1

U.S. Solar Photovoltaic System 

Cost Benchmark: Q1 2018

October 2018

NREL/PR-6A20-72133

Ran Fu, David Feldman, and Robert Margolis
2

Contents

• Introduction and Key Definitions

• Overall Model Outputs

• Market Study and Model Inputs

• Model Output: Residential PV

• Model Output: Commercial PV

• Model Output: Utility-Scale PV

• Model Applications

• Conclusions
3

NREL has been modeling U.S. photovoltaic (PV) system costs since 2009. This 

year, our report benchmarks costs of U.S. solar PV for residential, commercial, 

and utility-scale systems built in the first quarter of 2018 (Q1 2018). 

We use a bottom-up methodology, accounting for all system and projectdevelopment costs incurred during the installation to model the costs for 

residential, commercial, and utility-scale systems. In general, we attempt to 

model the typical installation techniques and business operations from an 

installed-cost perspective. Costs are represented from the perspective of the 

developer/installer, thus all hardware costs represent the price at which components 

are purchased by the developer/installer, not accounting for preexisting supply 

agreements or other contracts. Importantly, the benchmark also represents the sales 

price paid to the installer; therefore, it includes profit in the cost of the hardware, along 

with the profit the installer/developer receives, as a separate cost category. However, it 

does not include any additional net profit, such as a developer fee or price gross-up, 

which are common in the marketplace. We adopt this approach owing to the wide 

variation in developer profits in all three sectors, where project pricing is highly 

dependent on region and project specifics such as local retail electricity rate structures, 

local rebate and incentive structures, competitive environment, and overall project or 

deal structures. Finally, our benchmarks are national averages weighted by state 

installed capacities. 

Introduction
4

This report builds on a number of previous publications from NREL and Lawrence 

Berkeley National Laboratory (LBNL):

• Fu, Ran, David Feldman, Robert Margolis, Mike Woodhouse, and Kristen Ardani. 2017. U.S. Solar Photovoltaic 

System Cost Benchmark: Q1 2017. Golden, CO: National Renewable Energy Laboratory. NREL/TP-6A20- 68925. 

• Fu, Ran, Donald Chung, Travis Lowder, David Feldman, Kristen Ardani, and Robert Margolis. 2016. U.S. Solar 

Photovoltaic System Cost Benchmark: Q1 2016. Golden, CO: National Renewable Energy Laboratory. NREL/TP6A20-66532.

• Barbose, Galen, and Naïm Darghouth. 2016. Tracking the Sun IX: The Installed Price of Residential and NonResidential Photovoltaic Systems in the United States. Berkeley, CA: Lawrence Berkeley National Laboratory.

• Bolinger, Mark, and Joachim Seel. 2016. Utility-Scale Solar 2015: An Empirical Analysis of Project Cost, 

Performance, and Pricing Trends in the United States. Berkeley, CA: Lawrence Berkeley National Laboratory.

• Chung, Donald, Carolyn Davidson, Ran Fu, Kristen Ardani, and Robert Margolis. 2015. U.S. Photovoltaic Prices 

and Cost Breakdowns: Q1 2015 Benchmarks for Residential, Commercial, and Utility-Scale Systems. Golden, CO: 

National Renewable Energy Laboratory. NREL/TP-6A20-64746. 

• Fu, Ran, Ted James, Donald Chung, Douglas Gagne, Anthony Lopez, and Aron Dobos. 2015. Economic

Competitiveness of U.S. Utility-scale Photovoltaics Systems in 2015: Regional Cost Modeling of Installed Cost 

($/W) and LCOE ($/kWh). IEEE 42nd Photovoltaic Specialist Conference, New Orleans, LA.

• Feldman, David, Galen Barbose, Robert Margolis, Mark Bolinger, Donald Chung, Ran Fu, Joachim Seel, Carolyn 

Davidson, Naïm Darghouth, and Ryan Wiser. 2015. Photovoltaic System Pricing Trends, Historical, Recent, and 

Near-Term Projections. Golden, CO: National Renewable Energy Laboratory. NREL/PR-6A20-64898. 

Introduction
5

Key Definitions

Sector Category Description Size Range

Residential PV Residential rooftop systems 3 kW – 10 kW

Commercial PV Commercial rooftop systems, ballasted racking 10 kW – 2 MW

Utility-Scale PV Ground-mounted systems, fixed-tilt and one-axis tracker > 2 MW 

Unit Description

Value 2018 U.S. dollar (USD) 

System Size In direct current (DC) terms; inverter prices are converted by DC-to-alternating 

current (AC) ratios.
6

Contents

• Introduction and Key Definitions

• Overall Model Outputs

• Market Study and Model Inputs

• Model Output: Residential PV

• Model Output: Commercial PV

• Model Output: Utility-Scale PV

• Model Applications

• Conclusions
7

Overall Model Results (Total Installed Cost) 

1. Values are inflation adjusted using the Consumer Price Index (2018). Thus, historical values from our models are adjusted and

presented as real USD instead of nominal USD.

2. Cost categories are aggregated for comparison purposes. “Soft Costs – Others” represents permitting, inspection, and 

interconnection (PII); land acquisition; sales tax; and engineering, procurement, and construction (EPC)/developer overhead and 

net profit. 
8

Overall Model Results (Q1 2017 vs. Q1 2018) 

Sector Residential PV Commercial PV Utility-Scale PV, Fixed-Tilt

Q1 2017 Benchmarks

in 2017 USD/W DC $2.80 $1.85 $1.11

Q1 2017 Benchmarks

in 2018 USD/W DC $2.84 $1.88 $1.12

Q1 2018 Benchmarks

in 2018 USD/W DC $2.70 $1.83 $1.13

Drivers of 

Cost Decrease

• Higher module efficiency

• Lower structural BOS commodity price

• Lower electrical BOS commodity price

• Higher labor productivity

• Lower supply chain costs

• Decrease in higher-cost module inventory 

• Higher small installer market share

• Lower permitting cost 

• Lower inverter price 

• Higher module efficiency

• Smaller developer team

• Lower permitting and 

interconnection costs

• Lower inverter price 

• Higher module efficiency

• Optimized design 

coefficients for wind loads

• 1,500 Vdc to replace 

1,000 Vdc

• Lower developer 

overhead 

Drivers of 

Cost Increase

• Higher mixed inverter price due to higher 

advanced inverter adoption 

• Higher module price

• Higher labor wages 

• Higher module price

• Higher labor wages 

• Higher module price

• Higher labor wages

• Higher steel prices
9

Overall Model Results (Soft Cost) 

1. “Soft Cost” in this report is defined as non-hardware cost—i.e., “Soft Cost” = Total Cost - Hardware Cost (module, inverter, 

and structural and electrical BOS). 

2. In 2018, the decreased soft costs (%) of all three sectors are caused by the increased module prices. 

3. Residential and commercial sectors have larger soft cost percentage than the utility-scale sector.

4. Soft costs and hardware costs also interact with each other. For instance, module efficiency improvements have reduced 

the number of modules required to construct a system of a given size, thus reducing hardware costs, and this trend has 

also reduced soft costs from direct labor and related installation overhead.

5. An increasing soft cost proportion in this figure indicates that soft costs declined more slowly than hardware costs; it does

not indicate that soft costs increased on an absolute basis.
10

Overall Model Results (LCOE) 

The reductions in total capital cost, along with improvements in operation, system design, and technology have resulted in significant 

reductions in the cost of electricity. U.S. residential and commercial PV systems are 89% and 91% towards achieving SETO’s 2020 

electricity price targets, and U.S. utility-scale PV systems have achieved their 2020 SETO target three years early. 

Note that we use the fixed-tilt systems for LCOE benchmarks from 2010-2015 and then switch to one-axis tracking systems from 

2016 to 2018 to reflect the market share change in the utility-scale PV sector. All detailed LCOE values can be found in Appendix.
11

Contents

• Introduction and Key Definitions

• Overall Model Outputs

• Market Study and Model Inputs

• Model Output: Residential PV

• Model Output: Commercial PV

• Model Output: Utility-Scale PV

• Model Applications

• Conclusions
12

Solar photovoltaic (PV) deployment has grown rapidly in the United States over the past several years. As the figure shows, in 

2017 new U.S. PV installations included 2.1 gigawatts (GW) in the residential sector, 1.5 GW in the commercial sector, and 7.1 

GW in the utility-scale sector—totaling 10.7 GW across all sectors (Bloomberg 2018). Meanwhile, although commercial sector 

showed increased annual installation in 2017, compared to 2016, both residential and utility-scale sectors experienced the 

decreased installations in 2017 for the first time since 2004. The decreased installation in residential sector might be caused by 

the Net Metering reforms in some states. The decreased installation in utility-scale sector might be caused by the large volume 

of installations in 2016 when developers expected to fully leverage the 30% federal Investment Tax Credit (ITC).

US Solar PV Market Growth

U.S. PV market growth, 2004–2017, in gigawatts of direct-current (DC) capacity (Bloomberg 2018)
13

We use the California NEM Interconnection Applications Data Set (CSI 2018) to benchmark generic system characteristics, 

such as system size, module power and efficiency, and choice of power electronics. This database is updated monthly and 

contains all interconnection applications in the service territories of the state’s three investor-owned utilities (Pacific Gas & 

Electric, Southern California Edison, and San Diego Gas & Electric). Although there are other databases for other markets, 

such as Massachusetts and New York, we use only the California NEM database because of its higher granularity and greater 

consistency. However, we do not use the California NEM database for regional cost analyses; inputs and sources for regional 

analyses are described in subsequent sections of this report.

Database for Residential and Commercial Sectors
14

This figure displays module power and efficiency data from the California NEM database. Since 2010, module power 

and efficiency in both sectors have been steadily improving. We use the values of 17.2% (residential) and 19.1% 

(commercial and utility-scale) module efficiency in our models. Also note that since module selection may vary in 

different regions, the actual module efficiencies in other regions than CA may be different.

Module Power and Efficiency Trend (California) 
15

This figure displays average system sizes from the California NEM database. We use the 2017 value of 6.2 kW as the 

baseline case in our residential cost model to reflect the adoption of higher module efficiency.

Commercial system sizes have changed more frequently, likely reflecting the wide scope for “commercial customers,” which 

include schools, office buildings, malls, retail stores, and government projects. Thus, we use 200 kW as the baseline case in

our commercial model.

PV System Size Trend (California) 
16

According to the California NEM database, market uptake of MLPE has been growing rapidly since 2010 in California’s residential 

sector. This increasing market growth may be driven by decreasing MLPE costs and by the “rapid shutdown” of PV output from 

buildings required by Article 690.12 of the National Electric Code (NEC) since 2014—MLPE inherently meet rapid-shutdown 

requirements without the need to install additional electrical equipment. 

In 2017, MLPE—represented by the combined share of Enphase and SolarEdge inverter solutions—reached 65% of the total 

California residential market share. Therefore, in our residential system cost model, string inverter, power optimizer, and microinverter 

options are modeled separately and their market shares (35%, 37%, and 28%) are used for the weighted average case. 

Inverter Market — Residential PV Sector (California) 
17

Conversely, MLPE growth (represented by Enphase and SolarEdge) has been slow in California’s commercial sector, 

reaching a share of only 8% in 2017. Thus, we do not build MLPE inverter solutions into our commercial model.

Inverter Market — Commercial PV Sector (California) 
18

We source non-MLPE inverter prices from the PVinsights (2018) database, which contains typical 

prices between Tier 1 suppliers and developers in the market. 

Inverter Price for non-MLPEs
19

For MLPE inverter prices, we use data from public corporate filings, shown in this figure (Enphase 2018; SolarEdge 2018). 

Enphase’s Q1 2018 revenue was $0.39/Wac, which represents the typical microinverter price. SolarEdge’s Q1 2018 revenue was 

$0.26/Wac, including sales from DC power optimizers, string inverters, and monitoring equipment, which are typically included in

one product offering. GTM Research estimates a DC power optimizer cost of $0.06/Wac (GTM Research 2018), implying a string 

inverter and monitoring equipment price of $0.20/Wac. 

Inverter Price for MLPEs
20

We convert the USD/Wac inverter prices from previous inverter price figures to USD per watt DC (Wdc) 

using different DC-to-AC ratios (table below). In our benchmark, we use USD/Wdc for all costs, including 

inverter prices. Note that we updated the central inverter DC-to-AC ratios using Lawrence Berkeley 

National Laboratory data (Bolinger and Seel 2018); for the ratios in residential and commercial sectors, 

we use the estimates based on interview feedback (NREL 2018). 

Inverter Price and DC-to-AC ratios

Inverter Type Sector $ per Watt AC DC-to-AC Ratio $ per Watt DC

Single Phase 

String Inverter

Residential PV

(non-MLPE) 0.14 1.15 0.12

Microinverter Residential PV

(MLPE) 0.39 1.15 0.34

DC Power Optimizer

String Inverter

Residential PV

(MLPE) 0.20 1.15 0.18

Three Phase 

String Inverter

Commercial PV

(non-MLPE) 0.09 1.15 0.08

Central Inverter Utility-scale PV

(fixed-tilt) 0.06 1.36

(Oversized) 0.04

Central Inverter Utility-scale PV

(1-axis tracker) 0.06 1.30(Oversized) 0.05
21

Module Price (US vs. Global) 

We assume an ex-factory gate (spot or first-buyer) price of $0.47/Wdc for Tier 1 crystalline-silicon PV modules in Q1 2018. As 

this figure shows, U.S. spot prices declined substantially between 2014 and 2016, approaching global spot prices. In 2017, 

however, U.S. spot prices rose as many commercial and utility-scale PV developers and residential installers purchased large 

quantities of modules owing to uncertainty about U.S. policy on imported modules (GTM/SEIA 2018). By the time U.S. tariffs on

imported modules came into effect in 2018, U.S. spot prices had reached $0.47/Wdc—$0.17/Wdc above the global spot price—

and appeared to be leveling off.
22

Module Price Inputs: Q1 2018

Although commercial and utility-scale PV developers typically can procure modules at or near the spot price, residential 

integrators and installers incur additional supply chain costs (figure below). Historical inventory price can create a price lag

(approximately six months) for the market module price in the residential sector when the modules from previous procurement 

are installed in today’s systems. In the Q1 2017 residential PV benchmark this supply chain cost represented $0.21/W – a 60% 

premium. Because US module ASP was lower than Q1 2018 pricing for much of 2017 we do not included this supply chain cost 

in the current benchmark. We assume that small installers and national integrators are both subject to a 15% ($0.07/W) premium 

on the spot price for module shipping and handling (NREL 2018), consistent with Q1 2017 residential PV benchmark. Small 

installers are subject to an additional 35% ($16/W) premium owing to small-scale procurement (Bloomberg 2018), increasing 

from an assumed 20% premium in the Q1 2017 residential PV benchmark. Both types of companies are also subject to 6.9% 

sales tax (weighted national average), bringing the small installer module cost to $0.76/W and the national integrator cost to 

$0.58/W (Bloomberg 2018).
23

Our residential PV benchmark is based on two different business structures: “small installer” and “national integrator.” We define 

small installers as businesses that lead generation, sales, and installation, but do not provide financing solutions. The national 

integrator performs all of the small installer’s functions, and provides financing and system monitoring for third-party-owned systems. 

In our models, the difference between small installers and national integrators manifests in the overhead and sales and marketing 

cost categories, where the national integrator is modeled with higher expenses for customer acquisition, financial structuring, and 

asset management. To estimate the split in market share between small installers and national integrators, we use data compiled 

from corporate filings (Sunrun 2018; Vivint Solar 2018) and GTM Research and SEIA (2018). As shown in this figure, small installers 

have gained more market share than national integrators since 2016, because the direct ownership business model, led by installers, 

became more popular than third-party ownership.

Residential PV: Integrator vs. Installer 
24

Contents

• Introduction and Key Definitions

• Overall Model Outputs

• Market Study and Model Inputs

• Model Output: Residential PV

• Model Output: Commercial PV

• Model Output: Utility-Scale PV

• Model Applications

• Conclusions
25

Residential PV: Model Structure

System Design

• Available roof area

• Module efficiency

• System architecture

CORE COST 

DRIVERS

MODEL COST 

CATEGORIES INPUTS OUTPUTS

System Location

Company Structure

System Hardware

• Module

• Inverter

• Structural BOS

• Electrical BOS

Direct Labor

• Electrical

• Mechanical

• General construction

Indirect Labor

• Engineering design

• Construction permit 

administration

Overhead

(General and 

administrative)

Sales and Marketing 

(Customer acquisition) 

Permit, Inspection, 

and Interconnection 

(PII) Costs

System Hardware

• Equipment costs

• and quantities

• Supply chain costs

• Sales tax

Direct/Indirect Labor

• Wage rates by labor 

class and geography

• Person-hours per task 

by labor class

• Wage burden rates

PII Costs

Total Overhead Costs by 

Category

Total Equipment 

Costs

Total Direct and 

Indirect Labor Costs

Total PII Costs

Total Overhead Costs

Total 

Capital 

Cost
26

Residential PV: Modeling Inputs and Assumptions

Category Modeled Value Description Sources

System size 6.2 kW Average installed size per system Go Solar CA (2018) 

Module efficiency 17.2% Average module efficiency Go Solar CA (2018)

Module price $0.47/Wdc Ex-factory gate (first buyer) price, Tier 1 modules GTM and SEIA (2018), NREL (2018)

Inverter price 

Single-phase string inverter: 

$0.12/Wdc

DC power optimizer string inverter: 

$0.18/Wdc Microinverter: $0.39/Wdc

Ex-factory gate (first buyer) prices, Tier 1 inverters PVinsights (2018), NREL (2018), corporate filings 

(Enphase 2018, SolarEdge 2018) 

Structural BOS 

(racking) $0.10/Wdc Includes flashing for roof penetrations and all the rails and clamps NREL (2018)

Electrical BOS

$0.19–$0.27/Wdc

Varies by inverter option

Conductors, switches, combiners and transition boxes, as well as 

conduit, grounding equipment, monitoring system or production 

meters, fuses, and breakers

Model assumptions, NREL (2018), RSMeans (2017)

Supply chain costs 

(% of equipment 

costs)

Varies by installer type

15% costs and fees associated with shipping and handling of 

equipment multiplied by the cost of doing business index (101%)

Additional 35% small-scale procurement for module-related supply 

chain costs for small installers. Additional 20% for inverter-related 

supply chain costs for small installers and 10% for national 

integrators

NREL (2018), model assumptions 

Sales tax Varies by location; weighted national 

average: 6.9%

Sales tax on the equipment; national benchmark applies an 

average (by state) weighted by 2017 installed capacities RSMeans (2018), GTM and SEIA (2018)

Direct installation 

labor 

Electrician: $19.74–$38.96 per hour;

Laborer: $12.88–$25.57 per hour;

Varies by location and inverter option

Modeled labor rate depends on state; national benchmark uses 

weighted average of state rates BLS (2018), NREL (2018)

Burden rates (% of 

direct labor) Total nationwide average: 31.8%

Workers compensation (state-weighted average), federal and state 

unemployment insurance, Federal Insurance Contributions Act 

(FICA), builders risk, public liability

RSMeans (2018)

Permitting, 

inspection, and 

interconnection (PII)

$0.06/Wdc

Includes assumed building permitting fee of $200 and six office staff 

hours for building permit preparation and submission, and 

interconnection application preparation and submission

NREL (2018)

Sales & marketing 

(customer 

acquisition) 

$0.30/Wdc (installer)

$0.44/Wdc (integrator)

Total cost of sales and marketing activities over the last year—

including marketing and advertising, sales calls, site visits, bid 

preparation, and contract negotiation; adjusted based on state “cost 

of doing business” index

NREL (2017), Sunrun (2017), Vivint Solar (2017), 

Feldman et al. (2013)

Overhead (general & 

administrative)

$0.29/Wdc (installer)

$0.37/Wdc (integrator)

General and administrative expenses—including fixed overhead 

expenses covering payroll (excluding permitting payroll), facilities, 

administrative, finance, legal, information technology, and other 

corporate functions as well as office expenses; adjusted based on 

state “cost of doing business” index

NREL (2018), Feldman et al. (2013)

Profit (%) 17%

Fixed percentage margin applied to all direct costs including 

hardware, installation labor, direct sales and marketing, design, 

installation, and permitting fees 

Fu et al. (2017)
27

This figure presents the U.S. national benchmark from our residential model. The national benchmark represents an average 

weighted by Q1 2018 installed capacities. Market shares of 67% for installers and 33% for integrators are used to compute the

national weighted average. String inverter, power optimizer, and microinverter options are each modeled individually, and the

“mixed” case applies their market shares (35%, 37%, and 28%) as weightings. 

Residential PV: Model Outputs

Q1 2018 U.S. benchmark: 6.2-kW residential system cost (2018 USD/Wdc)
28

Residential PV: Model Outputs

This figure presents the benchmark in the top U.S. solar markets (by 2017 installations), reflecting differences in supply 

chain and labor costs, sales tax, and SG&A expenses—that is, the cost of doing business (Case 2012).

Q1 2018 benchmark by location: 6.2-kW residential system cost (2018 USD/Wdc)
29

Residential PV: Model Outputs

Our bottom-up modeling approach yields a different cost structure than those reported by public solar integrators in their corporate 

filings (Sunrun 2018; Vivint Solar 2018). Because integrators sell and lease PV systems, they practice a different method of

reporting costs than do businesses that only sell goods. Many of the costs for leased systems are reported over the life of the 

lease rather than the period in which the system is sold; therefore, it is difficult to determine the actual costs at the time of the sale. 

Although the corporate filings from Sunrun and Vivint Solar report system costs on a quarterly basis, the lack of transparency in the 

public filings makes it difficult to determine the underlying costs as well as the timing of those costs. 

Q1 2018 NREL modeled cost benchmark (2018 USD/Wdc) vs. Q1 2018 company-reported costs
30

Residential PV: Capital Cost Benchmark Historical Trends

From 2010 to 2018 there was a 63% reduction in the residential PV system cost benchmark. Approximately 57% of that reduction 

can be attributed to total hardware costs (module, inverter, and hardware BOS), as module prices dropped 82% over that time 

period. An additional 19% can be attributed to labor, which dropped 77% over that time period, with the final 24% attributed to other 

soft costs, including PII, sales tax, overhead, and net profit. 

Looking at this past year, from 2017 to 2018 there was a 5% reduction in the residential PV system cost benchmark.
31

Residential PV: LCOE assumptions

All 2010–2017 data are from Fu et al. (2017), adjusted for inflation. The inverter replacement line-item in Fu et al. (2017) is incorporated into 

O&M expenses in this edition to be consistent with the 2018 O&M benchmark. Other important assumptions: residential PV system LCOE 

assumes a 1) system lifetime of 30 years; 2) federal tax rate of 35% from 2010–2017, changing to 21% in 2018; 3) state tax rate of 7%; 4) 

MACRS depreciation schedule; 5) no state or local subsidies; 6) a working capital and debt service reserve account for 6 months of operating 

costs and debt payments (earning an interest of 1.75%); 7) a 3-month construction loan, with an interest rate of 4% and a fee of 1% of the cost of 

the system; 8) a module tilt angle of 25 degrees, and an azimuth of 180 degrees; 9) debt with a term of 18 years; and 10) $1.1 million of upfront 

financial transaction costs for a $100 million TPO transaction of a pool of residential projects.

2018 USD

per Watt DC

2010 2011 2012 2013 2014 2015 2016 2017 2018

Benchmark report

Installed cost 

($/W)

7.34 6.44 4.55 3.97 3.49 3.23 3.02 2.84 2.70

System size 

(kw-DC) 

5.0 5.0 5.1 5.1 5.2 5.2 5.6 5.7 6.2

Inverter 

loading ratio

1.10 1.11 1.12 1.13 1.13 1.14 1.15 1.15 1.15

Ongoing NREL benchmarking

Annual 

degradation 

(%)

1.00% 0.95% 0.90% 0.85% 0.80% 0.75% 0.75% 0.75% 0.70%

O&M expenses 

($/kw-yr)

54 48 41 36 30 25 25 24 22 

Pre-inverter 

derate (%)

90.0% 90.1% 90.2% 90.3% 90.4% 90.5% 90.5% 90.5% 90.5%

Inverter 

efficiency (%)

94.0% 94.8% 95.6% 96.4% 97.2% 98.0% 98.0% 98.0% 98.0%

Equity 

discount rate 

(real)

9.0% 8.6% 8.3% 7.9% 7.6% 7.3% 6.9% 6.9% 6.9%

Inflation rate 2.5% 2.5% 2.5% 2.5% 2.5% 2.5% 2.5% 2.5% 2.5%

Debt interest 

rate

5.5% 5.4% 5.3% 5.2% 5.0% 4.9% 4.8% 4.8% 4.8%

Debt fraction 34.2% 35.2% 36.1% 37.1% 38.1% 39.0% 40.0% 40.0% 40%
32

Residential PV: LCOE Benchmark Historical Trends

From 2010 to 2018 there was a 71% reduction in the residential PV system electricity cost benchmark (a 6% reduction was 

achieved from 2017 to 2018), bringing the unsubsidized LCOE between $0.12/kWh to $0.16/kWh ($0.08/kWh to $0.10/kWh when 

including the federal ITC). This reduction is 89% towards achieving SETO’s 2020 residential LCOE goal, which is 10 cents/kWh in 

2018 USD.

Note: For LCOE Kansas City, MO, without ITC cases are $0.51/kWh in 2010 and $0.15/kWh in 2018 (2018 USD); see also the 

Appendix. Thus, calculation is: (0.507 – 0.147)/(0.507 – 0.102) = 89%. 
33

Contents

• Introduction and Key Definitions

• Overall Model Outputs

• Market Study and Model Inputs

• Model Output: Residential PV

• Model Output: Commercial PV

• Model Output: Utility-Scale PV

• Model Applications

• Conclusions
34

Commercial PV: Model Structure

System Design

• Available roof area

• Module efficiency

• System architecture

CORE COST 

DRIVERS

MODEL COST 

CATEGORIES INPUTS OUTPUTS

System Location

Company Structure

EPC-System Hardware

• Module

• Inverter

• Structural BOS

• Electrical BOS 

EPC-Other Direct Costs

• Electrical labor

• Mechanical labor

• General construction 

labor

• Construction permit 

and inspection fees

• Interconnection

EPC-Indirect Costs

• Engineering design

• Construction permit 

administration

• EPC SG&A

System Hardware

• Equipment costs

and quantities

• Sales tax

EPC Direct/Indirect Labor

• Wage rates by labor 

class and geography

• Person-hours per task 

by labor class

• Wage burden rates

EPC Other Costs

• SG&A markup

• Supply chain costs

• Other costs and fees

Developer Labor

• Wage rates by labor 

class

• Wage burden rates

Total Equipment Costs

Total Direct and 

Indirect Labor Costs

Total EPC Other and 

Overhead Costs

Total Development 

Costs

Total 

Capital 

Cost

Developer Costs

• Project origination, 

acquisition

• Project engineering 

and management

• Project contingencies

• Developer SG&A

Developer Overhead and 

Other Costs by Category
35

Commercial PV: Modeling Inputs and Assumptions

Category Modeled Value Description Sources

System size 100 kW–1 MW Average installed size per system Go Solar CA (2018)

Module efficiency 19.1% Average module efficiency Go Solar CA (2018)

Module price $0.47/Wdc Ex-factory gate (first buyer) ASP, Tier 1 modules GTM and SEIA (2018), NREL (2018)

Inverter price Three-phase string inverter: 

$0.08/Wdc Ex-factory gate prices (first buyer) ASP, Tier 1 inverters PVinsights (2018), NREL (2018)

Structural 

components (racking) 

$0.10–$0.22/Wdc; varies by location 

due to wind and snow loading Ex-factory gate prices; flat-roof ballasted racking system ASCE (2006), model assumptions, NREL (2018)

Electrical 

components 

$0.13–$0.17/Wdc; varies by location 

due to cost of doing business

Conductors, conduit and fittings, transition boxes, switchgear, panel 

boards, etc. Model assumptions, NREL (2018), RSMeans (2018)

EPC overhead (% of 

equipment costs) 13% Costs and fees associated with EPC overhead, inventory, shipping, and handling NREL (2018)

Sales tax Varies by location Sales tax on equipment costs; national benchmark applies an 

average (by state) weighted by 2017 installed capacities RSMeans (2018), GTM and SEIA (2018)

Direct installation 

labor 

Electrician: $19.74–$38.96 per hour;

Laborer: $12.88–$25.57 per hour;

Varies by location

Modeled labor rate assumes non-union labor and depends on state; 

national benchmark uses weighted average of state rates BLS (2018), NREL (2018) 

Burden rates (% of 

direct labor) Total nationwide average: 31.8% Workers compensation (state-weighted average), federal and state unemployment insurance, FICA, builders’ risk, public liability RSMeans (2018)

PII $0.10/Wdc For construction permits fee, interconnection study fees for existing 

substation, testing, and commissioning NREL (2018)

Developer overhead

Assume 10-MW system 

development and installation per 

year for a typical developer

Includes fixed overhead expenses such as payroll, facilities, travel, 

insurance, administrative, business development, finance, and other 

corporate functions; assumes 10 MW/year of system sales 

Model assumptions, NREL (2018)

Contingency 4% Estimated as markup on EPC cost; value represents actual cost 

overruns above estimated cost NREL (2018)

Profit 7% Applies a fixed percentage margin to all costs including hardware, 

installation labor, EPC overhead, developer overhead, etc. NREL (2018) 
36

As in the commercial model, the national benchmark represents an average weighted by 2017 state installed capacities. We model 

different system sizes because of the wide scope of the “commercial” sector, which comprises a diverse customer base occupying a

variety of building sizes. Also, economies of scale—driven by hardware, labor, and related markups—are evident here. That is, as

system sizes increase, the per-watt cost to build them decreases. Meanwhile, because we assume that a typical developer has 10 

MW of system development and installation per year, the developer overhead on this 10 MW total capacity does not vary for 

different system sizes. When a developer installs more capacity annually, that developer’s overhead per watt in each system 

declines (shown in Figure 18 in our Q1 2015 benchmark report, Chung et al. 2015).

Commercial PV: Model Outputs

Q1 2018 U.S. benchmark: commercial system cost (2018 USD/Wdc)
37

Commercial PV: Model Outputs

This figure presents the benchmark from our commercial model by location in the top U.S. solar markets (by 2017 installations). 

The main cost drivers for different regions in the commercial PV market are the same as in the residential model (labor rates, 

sales tax, and cost of doing business index), but also include costs associated with wind or snow loading.

Q1 2018 benchmark by location: 200-kW commercial system cost (2018 USD/Wdc) 
38

Commercial PV: Capital Cost Benchmark Historical Trends

From 2010 to 2018 there was a 66% reduction in the commercial PV system cost benchmark. Approximately 79% of that 

reduction can be attributed to total hardware costs (module, inverter, and hardware BOS), as module prices dropped 82% over that

time period. An additional 5% can be attributed to labor, which dropped 50% over that time period, with the final 16% attributable to 

other soft costs, including PII, sales tax, overhead, and net profit. 

Looking at this past year, from 2017 to 2018 there was a 3% reduction in the commercial PV system cost benchmark. Cost 

reductions in most categories were moderated by a 32% increase in module spot price.
39

Commercial PV: LCOE assumptions

All 2010–2017 data are from Fu et al. (2017), adjusted for inflation. The inverter replacement line-item in Fu et al. (2017) is incorporated into 

O&M expenses in this edition to be consistent with the 2018 O&M benchmark. Other important assumptions: commercial PV system LCOE 

assumes a 1) system lifetime of 30 years; 2) federal tax rate of 35% from 2010–2017, changing to 21% in 2018; 3) state tax rate of 7%; 4) 

MACRS depreciation schedule; 5) no state or local subsidies; 6) a working capital and debt service reserve account for 6 months of operating 

costs and debt payments (earning an interest of 1.75%); 7) a 6-month construction loan, with an interest rate of 4% and a fee of 1% of the cost of 

the system; 8) a system size of 200 kW; 9) an inverter lifetime of 15 years; 10) a module tilt angle of 10 degrees and an azimuth of 180 degrees; 

11) debt with a term of 18 years; and 12) $1.1 million of upfront financial transaction costs for a $100 million TPO transaction of a pool of 

commercial projects. 

2018 USD

per Watt DC

2010 2011 2012 2013 2014 2015 2016 2017 2018

Benchmark report

Installed cost 

($/W)

5.43 5.04 3.47 2.82 2.80 2.30 2.20 1.88 1.83 

System size (kwDC) 200 200 200 200 200 200 200 200 200

Inverter loading 

ratio

1.10 1.11 1.12 1.13 1.13 1.14 1.15 1.15 1.15

Ongoing NREL benchmarking

Annual 

degradation (%)

1.00% 0.95% 0.90% 0.85% 0.80% 0.75% 0.75% 0.75% 0.70%

O&M expenses 

($/kw-yr)

33 30 28 25 22 19 19 18 18 

Pre-inverter 

derate (%)

90.5% 90.5% 90.5% 90.5% 90.5% 90.5% 90.5% 90.5% 90.5%

Inverter 

efficiency (%)

95.0% 95.6% 96.2% 96.8% 97.4% 98.0% 98.0% 98.0% 98.0%

Equity discount 

rate (real)

9.0% 8.6% 8.3% 7.9% 7.6% 7.3% 6.9% 6.9% 6.9%

Inflation rate 2.5% 2.5% 2.5% 2.5% 2.5% 2.5% 2.5% 2.5% 2.5%

Debt interest rate 5.5% 5.4% 5.3% 5.2% 5.0% 4.9% 4.8% 4.8% 4.8%

Debt fraction 34.2% 35.2% 36.1% 37.1% 38.1% 39.0% 40.0% 40.0% 40%
40

Commercial PV: LCOE Benchmark Historical Trends

From 2010 to 2018 there was a 72% reduction in the commercial PV system electricity cost benchmark (a 3% reduction was 

achieved from 2017 to 2018), bringing the unsubsidized LCOE between $0.09/kWh to $0.12/kWh ($0.06/kWh to $0.08/kWh when 

including the federal ITC). This reduction is 91% towards achieving SETO’s 2020 commercial PV LCOE goal, which is 8 cents/kWh

in 2017 USD. 

Note: For LCOE Kansas City, MO, without ITC cases are $0.39/kWh in 2010 and $0.11/kWh in 2018 in 2018 USD from Appendix. 

Thus, calculation is: (0.393 – 0.107)/(0.393 – 0.079) = 91%.
41

Contents

• Introduction and Key Definitions

• Overall Model Outputs

• Market Study and Model Inputs

• Model Output: Residential PV

• Model Output: Commercial PV

• Model Output: Utility-Scale PV

• Model Applications

• Conclusions
42

Utility-Scale PV: Model Structure

System Design

• Available land area

• Module efficiency

• System architecture

CORE COST 

DRIVERS

MODEL COST 

CATEGORIES INPUTS OUTPUTS

System Location

Company Structure

EPC-System Hardware

• Module

• Inverter

• Structural BOS

• Electrical BOS 

EPC-Other Direct Costs

• Electrical labor

• Mechanical labor

• General construction 

labor

• Construction permit 

and inspection fees

EPC-Indirect Costs

• Engineering labor

• Construction permit 

administration

• EPC SG&A

System Hardware

• Equipment costs

and quantities

• Sales tax

EPC Direct/Indirect Labor

• Wage rates by labor 

class and geography

• Person-hours per task 

by labor class

• Wage burden rates

EPC Other Costs

• SG&A markup

• Supply chain costs

• Other costs and fees

Developer Direct Costs by 

Category

Total Equipment Costs

Total Direct and 

Indirect Labor Costs

Total EPC Other and 

Overhead Costs

Total Development 

Costs

Total 

Capital 

Cost

Developer-Direct Costs

• Site control

• Land acquisition

• Interconnection 

studies, fees, and 

upgrades

• Transmission line

Developer-Overhead

• Project origination 

and acquisition

• Developer SG&A

Developer Overhead 

Markup
43

Category Modeled Value Description Sources

System size 5-100 MW A large utility-scale system capacity Model assumption

Module efficiency 19.1% Average module efficiency NREL (2018) 

Module price $0.47/Wdc Ex-factory gate (first buyer) price, Tier 1 modules GTM and SEIA (2018), NREL (2018)

Inverter price 

$0.04/Wdc (fixed-tilt)

$0.05/Wdc (one-axis tracker) 

Ex-factory gate (first buyer) price, Tier 1 inverters 

DC-to-AC ratio = 1.36 for fixed-tilt and 1.30 for one-axis tracker

Bloomberg (2018), Bolinger and Seel (2018), NREL 

(2018)

Structural 

components (racking) 

$0.10–$0.21/Wdc for a 100-MW 

system; varies by location and 

system size 

Fixed-tilt racking or one-axis tracking system ASCE (2006), model assumptions, NREL (2018)

Electrical components Varies by location and system size

Our model has been upgraded to 1,500 Vdc system, including 

conductors, conduit and fittings, transition boxes, switchgear, panel 

boards, onsite transmission, etc. 

Model assumptions, NREL (2018), RSMeans (2018)

EPC overhead (% of 

equipment costs)

8.67%–13% for equipment and 

material (except for transmission line 

costs); 23%–69% for labor costs; 

varies by system size, labor activity, 

and location 

Costs associated with EPC SG&A, warehousing, shipping, and 

logistics NREL (2018)

Sales tax Varies by location National benchmark applies an average (by state) weighted by 2017 

installed capacities RSMeans (2018), GTM and SEIA (2018)

Direct installation 

labor 

Electrician: $19.74–$38.96 per hour;

Laborer: $12.88–$25.57 per hour;

Varies by location

Modeled labor rate assumes both non-union and union labor and 

depends on state; national benchmark uses weighted average of 

state rates

BLS (2018), NREL (2018)

Burden rates (% of 

direct labor) Total nationwide average: 31.8% Workers compensation (state-weighted average), federal and state unemployment insurance, FICA, builders’ risk, public liability RSMeans (2018)

PII

$0.03–$0.09/Wdc

Varies by system size and location

For construction permits fee, interconnection, testing, and 

commissioning NREL (2018)

Transmission line

(gen-tie line)

$0.00–$0.02/Wdc

Varies by system size 

System size < 10 MW, use 0 miles for gen-tie line

System size > 200 MW, use 5 miles for gen-tie line 

System size = 10–200 MW, use linear interpolation

Model assumptions, NREL (2018)

Developer overhead

2%–12% 

Varies by system size (100 MW uses 

2%; 5 MW uses 12%)

Includes overhead expenses such as payroll, facilities, travel, legal 

fees, administrative, business development, finance, and other 

corporate functions

Model assumptions, NREL (2018)

Contingency 3% Estimated as markup on EPC cost NREL (2018)

Profit

5%–8% 

Varies by system size (100 MW uses 

5%; 5 MW uses 8%)

Applies a percentage margin to all costs including hardware, 

installation labor, EPC overhead, developer overhead, etc. NREL (2018)

Utility-Scale PV: Modeling Inputs and Assumptions
44

Utility-Scale PV: 1000 Vdc and 1500 Vdc

1000 Vdc 1500 Vdc

Input Max. Voltage (Vdc) 1000 1500 

Output Nominal AC Power

(MVA, Mega Volt Amp)

0.792 4

Rated AC operating voltage (Vac) 356 550

Max. Efficiency 98% 98.4%

Reduce trenching 0% 33%

Reduce wiring and cables 0% 33%

Reduce the number of combiner boxes 0% 33%

Reduce the number power conversion 

station (inverter + transformer)

0% 64%

Reduce DC wiring loss from higher 

voltage

No Yes

Reduce AC wiring loss from higher 

inverter efficiency

No Yes

Power harvesting and system 

efficiency

Regular Higher
45

Utility-Scale PV: 1000 Vdc and 1500 Vdc

This figure demonstrates the cost savings from increased voltage from 1000 Vdc to 1500 Vdc. This change 

reduces the total cost by reducing trenching length, wiring and cable length, number of combiner boxes and 

power conversion station (inverter and transformer)

U.S. utility-scale one-axis tracking PV system cost reduction by upgrading from 1000 Vdc to 1500 Vdc (2018 USD/Wdc)
46

This figure shows the percentage of U.S. utility-scale PV systems using tracking systems for 2007–2017. Although the 

data include one-axis and dual-axis tracking systems in the same “tracking” category, there are many more one-axis 

trackers than dual-axis trackers (Bolinger and Seel 2018). Cumulative tracking system installation reached 79% by 2017. 

Utility-Scale PV: U.S. Fixed-Tilt vs. Tracking Systems

Percentage of U.S. utility-scale PV systems using tracking systems, 2007–2017 (Bolinger and Seel 2018)
47

972

MW

216

MW

362

MW 15

MW

554

MW

428

MW

34

MW

66

MW

76

MW

89

MW

78

MW

67

MW

2

MW

3

MW

14

MW

12

MW

201

MW

Utility-Scale PV: Union Labor Case 

Although EPC contractors and developers tend to employ low-cost, non-union labor (based on data from BLS 2018) for PV 

system construction when possible, union labor is sometimes mandated. Construction trade unions may negotiate with the 

local jurisdiction and EPC contractor/developer during the public review period of the permitting process. This figure shows 

2017 utility-scale PV capacity installed (GTM Research and SEIA 2018) and the proportion of unionized labor in each state 

(BLS 2018). The unionized labor number represents the percentage of employed workers in each state’s entire construction 

industry who are union members. In our utility-scale model, both non-union and union labor rates are considered.

138

MW

658

MW

1192

MW

172

MW

179

MW

367

MW

318

MW

47

MW
48

Utility-Scale PV: Model Outputs, EPC Only

 $0.70 $0.80 $0.90 $1.00 $1.10 $1.20 $1.30 $1.40

Oklahoma

Arkansas

Alabama

Montana

South Dakota

North Carolina

Georgia

Oregon

Louisiana

Texas

Wyoming

Delaware

Arizona

Utah

Colorado

New Mexico

New Hampshire

Virginia

Tennessee

South Carolina

Nebraska

Kansas

Idaho

Mississippi

Vermont

Kentucky

Iowa

Puerto Rico

Maryland

Florida

Missouri

Ohio

West Virginia

Maine

Indiana

Michigan

North Dakota

Pennsylvania

Nevada

Washington

DC

Wisconsin

California

New York

Rhode Island

Illinois

Hawaii

Minnesota

New Jersey

Connecticut

Massachusetts

Alaska

(1) Fixed-tilt & Non-Union Labor

(2) One-Axis Tracker & Non-Union Labor

(3) One-Axis Tracker & Union Labor

Modeled EPC Costs

For 100 MW Systems

(2018$ / Wdc)
49

(1) The national benchmark applies an average weighted by 2017 installed capacities.

(2) Non-union labor is used.

(3) Economies of scale—driven by BOS, labor, related markups, and development cost—are demonstrated. 

Utility-Scale PV: Model Outputs, EPC + Developer

Q1 2018 U.S. benchmark: utility-scale PV total cost (EPC + developer) 2018 USD/Wdc
50

Utility-Scale PV: Capital Cost Benchmark Historical Trends

From 2010 to 2018 there was a 77% reduction in the utility-scale (fixed-tilt) PV system cost benchmark, and an 80% reduction in

the utility-scale (one-axis) PV system cost benchmark. Approximately 69% and 63% of that reduction can be attributed to total 

hardware costs (for fixed-tilt and one-axis systems respectively), as module prices dropped 81% over that time period. An 

additional 11%/12% can be attributed to labor, which dropped 81%/84% over that time period, with the final 20%/25% attributable 

to other soft costs, including PII, sales tax, overhead, and net profit (for fixed-tilt and one-axis systems respectively).

From 2017 to 2018, there was a 1% increase in the utility-scale (fixed-tilt) PV system cost benchmark, and a 0.4% increase in the 

utility-scale (one-axis) PV system cost benchmark. The majority of that increase can be attributed to the 32% increase in module

spot price, which offset cost reductions in other areas.
51

Utility-Scale PV (One-Axis Tracker): LCOE assumptions

All 2010–2017 data are from Fu et al. (2017), adjusted for inflation. The inverter replacement line-item in Fu et al. (2017) is incorporated into 

O&M expenses in this edition to be consistent with the 2018 O&M benchmark. Other important assumptions: utility-scale PV system LCOEs 

assume a 1) system lifetime of 30 years; 2) federal tax rate of 35% from 2010–2017, changing to 21% in 2018; 3) state tax rate of 7%; 4) 

MACRS depreciation schedule; 5) no state or local subsidies; 6) a working capital and debt service reserve account for 6 months of operating 

costs and debt payments (earning interest of 1.75%); 7) a 6-month construction loan with an interest rate of 4% and a fee of 1% of the cost of the 

system; 8) a system size of 100 MW; 9) an inverter lifetime of 15 years; 10) debt with a term of 18 years; and 11) $1.1 million of upfront financial 

transaction costs.

2018 USD per Watt DC 2010 2011 2012 2013 2014 2015 2016 2017 2018

Installed cost ($/W) 5.52 4.65 3.20 2.43 2.18 2.00 1.56 1.12 1.13 

Annual degradation (%) 1.00% 0.95% 0.90% 0.85% 0.80% 0.75% 0.75% 0.75% 0.70%

O&M expenses ($/kW-yr) 28 27 25 24 23 22 21 20 14 

Pre-inverter derate (%) 90.5% 90.5% 90.5% 90.5% 90.5% 90.5% 90.5% 90.5% 90.5%

Inverter efficiency (%) 96.0% 96.4% 96.8% 97.2% 97.6% 98.0% 98.0% 98.0% 98.0%

Inverter loading ratio 1.10 1.12 1.13 1.15 1.17 1.18 1.20 1.30 1.30

Equity discount rate 

(real)

7.4% 7.2% 7.0% 6.9% 6.7% 6.5% 6.3% 6.3% 6.3%

Inflation rate 2.5% 2.5% 2.5% 2.5% 2.5% 2.5% 2.5% 2.5% 2.5%

Debt interest rate 5.5% 5.3% 5.2% 5.0% 4.8% 4.7% 4.5% 4.5% 4.5%

Debt fraction 34.2% 35.2% 36.1% 37.1% 38.1% 39.0% 40.0% 40.0% 40.0%
52

Utility-Scale PV (Fixed-Tilt): LCOE assumptions

All 2010–2017 data are from Fu et al. (2017), adjusted for inflation. The inverter replacement line-item in Fu et al. (2017) is incorporated into 

O&M expenses in this edition to be consistent with the 2018 O&M benchmark. Other important assumptions: utility-scale PV system LCOEs 

assume a 1) system lifetime of 30 years; 2) federal tax rate of 35% from 2010–2017, changing to 21% in 2018; 3) state tax rate of 7%; 4) 

MACRS depreciation schedule; 5) no state or local subsidies; 6) a working capital and debt service reserve account for 6 months of operating 

costs and debt payments (earning interest of 1.75%); 7) a 6-month construction loan with an interest rate of 4% and a fee of 1% of the cost of the 

system; 8) a system size of 100 MW; 9) an inverter lifetime of 15 years; 10) debt with a term of 18 years; and 11) $1.1 million of upfront financial 

transaction costs.

2018 USD per Watt DC 2010 2011 2012 2013 2014 2015 2016 2017 2018

Installed cost ($/W) 4.63 3.97 2.70 2.07 1.91 1.85 1.47 1.04 1.06 

Annual degradation (%) 1.00% 0.95% 0.90% 0.85% 0.80% 0.75% 0.75% 0.75% 0.70%

O&M expenses ($/kW-yr) 28 26 24 22 20 18 18 17 13 

Pre-inverter derate (%) 90.5% 90.5% 90.5% 90.5% 90.5% 90.5% 90.5% 90.5% 90.5%

Inverter efficiency (%) 96.0% 96.4% 96.8% 97.2% 97.6% 98.0% 98.0% 98.0% 98.0%

Inverter loading ratio 1.10 1.15 1.20 1.25 1.30 1.35 1.40 1.30 1.36

Equity discount rate 

(real)

7.4% 7.2% 7.0% 6.9% 6.7% 6.5% 6.3% 6.3% 6.3%

Inflation rate 2.5% 2.5% 2.5% 2.5% 2.5% 2.5% 2.5% 2.5% 2.5%

Debt interest rate 5.5% 5.3% 5.2% 5.0% 4.8% 4.7% 4.5% 4.5% 4.5%

Debt fraction 34.2% 35.2% 36.1% 37.1% 38.1% 39.0% 40.0% 40.0% 40.0%
53

Utility-Scale PV: LCOE Benchmark Historical Trends

We use the fixed-tilt systems for LCOE benchmarks from 2010-2015 and then switch to one-axis tracking systems from 2016 to 

2018 to reflect the market share change in the utility-scale PV sector. All detailed LCOE values can be found in Appendix.

From 2010 to 2018 there was a 80%–82% reduction in the utility-scale PV system electricity cost benchmark (a 6%–9% reduction 

was achieved from 2017 to 2018), bringing the unsubsidized LCOE between $0.04/kWh to $0.06/kWh ($0.03/kWh to $0.04/kWh 

when including the federal ITC). This reduction signifies the achievement of SETO’s 2020 utility-scale PV goal, which is 6 

cents/kWh without subsidies.
54

Contents

• Introduction and Key Definitions

• Overall Model Outputs

• Market Study and Model Inputs

• Model Output: Residential PV

• Model Output: Commercial PV

• Model Output: Utility-Scale PV

• Model Applications

• Conclusions
55

This figure demonstrates the cost savings from increased system size. Scaling up the system size from 50 MW to 100 MW 

reduces related costs in several ways: per-watt BOS costs because of bulk purchasing, labor costs because of learning-related 

improvements, and EPC overhead and developer costs because these fixed costs are spread over more installed watts. Note that 

non-union labor is used in this figure.

Model Application — Economies of Scale

Model application: U.S. utility-scale one-axis tracking PV system cost reduction from economies of scale (2018 USD/Wdc)
56

Model Application — Module Efficiency Impacts

Our system cost models can also assess the economic benefits of high module efficiency. Because higher module efficiency 

reduces the number of modules required to reach a certain system size, the related racking or mounting hardware, foundation, 

BOS, EPC/developer overhead, and labor hours are reduced accordingly. This figure presents the relation between module 

efficiency and installed cost (with module prices held equal for any given efficiency) and demonstrates the cost-reduction potential 

due to high module efficiency. Note that fixed-tilt system is used in utility-scale curve and string inverter is used in residential curve.

Modeled impacts of module efficiency on total system costs (2018 USD/Wdc)
57

Contents

• Introduction and Key Definitions

• Overall Model Outputs

• Market Study and Model Inputs

• Model Output: Residential PV

• Model Output: Commercial PV

• Model Output: Utility-Scale PV

• Model Applications

• Conclusions
58

Conclusions

(1) Based on our bottom-up modeling, the Q1 2018 PV cost benchmarks are $2.70/Wdc 

($3.11/Wac) for residential systems, $1.83/Wdc ($2.10/Wac) for commercial systems, 

$1.06/Wdc ($1.38/Wac) for fixed-tilt utility-scale systems, and $1.13/Wdc ($1.54/Wac) for 

one-axis-tracking utility-scale systems. Overall, both modeled installed costs of 

residential and commercial PV systems continued to decline in Q1 2018. Meanwhile, 

modeled utility-scale PV system cost increased slightly.

(2) Lower inverter prices and higher module efficiencies continued contributing to these cost 

reductions across all three sectors. Increased module efficiency, smaller developer 

teams, lower structural and electrical BOS commodity prices, higher small installer 

market share, lower permitting cost, higher voltage configuration, and lower supply chain 

cost also contributed. On the other hand, higher module price, higher labor wages, higher 

advanced inverter adoption, and higher steel prices partially offset the cost reductions 

across the various sectors. 

(3) Our bottom-up system cost models enable us to investigate regional variations, system 

configurations (such as 1500 Vdc vs. 1000 Vdc, MLPE vs. non-MLPE, fixed-tilt vs. oneaxis tracker, and small vs. large system size), and business structures (such as installer 

vs. integrator, and EPC vs. developer). 
59

For More Information

Contact the authors: 

• Ran Fu, Ran.Fu@nrel.gov

• David Feldman, David.J.Feldman@ee.doe.gov

• Robert Margolis, Robert.Margolis@nrel.gov

This work was authored by the National Renewable Energy Laboratory, operated by Alliance for 

Sustainable Energy, LLC, for the U.S. Department of Energy (DOE) under Contract No. DEAC36-08GO28308. Funding provided by U.S. Department of Energy Office of Energy Efficiency 

and Renewable Energy Solar Energy Technologies Office. The views expressed in the article 

do not necessarily represent the views of the DOE or the U.S. Government. The U.S. 

Government retains and the publisher, by accepting the article for publication, acknowledges 

that the U.S. Government retains a nonexclusive, paid-up, irrevocable, worldwide license to 

publish or reproduce the published form of this work, or allow others to do so, for U.S. 

Government purposes.
60

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61

Appendix: PV System LCOE Benchmarks in 2018 USD$

Reporting Year 2010 2011 2012 2013 2014 2015 2016 2017 2018

2020 

Goal

2030 

Goal

Benchmark Date Q4 2009 Q4 2010 Q4 2011 Q4 2012 Q4 2013 Q1 2015 Q1 2016 Q1 2017 Q1 2018

Residential

Phoenix, AZ, no ITC 41.5 34.9 24.1 20.1 16.9 14.8 13.5 12.7 12.0

Kansas City, MO, no ITC 50.7 42.6 29.4 24.6 20.6 18.0 16.5 15.5 14.7 10.2 5.1

New York, NY, no ITC 54.0 45.4 31.3 26.2 21.9 19.2 17.5 16.5 15.6

Phoenix, AZ, ITC 27.6 23.1 16.1 13.4 11.2 9.8 8.9 8.5 7.9

Kansas City, MO, ITC 33.7 28.3 19.7 16.4 13.7 11.9 10.9 10.3 9.7

New York, NY, ITC 35.9 30.1 20.9 17.5 14.6 12.7 11.6 11.0 10.3

Commercial

Phoenix, AZ, no ITC 39.3 34.9 23.6 18.6 17.5 13.9 12.9 11.2 10.9

Kansas City, MO, no ITC 41.6 37.0 25.0 19.7 18.6 14.7 13.7 11.9 11.5 7.9 4.1

New York, NY, no ITC 31.8 28.2 19.1 15.0 14.2 11.2 10.4 9.1 8.8

Phoenix, AZ, ITC 25.9 23.0 15.7 12.4 11.6 9.2 8.6 7.5 7.3

Kansas City, MO, ITC 27.5 24.3 16.6 13.1 12.3 9.8 9.1 7.9 7.7

New York, NY, ITC 21.0 18.6 12.7 10.0 9.4 7.5 6.9 6.1 5.9

Utility-scale (one-axis tracking)

Phoenix, AZ, no ITC 26.7 22.0 15.1 11.5 10.1 9.0 7.1 5.5 5.2

Kansas City, MO, no ITC 29.4 24.3 16.7 12.6 11.1 9.9 7.9 6.1 5.7 6.1 3.1

New York, NY, no ITC 21.1 17.4 12.0 9.1 8.0 7.1 5.6 4.4 4.1

Phoenix, AZ, ITC 17.7 14.6 10.1 7.7 6.8 6.1 4.9 3.9 3.5

Kansas City, MO, ITC 19.5 16.1 11.2 8.5 7.5 6.7 5.4 4.3 3.9

New York, NY, ITC 14.0 11.6 8.0 6.1 5.4 4.8 3.9 3.1 2.8

Utility-scale (fixed-tilt)

Phoenix, AZ, no ITC 27.3 22.9 15.6 11.9 10.7 10.1 8.1 6.0 5.8

Kansas City, MO, no ITC 29.2 24.4 16.7 12.7 11.5 10.7 8.6 6.4 6.2

New York, NY, no ITC 22.4 18.7 12.8 9.7 8.8 8.3 6.7 4.9 4.8

Phoenix, AZ, ITC 18.2 15.2 10.5 8.1 7.3 6.8 5.5 4.2 4.0

Kansas City, MO, ITC 19.4 16.3 11.2 8.6 7.8 7.2 5.9 4.5 4.2

New York, NY, ITC 14.9 12.5 8.6 6.6 6.0 5.6 4.6 3.4 3.2
62

Acronyms and Abbreviations

AC alternating current

BOS balance of system

DC direct current

EPC engineering, procurement, and construction

FICA Federal Insurance Contributions Act

GW gigawatt

ILR inverter loading ratio

ITC investment tax credit

LCOE levelized cost of energy

MACRS Modified Accelerated Cost Recovery System

MLPE module-level power electronics

NEC National Electric Code

NEM net energy metering 

NREL National Renewable Energy Laboratory

O&M operation and maintenance

PERC passivated emitter and rear cells

PII permitting, inspection, and interconnection

PV photovoltaic(s)

Q quarter

R&D research and development

SAM System Advisor Model

SG&A sales, general, and administrative

TPO third party ownership

USD U.S. dollars

Vdc volts direct current

Wac watts alternating current

Wdc watts direct current