the aggregate pathways for PII and installation labor are 

highly uncertain. Because achieving the required PII cost target is nearly impossible with a piecemeal 

approach, an undefined solution set is introduced that may represent the combination of unknown 

regulatory mechanisms that enable wider-scale uniformity across AHJs, a market-wide average fee of 

$100 [instead of $250 (i.e., in the lower permitting fees solution set)] and streamlined inspection. 

Similarly, an undefined solution set is required to achieve the installation labor targets, which may entail 

a combination of additional equipment standardization and classification, reduced through-roof 

penetration, and general business practice efficiency improvements. 

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Table 10. Residential PV Soft-Cost Reduction Roadmap 

The commercial PV roadmap offers a more certain path to the SunShot soft-cost targets (Table 11). 

Additional reductions of $0.11/W and 1.1% (~110 bps) WACC beyond the current-trajectory reductions 

are required. Overall, customer acquisition has a medium uncertainty. Reaching the 2020 target hinges 

on the highly uncertain market penetration of improved site-assessment and design CROs, in addition to 

effective customer acquisition tools that accompany innovative financing solutions for new commercial 

PV markets. In the area of installation labor, commercial PV is more amenable than residential PV to 

streamlined installation practices; thus, achieving the SunShot target by 2020 is more certain. The nearuniversal adoption of integrated racking provides one plausible cost-reduction pathway. Commercial 

financing exhibits an overall medium uncertainty in achieving the roadmap WACC target, similar to 

residential financing. However, the commercial financing path requires the highly uncertain 

implementation of an undefined host-finance CRO (e.g., perhaps special rooftop property 

rights/easements or nuanced energy service agreements) as well as highly uncertain expansions of green 

bond programs and commercial PACE financing. Though we do not develop a commercial PII roadmap, 

our findings suggest that streamlining the interconnection process could reduce the major PII cost 

component substantially. 

Table 11. Commercial PV Soft-Cost Reduction Roadmap 

Regardless of the specific path taken to achieve the SunShot targets, the concerted efforts of numerous 

PV market actors and stakeholders will be required. These include developers/installers, service 

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2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Customer Acquisition 

($/W) $0.67 — — $0.53 $0.49 $0.45 $0.41 $0.36 $0.28 $0.19 $0.12

PII ($/W) $0.20 — — $0.18 $0.16 $0.15 $0.13 $0.11 $0.10 $0.06 $0.04

Installation Labor ($/W) $0.59 — — $0.51 $0.46 $0.42 $0.36 $0.30 $0.24 $0.19 $0.12

Other Soft Costs ($/W) $1.86 — — $1.30 $1.14 $0.97 $0.82 $0.68 $0.56 $0.48 $0.37

Financing (WACC %-real) — — 9.9% 9.4% 8.8% 8.2% 7.7% 7.7% 4.8% 3.4% 3.0%

Total Soft Costs ($/W) $3.32 — — $2.52 $2.25 $1.99 $1.72 $1.45 $1.18 $0.92 $0.65

Total System Costs ($/W) $6.60 — — $4.99 $4.49 $3.99 $3.49 $3.00 $2.50 $2.00 $1.50
 

 

 

providers, the financial community, utilities, PUCs, equipment providers, standards organizations, real 

estate and construction companies, state and local governments, and the federal government. We 

illustrate (in Section 7) how the required participation of each type varies substantially by soft-costreduction category while noting that roles and responsibilities will be complementary and somewhat 

fluid over time. 

This roadmapping study has a number of analytical limitations. To capture market-wide trends, it 

focuses on average effects and does not explore differences at the individual installer or company level. 

Also, the CROs identified have cross cost-category effects, including potentially making certain cost 

categories more expensive. Therefore, we assume that for any CRO to gain substantial market 

penetration, it will reduce LCOE. In addition, the 2020 SunShot targets for each cost category are based 

on the 2010 proportional share of total soft cost. Further refining model assumptions to account for 

different rates of cost reduction across categories would improve the analysis. Finally, the roadmap’s 

dollar-per-watt and WACC targets are not tied to installed-PV-capacity targets. Accounting for installed 

capacity would be particularly relevant for finance solution sets because it would help quantify the 

capital pools necessary to achieve the roadmap targets. 

Our data sources also have limitations. The ITRS, now two decades in existence, applies a year-long, 

multi-working-group approach involving several hundred companies, and therefore, likely receives well 

into the millions of U.S. dollars of in-kind support. This paper represents a small-scale initial soft-cost 

roadmapping effort, depending on market analysis and more than 70 in-depth interviews. The ITRS 

approach likely provides more resolution on solutions, novel approaches for structuring the roadmap, a 

broader set of viewpoints, and results that more accurately represent the average of major stakeholders’ 

views. Most interviewees we consulted were solar industry participants, and their views about the 

industry’s possible advancements may be more optimistic than the views held by a broader, more 

diverse group of stakeholders. 

This report is part of a series of NREL research efforts that will track soft-cost reductions over time and 

quantify the impacts of innovations. Future work will include further elaboration of interconnection 

costs and benchmarks, particularly to show the wide range in residential PV interconnection processing 

times and installer costs. Similarly, future analysis of customer acquisition costs will be improved by 

broadening the costs examined to include those currently in the additional overhead category. 

Additional future work could focus on the geography of the PV market. The distributed PV market is 

regionally diverse, depending on factors such as each locality’s solar radiation, government subsidies, 

and utility rules, rates, and programs. Actionable guidance aimed at the state and local levels—such as 

regionally focused roadmaps with detailed cost-reduction opportunities—would promote achievement of 

the national SunShot targets. 

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GTM-SEIA (Greentech Media – Solar Energy Industries Association). (2012). “U.S. Solar Market 

Insight Report Q2 2012 Executive Summary.” Accessed August 6, 2013: 

http://www.slideshare.net/SEIA/us-solar-market-insight-report-q2-2012. 

GTM-SEIA. (2013). “U.S. Solar Market Insight Report 2012 Year in Review Full Report.” Greentech 

Media Inc. and Solar Energy Industries Association. 

Linder, S.; Di Capua, M. (2012). “Re-Imagining U.S. Solar Financing.” Bloomberg New Energy 

Finance. 

Mendelsohn, M.; Kreycik, C.; Bird, L.; Schwabe P.; Cory, K. (2012). The Impact of Financial Structure 

on the Cost of Solar Energy. NREL/TP-6A20-53086. Golden, CO: National Renewable Energy 

Laboratory. 

Hubbell, R.; Lowder, T.; Mendelsohn, M.; Cory K. (2012). Renewable Energy Finance Tracking 

Initiative Solar Trend Analysis. NREL/TP-6A20-53531. Golden, CO. National Renewable Energy 

Laboratory. 

Pitt, D. (2008). “Taking the Red Tape Out of Green Power: How to Overcome the Permitting Obstacles 

to Small Scale Distributed Renewable Energy.” New York, NY: Network for New Energy Choices. 

Rose, J.; Chapman, S.; Rose, G.; Jackson, R.; Weidman, J.; Christopher, K.; Culley, T.; Keyes, J.; Fox, 

K.; Varnado, L. (2011). “Freeing the Grid: Best Practices in State Net Metering Policies and 

Interconnection Procedures.” New York, NY: Network for New Energy Choices. Accessed August 6, 

2013: http://www.newenergychoices.org/uploads/FreeingTheGrid2010.pdf. 

Schwabe, P.; Mendelsohn, M.; Mormann, F.; Arent, D. (2012). Mobilizing Public Markets to Finance 

Renewable Energy Projects: Insights from Expert Stakeholders. NREL/TP-6A20-55021. Golden, CO: 

National Renewable Energy Laboratory. 

Seel, J.; Barbose, G.; Wiser, R. (2012). Why are Residential PV Prices in Germany So Much Lower 

Than in the United States? A Scoping Analysis. Berkeley, CA: Lawrence Berkeley National Laboratory. 

SMA Solar Technology. (2013). “The Commercial Promise of 1,000 VDC PV Design.” Accessed May 

2013: http://www.sma-america.com/en_US/news-information/resource-center/the-commercial-promiseof-1000-vdc-pv-design.html. 

Smith, S.; Shaio, M.J. (2012). “Solar PV Balance of System (BOS) Markets: Technologies, Costs and 

Leading Companies, 2013-2016.” Greentech Media Inc. 

Sunrun. (2011). “The Impact of Local Permitting on Solar Cost.” San Francisco, CA: Sunrun. 

Tong, J. (2012). “Nationwide Analysis of Solar Permitting and Implications for Soft Costs.” Clean 

Power Finance. Accessed February 2013: http://www.solarpermit.org/CPFDOE%20Permitting%20Study_Dec2012_Final.pdf. 

Trabish, H. (2013). “New Financing Tools Move Renewables from Wall Street to Main Street.” 

Greentech Media. Accessed April 2013: http://www.greentechmedia.com/articles/read/moving-the49
	 This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 

at www.nrel.gov/publications.
financing-of-solar-and-wind-from-wall-street-to-main 

street?utm_source=feedburner&utm_medium=feed&utm_campaign=Feed%3A+GreentechMedia+%28 

Greentech+Media%29. 

Vote Solar. (2012). “Project Permit Interactive Permitting Map.” Accessed September 2012: 

http://votesolar.org/city-initiatives/project-permit/. 

Woodlawn Associates. (2012). “Residential Solar Market Effectiveness.” Presented to U.S. Department 

of Energy, September 2012. 

50
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SOLUTION SET 

SOFTWARE 

TOOLS 

DESIGN 

TEMPLATES 

CONSUMERTARGETING 

STRATEGIES 

COSTREDUCTION 

OPPORTUNITY 

(CRO) 

. .. . . assessment tied 

to 

bid prep 

software 

Next Gen: site 

assessment 

plus on-location 

bid prep on 

initial site visit 

I Standardized 

jsystem designs 

Marketing 

programs 

& partnerships 

(e.g., Solar City, 

Home Depot) 

Lead 

qualification 

& generation 

programs 

Referral 

programs 

Consumerawareness 

campaigns 

(including online 

outreach) 

2010 

MARKET 

PENETRATION 

2% 

10% 

10% 

10% 

6% 

10% 

5% 

*Individual va lues may not add up to totals owing to rounding 

2020 

MARKET 

PENETRATIONCURRENT 

TRAJECTORY 

50% 

65% 

85% 

85% 

30% 

50% 

50% 

2020 

MARKET 

PENETRATIONROADMAP 

70% 

85% 

85% 

85% 

60% 

68% 

60% 

MAX 

REDUCTION 

POTENTIAL 

FROM 2010 

BASELINE 

($0.67/W) 

$0.12 

$0.05 

$0.06 

$0.06 

$0.11 

$0.17 

$0.22 

Appendix A: Supplemental Data Tables 

Table A-1. Residential Customer Acquisition Market Penetration and Maximum Cost-Reduction Potential 

51
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SOLUTION SET 

SOFTWARE 

TOOLS 

DESIGN 

TEMPLATES 

CONSUMERTARGETING 

STRATEGIES 

COSTREDUCTION 

OPPORTUNITY 

(CRO) 

. . . . assessment 

tied to 

bid prep 

software 

Next Gen: site 

assessment 

plus on-location 

bid prep on 

initial site visit 

Standardized 

system designs 

Marketing 

programs 

& partnerships 

(e.g., Solar City, 

Home Depot) 

Lead 

qualification 

& generation 

programs 

Consumerawareness 

campaigns 

(including 

online outreach) 

Undefined 

(includes 

innovative 

financing to 

NEW MARKETS open new 

markets 

coupled with 

new customer 

acquisition 

advancments) 

2010 

MARKET 

PENETRATION 

0% 

0% 

9% 

9% 

9% 

9% 

0% 

*Individua l values may not add up to tota ls owing to round ing 

2020 

MARKET 

PENETRATIONCURRENT 

TRAJECTORY 

9% 

28% 

28% 

19% 

19% 

47% 

0% 

2020 

MARKET 

PENETRATIONROADMAP 

6% 

40% 

34% 

12% 

19% 

40% 

38% 

MAX 

REDUCTION 

POTENTIAL 

FROM 2010 

BASELINE 

($0.19/W) 

$0.02 

$0.05 

$0.07 

$0.10 

$0.02 

$0.10 

$0.16 

Table A-2. Commercial Customer Acquisition Market Penetration and Maximum Cost-Reduction Potential 

52
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SOLUTION SET 

STANDARDIZATION 

TRANSPARENCY 

ONLINE 

PERMITTING 

LOWER FEES 

COSTREDUCTION 

PPORTUNITY 

(CRO) 

Uniform 

permitting & 

inspection 

requirements 

across 

jurisdictions 

(excludes 

interconnection) 

Online database 

of requirements 

by jurisdiction 

Online permit 

application 

submittal 

Market-wide 

average fee 

reduction from 

$430 to $250 

Interconnection 

best practices 

(e.g., rapid 

INTERCONNECTION application 

BEST PRACTICES process, 

defined process 

for systems > 

15% peak load) 

Undefined 

(likely includes 

market-wide 

UNDEFINED average fee 

of $100 and 

streamlined 

inspection) 

2010 

MARKET 

PENETRATION 

10% 

0% 

20% 

3% 

3% 

0% 

*Individual va lues may not add up to tota ls owing to round ing 

2020 

MARKET 

PENETRATIONCURRENT 

TRAJECTORY 

30% 

65% 

40% 

40% 

25% 

0% 

2020 

MARKET 

PENETRATIONROADMAP 

45% 

80% 

55% 

80% 

60% 

45% 

MAX 

REDUCTION 

POTENTIAL 

FROM 2010 

BASELINE 

($0.20/W) 

$0.05 

$0.03 

$0.01 

$0.04 

$0.01 

$0.16 

Table A-3. Residential, Inspection, and Interconnection Market Penetration and Maximum Cost-Reduction 

Potential 

53
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SOLUTION SET 

INTEGRATED 

RACKING 

MODULE 

INTEGRATED 

ELECTRONICS 

PREFAB RICATION 

PLUG AND 

PLAY 

SOLAR-READY 

HOMES 

UNDEFINED 

COSTREDUCTION 

OPPORTUNITY 

(CRO) 

..... • 

mounting 

structure 

AC Modules 

(microinverter 

integrated at 

factory) 

Microinverters 

(small inverters 

on racking 

convert to AC) 

Preassembly 

of panels and 

racking in 

warehouse/ 

factory 

Gen 1 (AC 

module with 

integrated 

racking) 

Gen 2 (fully 

inclusive 

off-the-shelf 

s stem 

Solar-ready 

homes (new 

building design 

integrates 

roofto PV 

Undefined 

(likely includes 

more equipment 

standardization, 

reduced 

through-roof 

penetration, 

experience 

gains) 

2010 

MARKET 

PENETRATION 

1% 

1% 

10% 

1% 

0% 

0% 

1% 

0% 

*Individua l va lu es may not add up to totals owin g to rounding 

2020 

MARKET 

PENETRATIONCURRENT 

TRAJECTORY 

30% 

30% 

35% 

20% 

30% 

0% 

7.5% 

0% 

2020 

MARKET 

PENETRATIONROADMAP 

5% 

10% 

10% 

18% 

45% 

20% 

7.5% 

70% 

MAX 

REDUCTION 

POTENTIAL 

FROM 2010 

BASELINE 

($0.59/W) 

$0.14 

$0.10 

$0.03 

$0.20 

$0.28 

$0.51 

$0.10 

$0.25 

Table A-4. Residential Installation Market Penetration and Maximum Cost-Reduction Potential 

54
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SOLUTION SET 

INTEGRATED 

RACKING 

MODULE INTEGRATED ELECTRONICS 

PREFAB RICATION 

COSTREDUCTION 

OPPORTUNITY 

(CRO) 

Integrated 

racking 

(eliminates 

additional 

mounting 

structure) 

Microinverters 

(small inverters 

on racking 

convert to AC) 

DC optimizers 

(track & 

optimize 

module 

performance 

individually) 

Preassembly 

of panels and 

racking in 

warehouse/ 

factory 

1,000-volt DC 

(enables more 

1,000- VOLT DC modules wired 

together per 

string) 

2010 

MARKET 

PENETRATION 

5% 

10% 

5% 

5% 

1% 

*Individual values may not add up to totals owing to rounding 

2020 

MARKET 

PENETRATIONCURRENT 

TRAJECTORY 

67% 

45% 

55% 

15% 

5% 

2020 

MARKET 

PENETRATIONROADMAP 

90% 

45% 

55% 

15% 

5% 

MAX 

REDUCTION 

POTENTIAL 

FROM 2010 

BASELINE 

($0.42/W) 

$0.22 

$0.13 

$0.08 

$0.30 

$0.05 

Table A-5. Commercial Installation Labor Market Penetration and Maximum Cost-Reduction Potential 

55
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SOLUTION SET 

THIRD-PARTY 

FINANCE 

UTILITY 

FINANCE 

HOMEOWNER 

FINANCE 

COMMUNITY 

SOLAR 

COSTREDUCTION 

OPPORTUNITY 

(CRO) 

Standard Third 

Party 

Third Party with 

Debt/ABSPrime 

Third Party with 

Debt/ABSSubprime 

Corporate OnBalance Sheet 

Third Party with 

YieldCo 

Third Party with 

Institutional 

Equity 

On-Bill 

Financing/ 

Repayment 

Cash Purchase 

Solar Loans 

Mortgage-New 

Build 

Residential 

PACE 

Community 

Solar 

2010 

MARKET 

PENETRATION 

38% 

38% 

0% 

0% 

0% 

0% 

0% 

17% 

5% 

1% 

1% 

1% 

*Individual va lues may not add up to totals owing to rounding 

2020 

MARKET 

PENETRATIONCURRENT 

TRAJECTORY 

0% 

2% 

2% 

35% 

11% 

0% 

6% 

3% 

19% 

15% 

1% 

6% 

2020 

MARKET 

PENETRATIONROADMAP 

4.8% 

9.3% 

2.9% 

3.0% 

5.0% 

3.2% 

1.6% 

0.6% 

4.4% 

9.4% 

MAXWACC 

REDUCTION 

FROM 2012 

BASELINE 

(9.9%), IN 2020 

(%-REAL) 

5.2 

0.6% 

7.0% 

6.9% 

4.9% 

6.7% 

8.3% 

9.3% 

5.5% 

0.5% 

Table A-6. Residential Financing Market Penetration and Maximum Cost-Reduction Potential 

56
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SOLUTION SET 

THIRD-PARTY 

FINANCE 

UTILITY 

FINANCE 

HOST 

FINANCE 

COMMUNITY 

SOLAR 

COSTREDUCTION 

OPPORTUNITY 

(CRO) 

Standard Third 

Party 

Third Party with 

Debt/ABS 

Third Party with 

REIT 

Third Party with 

Crowdsourced 

Funding 

Corporate OnBalance Sheet 

MUSH: Muni 

Bonds +Third 

Party 

Third Party with 

YieldCo 

Full Utility 

Ownership 

Utility Equity 

and Tax Equity 

Cash Purchase 

MUSH: with 

Debt/Bonds 

Green Bonds 

Commercial 

PACE 

Undefined 

CRO(s) 

Community 

Solar 

2010 

MARKET 

PENETRATION 

40% 

0% 

0% 

0% 

0% 

2% 

0% 

7% 

0% 

46% 

1% 

0% 

3% 

0% 

1% 

*Individual va lues may not add up to totals owin g to rounding 

2020 

MARKET 

PENETRATIONCURRENT 

TRAJECTORY 

0% 

3% 

11% 

2% 

16% 

0% 

1% 

14% 

0% 

9% 

2% 

3% 

9% 

26% 

4% 

2020 

MARKET 

PENETRATIONROADMAP 

5.2% 

3.2% 

4.5% 

3.5% 

3.2% 

5.1% 

5.1% 

3.4% 

2.4% 

2.3% 

1.9% 

5.0% 

MAXWACC 

REDUCTION 

FROM 2012 

BASELINE (9.2%) 

IN 2020 (%-REAL) 

4.0% 

6.0% 

4.7% 

5.7% 

6.0% 

4.1% 

4.1% 

5.8% 

6.8% 

6.9% 

7.3% 

4.2% 

Table A-7. Commercial Financing Market Penetration and Maximum Cost-Reduction Potential 

57
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Appendix B. Example Interview and Survey Questions 

We collected data via a combination of interview questions and survey instruments. The process was 

iterative: we modified our instruments and re-surveyed participants as we learned what methods elicited 

the desired amount of detail. For example, for some iterations we pre-populated surveys with estimates 

and asked the participants to judge whether the estimates were high or low. Presented here are 

simplified/consolidated examples of the instruments we used in our data collection. 

Table B-1. Example Interview Questions 

Customer Acquisition 

What are the most costly elements of the customer acquisition process? 

(fill in the blank) Due to market maturity alone, customer acquisition costs are estimated to come down by X% by 2020. 

What is the cost reduction potential of remote system design and site assessment in the near term and long term? (2015 vs. 

2020) Where is the potential for further automation and streamlining in the customer acquisition process? 

How much can customer acquisition costs be reduced by with the implementation of an installer data base with online 

quote system? (i.e. A Tire RAC interface for solar) 

Is there cost reduction potential associated with providing educational materials for potential PV customers? Which market 

sectors would reap greatest cost reductions (residential, commercial, utility)? How much could customer acquisition costs 

be reduced by with increased awareness via education? (including the cost of marketing/advertising ) 

What other CA cost reduction activities we should investigate? 

Permitting, Inspection, and Interconnection 

What are the most costly and time consuming permitting, inspection, and interconnection tasks undertaken when 

completing a PV installation? What are the estimated costs per watt? 

Regarding permit preparation, how much time/money could be saved from an online permitting database/clearinghouse of 

information? 

How much extra cost do you incur due to variation in PII requirements across jurisdictions? AS AHJs and municipal 

permitting offices begin to harmonize and standardize requirements across jurisdictions, how much do you anticipate 

permitting costs to be reduced by in the near to long term? 

What are the most significant cost adders throughout the inspection process? How can these costs be reduced in the near 

term and long term? By how much? 

What are the system size thresholds for interconnection studies and what are the general cost points where these studies 

become cost prohibitive? What size system is typically required to offset the additional costs of interconnection studies? 

What are the unique permitting, inspection, and interconnection challenges for commercial scale systems? How can the 

estimated costs of these by reduced and by how much in the near term and long term? 

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What other PII cost reduction activities we should investigate? 

Installation Labor 

In terms of percentage, by how much are installation labor requirements likely to be reduced with hardware innovations 

(i.e. AC modules, grid racking, integrated rail module systems) the near term and long term? (2015 vs. 2020) 

In addition to improved training and pre-fabrication, what other market developments/interventions have potential to 

reduce installation labor costs in the near and long term? By how much? 

What other installation cost reduction activities we should investigate? 

Are there special installation techniques specific to larger systems that can help reduce installation time and cost? By how 

much in the near term and long term? (2015 vs. 2020) 

59
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$ 0.37 

$ 0.04 

$

 

Example Survey Instrument (Residential PII) 

Table B-2. Example Survey Instrument (Residential PII) 

NREL PV Cost Benchmarking and Road Mapping Overview and Industry Input 

OBJECTIVE 

While technological improvements are necessary to achieve U.S. DOE SunShot cost reduction targets, 

decreasing regulatory and process costs are equally important for the integration of solar into the national 

energy portfolio. This analysis quantifies the impact of regulatory and process hurdles on solar deployment 

and identifies potential pathways forward for achieving non-hardware BOS cost (“soft cost”) reductions. 

PROJECT OVERVIEW 

PHASE I: NREL recently collected data to benchmark soft costs for residential and commercial PV systems, 

installed in 2010, in support of the U.S. DOE SunShot Initiative. Phase I of this project collected installer 

level data in the following DOE priority cost categories, to provide further granularity to laboratory led PV 

system price modeling and analysis activities. 

 Customer acquisition
 

 Permitting, inspection, interconnection
 

 Third-party Financing
 

 Installation
 

As a result of this surveying, we established the following benchmarks for a) Residential systems and b) 

Commercial Systems (<250kW) 

Category Residential Interim Residential 

Benchmark- SunShot target2010 2020 

0.12 

Roadmap: 

How do we 

get from 

Benchmark 

to SunShot 

target? 

Other Costs $ 1.86 

Permitting, Inspection, Interconnection (includes fee of $ 0.20 

$.09, $.11/W for labor) 

Installation Labor $ 0.59 

Customer Acquisition $ 0.67 $ 0.13 

Total $ 3.32 $ 0.65
 

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PHASE II Meeting SunShot targets requires substantial cost reductions in each category (see above) Phase 

II develops a roadmap for plausible cost reduction pathways given a certain series of cost reduction 

interventions. The goal is to estimate the amount, measured in dollars per watt ($/W), that can be saved by 

specific actions (i.e. $/W saved by switching to an online permitting database). This is where we need 

industry input. 

The following page provides an initial proposed roadmap framework with cost reduction measures (cost 

levers) that have been cited to have significant cost reduction potential. The focus of this data collection is 

to approximate and quantify the $/W amount that these cost levers can reduce costs by, by 2020 (given a 

PV system that adopts the solution). To do so, for each cost lever we approximate the current (2012) and 

anticipated-future market penetration levels by 2020. Market penetration is measured as a % of new PV 

capacity installed that year (annual installed capacity). Using these inputs, we then approximate the 

additional market penetration required, of each cost lever, in 2020 to meet SunShot targets. Given your 

experience and knowledge of the market, for the cost levers identified, what is the estimated maximum cost 

reduction potential ($/W), current market penetration (%), and anticipated-future market penetration 

(%)? 

Residential Permitting, Inspection, and Interconnection (5 kW) $/w Cost Reduction from baseline by 2020 % Current est. market penetration 

% Anticipatedmarket penetrationby 2020

Comments 

Standardization of permitting requirements based on best practices( 

independent of interconnection requirements) 

Database of requirements (across jurisdictions) 

Data base assumed to ONLY disclose requirements, no online permitting submittal 

capabilities are included 

Online Permitting Submittal 

Fee reduction from $430 to $250 (assumed) 

Comprehensive permitting reform (Database+ standardization + online submittal) 

Best Practices, Interconnection (i.e. IREC Model Standards) 

Standard inspection check list with improved inspector training/education 

61
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Appendix C: Solution Set and Cost-Reduction Opportunity 

Descriptions 

Customer Acquisition 

The following are expanded definitions of the residential and commercial customer acquisition solution 

sets and CROs discussed and roadmapped in Section 3. 

Software Solutions: Upfront or “sunken” customer acquisition costs can be addressed through software 

solutions that aim to streamline sales and system design aspects of customer acquisition. Software 

solutions that automate portions of the sales and system design process can reduce overall customer 

acquisition costs as long as the cost to deploy the technology does not outweigh the benefit of lower perunit customer acquisition costs over a period of time. 

 Remote Site Assessment Tied to Bid Prep Software: This refers to conducting the 

initial site assessment and providing a proposal/bid without ever physically visiting the customer 

site where the PV is to be located. Reduces time spent labor intensive, in-person site visits to 

ascertain system design specifications needed for bid generation, such as installation size, 

location, and energy production potential. At present, the purchase of software for remote site 

assessment and system design may be cost prohibitive for lower volume installers, but this is 

subject to change as such innovations achieve greater market penetration and come down in cost. 

 Next Generation Site assessment plus on-location bid prep on initial site visit: these 

tools enable streamlined sales and system design processes. For example, a tool may enable sales 

people to complete the site assessment and provide a proposal on-location site during the initial 

site assessment or allow the sales person to send data back to the system designer in the office in 

real time. 

Design Templates: It is common for PV installers to employ standardized bid preparation templates and 

auto-fill forms to reduce duplicative work when preparing bids. This type of standardization is not 

included in the roadmap study because it is considered a standard practice that firms will engage in as a 

matter of striving for efficient business processes. The standardizing of system designs is included 

because it is recognized as a promising area for reducing system design costs. 

 Standardized System Designs: Standard PV system designs that do not need to be 

custom-designed for each prospective customer can reduce system design engineering labor 

hours. PV system designs can be standardized around common housing or building stock and 

adapted to specific building and site parameters if needed. This reduces duplicative design work 

for similar sites. Standard designs also helps reduce associated hardware/equipment costs by 

allowing for a standard bill of materials for hardware greater economies of scale on hardware 

purchases. Standard system designs are more prevalent in the commercial sector than in the 

residential sector because the common flat commercial rooftop makes a better palate for standard 

designs than the diverse roofing configurations and surfaces seen in the residential market. 

Consumer Targeting Strategies: Effective targeting strategies generate higher-quality leads that can 

increase sales-closing ratios or bid-success rates. This increases the overall volume sold and provides a 

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larger customer base to spread costs across. Increasing the volume of PV sold will reduce an installer’s 

customer acquisition cost per watt as long as the annual customer acquisition expenditures do not 

increase to levels that negate the added benefit of increased volume (in terms of customer acquisition 

cost per watt). 

 Marketing Programs and Partnerships: Many PV installation firms seek partnerships 

with established market entities that have ready access to potential solar customers, such as 

utilities, energy marketers, and big-box retailers. The known brand adds a trusted layer of 

confidence for consumers. The distribution outlet may raise awareness across a broader market 

than might otherwise consider a PV system installation. 

 Lead Qualification and Generation Programs: This refers to pay-per-lead services or 

group purchase programs through a city, employer, or neighborhood organization (i.e. Solarize 

Portland Program; Marin Group Buy Program), whereby installers receive leads through an 

outside organization. Close ratios associated with lead qualification and generation programs are 

the primary metric of their value to installers. For example, an expensive lead that closes is more 

valuable than free leads that do not close because employee time, which contributes to customer 

acquisition costs, is expended to try and close the lead. Companies participating in programs that 

offer groups of customers or qualified leads (e.g., group purchase programs and big-box retailer 

partnerships) may incur lower customer acquisition costs per unit sold if the cost of winning the 

group bid or participating in the program is offset by a commensurate increase in the volume of 

PV sold. Programs that group together potential PV customers by geographic region and offer a 

vetted discount option for purchasing PV systems have been termed “solarize” programs in many 

areas. These programs are typically run by an organization, usually a municipality or non-profit. 

The organization issues a request for bid and selects a vendor to install multiple PV systems at a 

discounted price. 

 Referral Programs: This refers to formal and informal referral programs (whether a 

company actively solicits and pays for referrals or gets referral business by word of mouth 

without payment). 

 Consumer Awareness Campaigns: Advertisements and outreach focused on increasing 

consumer awareness about the benefits of solar. 

New Markets: Opening up new market segments via innovative finance leads to lower customer 

acquisition costs for these new market segments. Decreased customer acquisition costs against the 

market average ($0.19/W in 2010), however, will only occur with the undefined CRO. 

 This undefined CRO involves new and advanced customer acquisition practices that 

couple well with innovative financing solutions that open up challenged commercial market 

segments. These challenged segments include lower building owner credit classes43 and/or real 

estate properties in which solar misaligns with their investor’s interests (e.g., split incentives on 

energy savings with utility bill-paying tenants and misaligned investment time horizon). 

43 Most small commercial PV financing is made available to high credit quality corporations and MUSH entities (less than 

10% of available commercial rooftop space). In addition, many real estate companies intend to sell building assets within five 

to seven years, which does not align with much longer duration (10 to 25 year) solar PV leases and PPA contracts. Other 

commercial building assets are held real estate entities, such as REITs, that are challenged to monetize tax benefits (see 

“Third Party with REIT” in Appendix C for further discussion). In addition many real estate investment entities don’t pursue 

solar because they consider it an atypical asset or income stream for other business related reasons. 

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Permitting, Inspection, and Interconnection 

The following are expanded definitions of the residential PII solution sets and CROs discussed and 

roadmapped in Section 4. 

Standardization of Requirements 

 Standardization of Permitting Requirements: Implementing uniform permitting and 

inspection requirements and fees across jurisdictions (independent of interconnection 

requirements). 

Transparency of Requirements 

 Database of Requirements: Currently Clean Power Finance is working to create an 

online database that discloses all the PII requirements by jurisdiction. 

Online Permitting 

 Online Permit Application Submittal: Submitting an application online, directly to the 

AHJ or through a centralized database/system. 

Lower Permitting Fees 

 Lower, Standardized Fees not Based on System Size: A typical fee identified by 

SunRun of $430 is used as a baseline for permitting fees for this analysis. A lower fee of $250 is 

considered for the purposes of roadmapping fee reductions through 2020. 

Interconnection Best Practices 

Interconnection Best Practices: The Interstate Renewable Energy Council and DOE have identified 

several measures to streamline the interconnection processes. This CRO includes the following: 

 Setting minimum response and review times for interconnection applications 

 Avoiding overly burdensome administrative requirements, such as obtaining signatures 

from local code officials unless such requirements are standard practice in a jurisdiction for 

similar electrical work 

 Defining an interconnection approval process for systems generating above 15% peak 

load (for both residential and commercial PV). 

Undefined Solution Set 

 This undefined CRO likely combines unknown regulatory mechanisms that enable 

wider-scale uniformity across AHJs, an average fee of $100 [instead of $250 (i.e., in the lower 

permitting fees solution set)] and streamlined d inspection process ( coordination between the 

utility and the city/county inspectors to combining multiple inspections into a single inspection). 

Installation Labor 

The following are expanded definitions of the residential and commercial installation labor solution sets 

and CROs discussed and roadmapped in Section 5. 

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Integrated Racking 

 Integrated racking eliminates the additional mounting structure, as the module frame 

provides the structural support for the system. In addition to substantial reduction in mechanical 

labor by reducing the part count, integrated racking provides savings in manufacturing, project 

design, shipping, and installation. In some cases there can be an additional upfront cost. 

Examples include the Zep Groove system and the Andalay Groove mounting system. 

Module Integrated Electronics 

 AC Modules: (residential; not identified as a commercial solution): An AC module 

contains an integrated micro-inverter; DC from the module is wired directly to the micro-inverter 

at the factory. AC modules may add upfront cost to the system and/or have system LCOE 

implications. 

 Microinverters: Microinverters are small inverters mounted on the racking, directly 

belowthe panel, converting DC to AC at the module-level. This is an alternative to central, or 

string inverters. Microinverters reduce labor associated with cable runs. Microinverters may add 

upfront cost to the system and/or have system LCOE implications. 

Prefabrication 

 Prefabrication involves pre-assembling panels and racking in a warehouse, which is 

then directly craned onto roof and locked into a mounting structure. 

Plug and Play (Residential) 

 Generation 1 Plug and Play: This CRO utilizes an AC module with integrated racking, 

enabling panels to directly connect without additional mounting hardware. An example of a 

system that employs integrated racking, wiring, grounding, and inverter is the Westinghouse 

Solar Instant Connect. 

 Generation 2 Plug and Play: This refers to a commercial, off-the-shelf system that is 

fully inclusive with little need for individual customization. Any homeowner/consumer can buy 

and install (or have a contractor install) the system without the need for special training or 

specialized tools. This type of system reduces labor to a maximum of 10 unspecialized man 

hours and requires no electrician labor. 

Solar-Ready Homes (Residential) 

 A solar-ready home is a residential new-build that is designed to easily integrate roofmounted PV. Considerations and building features can include, but are not limited to, designing 

roofs for solar loads, grouping roof equipment and vents on the north side of the roof, 

minimizing shading, pre-drilled mounting holes, pre-engineered roof trusses, and built-in wiring 

from roof to panels during construction. 

Undefined Solution Set (Residential) 

 An undefined CRO likely includes more equipment standardization, reduced throughroof penetrations, and installation labor-efficiency gains due to experience. For example, 

industry representatives have suggested that standardizing module dimension (akin to 

standardized lumber dimensions) would reduce installation labor by reducing on-the-job design 

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costs and hardware selection, generally streamlining installs. Additional plausible 

standardization contingent upon standardized module dimensions include standardizing the 

junction box placement, cable harness, and mounting scheme. Reduced through-roof penetration 

could be achieved by an increase in standing seam metal roofs,- particularly on new build homes. 

Adjustment to current regulations could also allow systems to be secured to clay tile roofs via 

roof clamps—a practice currently employed in Germany. Last, learning-by-doing will certainly 

increase process efficiency and reduce costs. For example, less intermittent flows would better 

enable installers to optimize processes and efficiently use resources. 

Power Electronics (Commercial) 

 DC Optimizer: This CRO refers to equipment that connects to each PV module that 

replaces the traditional solar junction box. Typically optimizers track the maximum power point 

of each module individually, monitor performance, and communicate performance data. This 

architecture allows the connection of a large number of panels on a single cable run, reducing 

up-front solar array costs and providing more design flexibility. Examples include Parallel Solar 

from eiQ and SolarEdge and Tigo. DC optimizers have system LCOE implications. 

 1,000-Volt DC (VDC) Modules: This CRO is included on account that PV systems that 

utilize 1,000-VDC modules, compared to traditional 600-VDC modules, realize a 40% BOS 

wiring savings (SMA Solar Technology), which reduces overall installation labor requirements 

and costs. While 1,000-VDC modules have been a standard best practice for commercial and 

utility-scale PV installations in Europe, barriers to adoption in the United States have included 

lack of UL-listed products, standard designs set at 600 VDC, and lack of inspector awareness 

that provisions exist in the current code to support 1,000-VDC modules for commercial 

installations. Recently, there has been a shift in the United States toward utilization of 1,000-

VDC modules as many of these barriers are removed. 

Financing 

The following are expanded definitions of the residential and commercial financing CROs discussed and 

roadmapped in Section 6. 

Residential 

Third-Party Finance 

 Standard Third Party: Developer equity is in partnership with tax equity, though both 

come from a single financing source. Venture capital and private equity (VC/PE are assumed to 

provide developer/sponsor equity for the majority of residential solar deals in 2013, transitioning 

to greater public capital (public market shareholder-provided equity) over time. Public equity 

provides the majority of developer equity by 2015 in both current trajectory and roadmap cases. 

 Third Party With Debt/ABS—Prime: Involves developer equity, tax equity, and debt 

in a portfolio fund for high-FICO (>680) customers. The debt is provided either via lender debt, 

bonds, or ABS. Debt can be provided at a developer equity holding company level above the 

portfolio fund (back-leveraging) or within the portfolio fund (project-level). It is assumed that 

the average loan-to-value against developer equity begins around 1.5 in 2013 and transitions to a 

lower LTV ratio (1.3 in current trajectory and 1.2 in roadmap case) or equivalent (e.g., via over66
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collateralization) in later years. In addition, due to higher liquidity needs, it is assumed that the 

vast majority of debt is securitized in later years. 

 Third Party With Debt/ABS—Wubprime: The same as prime definition but with a 

targeted customer market similar to the lending credit class of subprime mortgages. Debt rates 

are higher due to higher risk. 

 Corporate On-Balance Sheet: Describes public companies developing and financing a 

large volume of projects without external tax equity. In the lower ITC years of 2017–2020, large 

public corporations (likely Fortune 500, possibly Fortune 100) should be able to fund high 

volumes of PV projects without maxing out their tax appetites. Currently, more pure-play solar 

developers and/or lease/PPA providers would likely be merger and/or acquisition (M&A) targets 

of these large corporations. It may be possible for a solar developer today to grow more 

organically to this size, particularly if it offers more diversified services and products. Public 

corporations conducting M&A would likely involve a mixture of engineering service, telecom, 

and energy (e.g., oil and gas) companies and IPP utilities. The existence of a robust secondary 

ABS market for solar may be critical to enable market participation by large corporations, 

ensuring that they need not hold the assets for long periods. 

 Third Party With YieldCo: YieldCos are companies providing long-term steady yields 

based on regular cash flows, as debt payments or equity dividends or both, from solar projects. 

YieldCos are attractive to retail and institutional investors pursuing “income” investments. 

YieldCos could exist as more traditional company types, such as “C” corporations, or as taxadvantaged (i.e., none/limited taxation) entities, such as REITs,44 MLPs, business development 

companies/registered investment companies (BDCs/RICs), or Canadian investment trusts. The 

yieldCo term can be used solely to describe “C” corporations, but the broader yield-oriented 

company meaning is used in this report. For residential PV, only MLPs garnered significant 

interviewee interest. Federal legislation, however, is required to enable solar projects to qualify 

as viable assets for MLP ownership. Following the interview period, on June 7, 2013, NRG 

announced intentions45 for a $400 million IPO of a subsidiary “C” corporation yieldCo that 

would include solar (albeit not residential) project cash flows. Proceeds from the IPO would help 

raise capital for a utility-scale solar project. 

 Third Party with Institutional Equity: This is the same as standard third party but with 

the developer able to source developer equity from long-term-focused, lower cost-of-capital 

investors, such as pension funds and endowments. This CRO is focused on direct investment by 

institutional equity sources without ABS, and as such, this is more of an early-year activity 

before ABS becomes robust for solar. 

Utility Finance 

 Utility on-bill financing are loans repaid via additional charges on the utility bill, 

resulting in overall lower bills where breakeven-or-better PV economics exist. The capital comes 

from the utility’s balance sheet or bank loans routed through utilities with the utility as the debt 

servicer. Default recourse in on-bill finance is for the utility to cut off power and, in some cases, 

act on property liens. In some cases the financing remains with the meter after property sale. In 

44 See “third-party with REIT” under commercial market in appendix C for more detail. 

45 http://www.bloomberg.com/news/2013-06-07/nrg-plans-400-million-ipo-for-unit-to-own-operate-power-assets.html 

(accessed June 17, 2013). 

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this paper, on-bill “financing” and “repayment” are differentiated, as “repayment” allows for 

third-party financing routed through a utility’s bill. On-bill repayment had no material residential 

solar financing activity in 2012. 

Homeowner Finance 

 Cash Purchases: While not regularly considered a “financing cost-reduction 

opportunity,” cash purchases are in effect full equity financings by homeowners. 

 Solar Loans: Specialized loan products for solar currently exist. This debt is provided as 

efficiency loan products, home equity loans, home equity lines of credit (HELOCs), mortgages, 

and home improvement loans. Despite what their name might imply, these types of debt 

generally do not include the value of the PV system in the real estate value. Instead, these loans 

are often unsecured (against the credit of the borrower) or against homeowner equity in their 

home (non-inclusive of the PV system’s value). In other words, they are methods of putting cash 

in the hand of the homeowner that is somewhat uncorrelated with the solar PV system’s value. 

Examples of current offerings include the FHA’s PowerSaver Pilot Program, the U.S. 

Department of Housing and Urban Development (HUD) insured Title 1 Home Improvement 

Loan (Admirals Bank is a notable offering bank), the Colorado Energy Star Mortgage, and the 

Fannie Mae Energy Loan. Over time, solar loans are anticipated to transition to be party of 

standard real estate loan products, providing higher liquidity and lower cost of capital than first 

generation solar loans. These real estate loan products would likely include PV system value 

within the appraised real estate value. Such appraisal practices did occur under common real 

estate appraisal conditions in 2012. Home equity loans may become the most likely vehicle for 

finance solar on existing homes though mortgage refinancings may also play a role. The value of 

PV would be determined either on an income basis, as in Sandia National Laboratories’ PV value 

valuation software or a comparable asset sale basis. To not require homeowner capital 

contribution, perhaps developers would put working capital at risk to bring the PV project to 

completion and then be paid back by the loan. Banks routing these loan products through 

developers, providing a “one-stop shop” and cents-per-kilowatt-hour-correlated offerings, would 

likely increase customer uptake. 

 Mortgage—New Build: This CRO primarily entails a mortgage for the purchase of a 

newly built home that includes PV. This CRO assumes a transition from specialty mortgage 

products designed to support solar financing to standard mortgages that include solar in the 

appraised value of the home. This CRO may exceed the market penetration of solar-ready 

homes because it is assumed that there may be mechanisms for the home buyer to add solar as 

part of the mortgage financing. 

 Residential PACE: Residential PACE programs provide loans for PV, paid back through 

property tax collections, which thus remain with the property and senior to most other liens 

including mortgages. Residential PACE has experienced recent challenges in relation to 

mortgage underwriting, putting many programs on “pause.” In 2010, Fannie Mae and Freddie 

Mac refused to underwrite mortgages on homes involved with PACE lending. In 2012 the State 

of California, in support of PACE, won a federal court ruling against the Federal Housing 

Financing Authority (FHFA), Fannie Mae, and Freddie Mac. The court ruled the defendants 

must take in public and stakeholder comments before making such underwriting decisions. 

Greater clarity from FHFA should come in 2013. Despite the uncertainties, residential PACE 

persists in some areas. Nonetheless, interviewees felt that that residential PACE did not hold 

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long-term scalability. However, after our interview period was complete, $100 million in loans 

were offered through the Riverside County, California, HERO program (accessible throughout 

California) and $500 million in loans offered through the Florida PACE Funding Agency. Both 

loan programs cover PV, other renewables, and energy efficiency. 

Community Solar 

 Community solar is generally financed through one of the third-party or utility-financing 

CROs. While community solar financing could be grouped within these other solution sets, it has 

unique investment risks, utility-value propositions and challenges, and policy treatment. 

Subscribers to community solar projects (usually built at a scale comparable to a medium-tolarge commercial project) receive the net-metering benefits of solar as if a solar installation the 

size of their subscription was on their rooftop (hence, “virtual”). 

Commercial 

Third-Party Financing 

 Standard Third Party: VC/PE is assumed to provide developer equity. Developer 

equity is paired with tax equity. 

 Third Party With Debt/ABS: Involves developer equity, tax equity, and debt supporting 

a portfolio fund. This CRO is best suited to high-credit-quality power offtakers. The debt is 

provided either via lender debt, bonds, or ABS. Debt can be provided at a developer equity 

holding company level above the portfolio fund (back-leveraging) or within the portfolio fund 

(project-level). 

 Third Party with REIT: REITs are business entities electing REIT designation under 

Form 1120-REIT. REITs do not pay corporate tax and are able to access retail investors in public 

markets through public offering of shares. REITs must follow tax code minimums for asset 

holdings of and income streams from real property. While it is possible for REITs to participate 

at low levels in asset ownership and income streams if maintaining their real property asset and 

income minimums, substantial REIT involvement in solar is likely not possible without the PV 

holding real property status, a status not yet indicated via an IRS public publication of private 

letter ruling(s). REIT PV development could occur though specialty REITs that focus on owning 

PV or more traditional REITs that would develop PV on buildings they own or acquire. Both of 

these actions would fit under the “host finance” solution set. Interviewees were unsure of how 

either of these equity activities could marry well with tax benefit capture (i.e., with tax equity), 

and therefore believed REITs providing debt to commercial PV projects (back-leveraged or 

within project structure) would be the most likely route for early REIT activity. Hence, REITs 

are placed within this “third-party finance” solution set. There are also REIT work-around 

options (REITs leasing rooftop space to a third-party owner of a PV system), which was 

occurring in 2012, but that is considered “standard third-party” financing for this paper as the 

REIT is not involved in the financing. 

 Third Party with Crowdsourced Funding: Crowdsourced funding is accessing retail 

investors through lower regulation pathways than traditional securities purchases. The 2012 

Jumpstart our Business Startups (JOBS Act authorized expanded crowdsourced funding 

constructs, although the Securities and Exchange Commission has not yet promulgated JOBS 

Act regulations. Nevertheless, providing debt through crowdsourced funding was viable prior to 

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the JOBS Act, and interviewees believed that debt, rather than equity, will be the most natural fit 

for crowdsourced funding for PV going forward. Early crowdsourced debt has occurred directly 

to hosts (so under the “host finance” solution set), but to reach substantial scale, interviewees 

believed crowdsourced funding’s primary role would be as a debt provider to commercial 

projects alongside developer equity and tax equity. Direct lending to hosts may serve a smaller 

but regular role in financing projects in those regulated utility territories that do not allow thirdparty financing. 

 Corporate On-Balance Sheet: This CRO entails public developers financing deals 

without external tax equity, entirely on their balance sheet. Large corporations should be able to 

fully fund significant volumes of small commercial PV projects without maxing out their tax 

appetite in the 10% ITC later years (2017–2020). Currently, more pure-play solar developers 

(including lessors) would be likely M&A targets of these large corporations or public (e.g., 

SunPower and SunEdison) or later-to-become public developers could possibly organically grow 

to this size, although further diversification likely would be necessary. 

 MUSH—Municipal Bonds + Third Party: For MUSH properties, it is possible to 

combine governmental-bonded debt with tax-equity-backed third-party funds. This enables 

lower-cost projects at lower WACC than either bonding or third-party financing alone. Taxable 

bonds can be loaned into developer portfolio funds. This has been called the “Morris Model,” as 

this financing practice began in Morris County, New Jersey. A similar outcome can be achieved 

by pre-paying third-party PPAs with bond proceeds. 

 Third Party With YieldCo: YieldCos are companies providing long-term steady yields 

based on regular cash flows, as debt payments or equity dividends or both, from solar projects. 

YieldCos are attractive to retail and institutional investors pursuing “income” investments. 

YieldCos could exist as more traditional company types, such as “C” corporations, or as MLPs, 

BDCs/RICs, Canadian investment trusts, or other novel approaches. Some use the yieldCo term 

to describe only “C” corporations, but the broader yield-oriented company meaning is used here. 

These entities usually benefit from limited taxation at the company level, and some, such as 

MLPs, also pass through passive tax benefits, which are desirable to a limited investor class. For 

residential PV, only MLPs garnered significant interviewee interest. Federal legislation, 

however, is required to enable solar projects to qualify as viable assets for MLP ownership. 

Following the interview period, on June 7, 2013, NRG announced intentions46 for a $400 million 

IPO of a subsidiary “C” corporation yieldCo that would include solar project cash flows. 

Proceeds from the IPO would help raise capital for a utility-scale solar project. REITs may also 

be included as a kind of yieldCo but are broken out as a separate CRO for commercial PV 

financing because of high REIT-specific interests of interviewees. 

Utility Financing 

 Full Utility Ownership: Utilities can fully fund projects in their service territories and 

include them in the rate base. These full financings have generally occurred under the auspices 

of, or were made financially viable by, renewable portfolio standards (RPSs). New business 

46 http://www.bloomberg.com/news/2013-06-07/nrg-plans-400-million-ipo-for-unit-to-own-operate-power-assets.html 

(accessed June 17, 2013) 

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models for distributed-generation ownership by the utility may provide value when RPS 

programs are no longer available or as supportive. 

 Utility Equity and External Tax Equity: This CRO may not be possible without PUC 

regulatory changes in many states. This has been done for larger projects (large commercial and 

utility-scale) by IPP utilities. If allowed in regulated territories, this CRO would allow much 

quicker monetization of the ITC (otherwise it must be spread over the rate-based period (i.e., 

monetized over about 25 years by the regulated utility instead of in first year by a tax-equity 

investor). 

Host Finance 

 Cash Purchase: The building owner buys the system outright (i.e., 100% equity asset 

purchase). 

 MUSH With Debt/Bonds: Municipalities can offer debt to PV projects on their local 

MUSH buildings via municipal bond offerings. ESCO activities on MUSH properties supported 

by private bank loans are included in this category for simplicity. 

 Green Bonds: In 2012 there already existed a growing market for “green bonds,” but this 

market primarily consists of privately issued bonds for utility-scale project and renewable energy 

corporation-issued bonds as well as specialty federal government-enabled bonds, such as Clean 

Renewable Energy Bonds. Our CRO involves only state and local governmental backing and is 

specific to distributed solar energy, substantial differentiators from the vast majority of the 

current “green bond” market. State and local governments can offer bonds to fund small 

commercial PV systems within their jurisdictions. These offerings would offered to cover private 

and public businesses—not just (and possibly excluding) MUSH properties. This bonding 

construct has already been attempted for energy efficiency in private (non-MUSH) buildings in a 

few states. Green bonds for PV would likely be at rates lower than private lending rates because 

they would have recourse to public funds. For instance, these bonds could be issued as municipal 

general obligation bonds, which have recourse to the municipalities’ other revenues and cash. 

Another option is an obligation charge bond (used in the past to fund environmentally beneficial 

power plant capital expenses like scrubbers), which would be funded through universal utility 

billing surcharges. State green bank loan guarantees for private loan issuances would also be 

covered under this CRO (albeit not necessarily “bonds”). 

 Commercial PACE: Commercial PACE programs provide loans for PV. The loans are 

paid back through property tax collections, thus they remain with the property and have 

enhanced credit owing to their senior position to most other liens including mortgages. This 

CRO is viable for commercial properties, where credit is often not strong and where owners 

possess shorter (about 5–7 years) investment horizons than third-party contract terms. 

	 Undefined CRO(s): As discussed in this report, other CROs presented were collectively 

insufficient to achieve the roadmap target. A single new, undefined CRO—or perhaps a 

collection of new CROs— likely will be necessary to meet the roadmap target. 

Community Solar 

	 Community solar is generally financed through one of the third-party or utility-financing 

CROs. While community solar financing could be grouped within these other solution sets, it 

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has unique investment risks, utility-value propositions and challenges, and policy treatment. 

Subscribers to community solar projects (usually built at a scale comparable to a medium-tolarge commercial project) receive the net-metering benefits of solar as if a solar installation 

the size of their subscription was on their rooftop (hence, “virtual”). 

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