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Contract No. DE-AC36-08GO28308

Photovoltaic Shading Testbed 

for Module-Level Power 

Electronics: 2014 Update

Chris Deline

National Renewable Energy Laboratory

Jenya Meydbray and Matt Donovan

PV Evolution Labs / DNV GL

Technical Report

NREL/TP- 5J00-62471

August 2014
NREL is a national laboratory of the U.S. Department of Energy

Office of Energy Efficiency & Renewable Energy

Operated by the Alliance for Sustainable Energy, LLC

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

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

Contract No. DE-AC36-08GO28308

National Renewable Energy Laboratory

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Photovoltaic Shading Testbed 

for Module-Level Power 

Electronics: 2014 Update

Chris Deline

National Renewable Energy Laboratory

Jenya Meydbray and Matt Donovan

PV Evolution Labs / DNV GL

Prepared under Task No. SS12.3050

Technical Report

NREL/TP- 5J00-62471

August 2014
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Photovoltaic Shading Testbed for ModuleLevel Power Electronics: 2014 Update

Abstract

The 2012 NREL report, “Photovoltaic Shading Testbed for Module-Level Power Electronics,” 

provides a standard methodology for estimating the performance benefit of distributed power 

electronics under partial shading conditions. Since the release of the report, experiments have 

been conducted for a number of products, under different weather conditions and for different 

system configurations. Drawing from these experiences, updates to the test and analysis methods 

are recommended. Proposed changes in data processing have the benefit of reducing the

sensitivity to measurement errors and weather variability, as well as bringing the updated

performance score more in line with measured and simulated values of the shade recovery 

benefit of distributed photovoltaic power electronics.

Also, due to the emergence of new technologies, including submodule embedded power 

electronics, the shading method has been extended to include power electronics that operate at a 

finer granularity than the module level. A minor update to the method is proposed to account for 

these emerging technologies that will respond to shading differently than module-level devices.

A revised version of the original test procedure is 

given here, along with updates for submodule 

electronics. The partial-shading test remains a

repeatable test procedure that attempts to simulate 

shading situations as would be experienced by 

typical residential or commercial rooftop 

photovoltaic systems. Performance data for 

multiple products tested using this method are 

discussed, based on equipment from Enphase, Solar 

Edge, Maxim Integrated, and SMA. In general, the 

annual recovery of shading losses from the modulelevel electronics evaluated is 25%–35%, with the 

major difference between different trials being 

related to the number of parallel strings in the test 

installation rather than differences between the 

equipment tested.

Figure 1. 2012 NREL report “Photovoltaic 

Shading Testbed for Module-Level Power 

Electronics.”
2

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1. Overview

The 2012 NREL report, “Photovoltaic Shading Testbed for Module-Level Power Electronics” 

[1], provides the groundwork for experimental evaluation of distributed power electronics. It is a 

repeatable, experimental method that can be conducted over a short period of time (< 1 week) for 

a variety of distributed photovoltaic (PV) power electronics such as microinverters and DC 

power optimizers. The test is designed such that variability in the weather and measurement 

uncertainty can be minimized, and short-term power production can be extrapolated to determine 

annual energy improvement under different shading conditions. 

In the original proposed test, a series of partial-shading conditions were applied to two side-byside PV systems—one equipped with the device under test (DUT) and the other equipped with a 

standard string inverter (reference). The relative performance of one system versus the other was

averaged using a weighted average based on survey data that was collected for representative 

rooftop installations. Three shade conditions were simulated by different weighting conditions: 

“light” shading (7% annual irradiance reduction), “moderate” shading (15%–19% irradiance 

reduction), and “heavy” shading (25% irradiance reduction). These shading conditions were to 

provide the basis for a weighted-average annual performance score, representing the percentage 

of increased annual production from the use of the device in that particular system configuration. 

In the updated method considered here, the experimental methodology remains largely the same. 

A similar method of partial shading is proposed, using the same type of shading fabric and 

amounts of shade. In the case of submodule power electronics, a slight modification to the 

application of shade may be required to account for their particular response to partial shading. 

A major modification to the original method lies in the analysis of the measured shade data. The 

“table method” originally proposed in 2012 is entirely removed because it was found to be 

unreasonably sensitive to measurement errors, among other problems. The alternate “normalized 

method” was found to generate repeatable data because the shaded data are normalized by 

unshaded data on the same system. This removes bias errors from differences in STC rating 

between the two comparison systems, as well as removing variability not captured by 

temperature or irradiance throughout the day. 

Additional improvements to the “normalized method” are proposed here resulting in a more 

accurate final shade-mitigation score. The shade-mitigation score is an estimate of the percentage 

of shading loss that is recovered by the use of the DUT on an annual basis. This value can be 

used directly in annual performance estimation software such as PVWatts or PVSyst to estimate 

the performance and economic benefit of distributed power electronics under different system 

configurations.

2. Test Configuration: Overview and Rationale

The partial-shading testbed was designed to recreate conditions of medium-sized residential 

rooftop systems, composed of 2–3 parallel strings of 10–12 panels. This was done for reasons 

explained in the original paper and supported by references [2,3,4,5]. A side-by-side test with 
3

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two identical arrays is employed. The reference array is equipped with a typical string inverter, 

whereas the DUT array will be equipped with the DUT to be tested.

One consideration for the reference array is that its inverter should be chosen with a DC 

operating window to accept a low-voltage DC input. Uniform shading of up to 30% of the 

modules in a string should be tolerated before minimum maximum-power-point tracking 

(MPPT) tracking voltage limits are reached. See additional discussion on the reference inverter’s 

DC input range in [1].

Measurement of array performance should be conducted using revenue-grade AC kWh meters

with 0.2% accuracy (ANSI C12.20) and 1 Wh resolution at the output of each array. If AC 

microinverters are used in the DUT array, the kWh meter should be placed at the point of 

common AC connection of all of the microinverters in the array. Performance comparison will 

be gauged by periodic measurement of kWh production of both installations taking 1-min 

average AC kWh data. 

Temperature should be collected at the back of a similarly located module in each string (e.g., 

top row edge, bottom row middle). Plane-of-array irradiance should be monitored using a silicon 

photodetector, thermopile pyranometer, or reference cell. Temperature and irradiance are used 

to translate field performance to a common reference condition (here, STC conditions are used:

1000 W/m2 and 25o

C module temperature).

2.1. Direct-Shading Procedure

Direct shading is applied to both the reference and DUT arrays using a semi-transparent mesh 

material in a series of different shade conditions (between 20 and 30 unique shading 

configurations, depending on the system under test). A discussion of the relative merits of direct 

vs. obstruction shading can be found in [1]. The opacity of the shading fabric being used should 

also be at least 50% with a uniform spectral response. The specific mesh suggested here is 

McMaster-Carr P/N 87655K134. This mesh has been found to have a transmittance of 36%

with good spectral uniformity.

The exact methodology for shading the solar 

panels is as follows. A row of modules to be 

shaded are arranged in portrait configuration. 

This will allow side-to-side shading to cover one 

bypass-diode-protected submodule at a time. (In 

a typical 60-cell module, each one-third of the 

module is protected by a single bypass diode.) 

The shading screen is drawn from one side of the 

row to the other, in one-third module increments

(Fig. 2). The shading material should be affixed 

to the frame of the module at the top and bottom 

to prevent the shade screen from moving during a 

test measurement period. (Clothespins work 

Figure 2. Partial shading of a single module 

should use 50% opacity filter to cover all of 

a given bypass diode submodule (one-third

of the module for 60-cell modules). 
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well!) With shade covering the entire submodule, performance is less dependent on individual 

cell reverse-bias characteristics, which can vary widely [6]. An argument can be made that 

shade in the real world does not conform to this approach of covering an entire submodule at a 

time. However, from an electrical standpoint, there is little difference between a single cell in a 

submodule being shaded, and the entire submodule being shaded. The method here assumes a 

limit condition--where any shade on a given submodule is equivalent to the entire submodule

being shaded. Otherwise, there are an infinite number of permutations of shadow shape.

Prior to collecting shaded data on the two arrays, at least one full day of unshaded performance 

should be collected. This allows for the performance of each array under each shaded condition 

to be compared with unshaded performance at a similar time of day on a day immediately 

preceding the shaded data.

Shading is applied to each array according to Table 1. This table assumes three parallel strings 

of 12 modules and 3 bypass diodes per module for a total of 36 submodules in each string. The 

shading configuration is specified by the naming convention A:B:C where A is the number of 

submodules shaded in the first string, B is the number of submodules shaded in the second, and 

C is the number of submodules shaded in the third string. Three separate shade ratios are used, 

each shading a different proportion of the three parallel strings. With single-string shading, only 

one of the three strings is shaded, with the other two strings receiving zero shading. It is 

therefore denoted by the shade vector n:0:0 where n is the number of shaded submodules in 

string A, up to a maximum of 36. The two other shade vectors used in this procedure are twostring shading (n:n:0) and three-string shading (n:n:n). As an example, the single-string shading 

case 4:0:0 has string A with 4 submodules shaded (one full module plus one-third of the next 

module) and strings B and C with no shading. In another example, the uniform shading case 

12:12:12 has all three parallel strings with four complete modules shaded (12 submodules).

Table 1. Shade Conditions for the Direct-Shading Test, Three Parallel Strings of 12 Modules Each

Single-string (n:0:0) shading Two-string (n:n:0) shading Three-string (n:n:n) shading

Submodules shaded n (of 36) Submodules shaded n (of 36) Submodules shaded n (/36)

String 1 String 2,3 String 1,2 String 3 String 1,2,3

1,4,8,12,16,20,24,28,32,35 0 1,4,8,12,16,20,24,28,32,35 0 1,4,8,12,16,20,24,28,32,35

For each of the shading conditions considered, a minimum 5-min measurement interval is 

required, preceded by a settling time to enable the inverters to reach steady-state operation. The 

valid conditions for data collection include solar incidence angle less than 50 degrees with 

respect to the plane of array (POA), as well as clear-sky conditions and POA irradiance greater 

than 500 W/m2

. 

A final consideration deals with inverter peak-power operation. For the reference inverter to 

properly track the global maximum power point, the reference inverter should not be started up 

in a partially shaded condition. If a particular heavily shaded condition is desired, that shading 

condition should be arrived at gradually, giving the inverter several minutes to adjust to each 

subsequent operating voltage.
5

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Submodule-level DUT: The original shading 

procedure was developed for distributed power 

electronics acting at the module level. In the 

case of a DUT that is applied at a finer 

granularity (such as the bypass-diode level), a 

submodule should be defined as the smallest 

group of PV cells connected to a single power 

electronics converter, possibly down to a single 

solar cell. In this case, the number of shaded 

submodules in Table 1 represents the fraction of 

the entire string that should be shaded. 

For a DUT intended specifically for the mitigation of inter-row shading losses, direct shading 

should be applied consistent with the expected shading pattern. For example, the entire string 

should be shaded uniformly from the bottom of the panel up (Fig. 3). In this case, the submodule 

shading values of Table 1 should be converted into a fraction of each module to be shaded by 

dividing by 36. For instance, in the case of inter-row shading, the 12:12:0 shading condition 

involves shading the bottom third of each module in strings A and B. A methodology for interrow shading comparison is detailed in Chapter 5.

3. Analysis Methodology

3.1. Definition of Performance Metrics

Partial-shading results focus on energy production normalized to STC, defined as operation at 

1000 W/m2 and 25oC cell temperature. For a given shade condition, an array’s energy 

production can be normalized to this common reference condition with knowledge of the average 

POA irradiance, the module’s temperature coefficient β, and back-of-module temperature during 

the measurement period:

STC Energy = Energy × �

1000 W/m2

Irradiance � × [1 + β(Tmodule − 25oC)] Eq. (1)

A second value is the amount of energy produced by the reference and DUT system relative to 

unshaded conditions. Here, Normalized Performance is used to express the energy production of 

a shaded system on a scale of zero to one, with the following definition:

Normalized Performance = Shaded STC energy

Unshaded STC energy

Eq. (2)

Normalized Performance represents the impact of shading on either the reference or DUT system 

for each particular shading configuration. Therefore, through the course of measurement, a 

separate normalized performance value is obtained for each reference or DUT system, at each 

unique shading point.

Figure 3. Shading for DUT designed for interrow shading should be applied across an 

entire row from the bottom of the module up.
6

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With this treatment of Normalized Performance, the amounts of shaded and unshaded energy 

generated at STC are obtained from the same time period on consecutive days (one day with 

shading applied, the other with no shading). In effect, we are comparing the shaded system 

against itself under very similar conditions with no shade. By using tests measured on 

consecutive days and at the same time periods during those days to compare shaded to unshaded 

performance, we obtain a measure of system shading impact that is less susceptible to errors 

caused by irradiance and temperature normalizations, angle of incidence, and spectrum, because 

all of those parameters are similar on both days.

Example Normalized Performance data: As an example of how the normalized performance 

data can be displayed for the various shading configurations, the experimental results previously 

published in [1] are shown as Normalized Performance in Fig. 4. The DUT array is equipped 

with Enphase M215 microinverters, compared to a reference array with a string inverter. It is 

clear that although the DUT array has a linear response with respect to shade extent, the 

Reference array has a nonlinear shade response with greater losses from shade.

Figure 4. Normalized Performance data for the experimental results originally provided 

in Ref [1], Fig. 13.

3.2. Shading Histograms from Residential Survey

We now move on from synthetic shading on our test array to a discussion on how shading 

typically occurs in real-world residential installations. To be able to make some generalizations, 

site-survey information was obtained from 66 residential PV installations in California. In these 

measurements, a panoramic view of surrounding obstructions was taken, and the annual 

irradiance lost due to shade was calculated. Here, annual irradiance is defined as “Solar Access” 

measured by a Solmetric Suneye imaging tool [7]. This measurement is averaged across the 
7

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installation using multiple images taken at the corners of the PV array. The annual irradiance

loss for these various site surveys are shown in Fig. 5.

Figure 5. Site survey details for 66 residential installations. The three asterisks * indicate the three

shade-weighting conditions targeted in this test.

Note that the annual irradiance losses shown above in Fig. 5 are not exactly the same as the 

expected electrical losses in the PV system. To determine the actual power losses from shading

would require detailed simulations to be conducted for each system, or to have the shading 

obstructions removed for a period of time for a before-and-after comparison. Because this sort 

of validation is impractical, we are assuming here that a 1:1 relationship exists between a 

system’s reduced Solar Access, and the annual power loss on that system due to shading. 

Rather than analyzing each of the systems in our distribution, three representative systems are 

chosen with different amounts of shading. These three systems, marked in Fig. 5, represent 

light, medium, and heavy residential shading conditions, with annual Solar Access shading 

reductions of 7%, 19%, and 26%, respectively. Additional details about these three 

representative systems may be found in [1]. 

The next step is to investigate the distribution of shading in each system. A key question is 

whether the system’s annual shading loss stems from of a small amount of shade occurring over 

a large period of time, or infrequent instances of heavy shading. A histogram is given in Fig. 6 

that reflects the amount of time in a year that a system operates under different amounts of 

system shading (from unshaded to full system shading). The y-axis of the histogram is scaled by 

the incident irradiance (unshaded) during each associated time period. This method of weighting 

by irradiance accounts for the larger impact for shade occurring during high-irradiance 

conditions. It can be noted that even for the heavily shaded PV installation, the largest single 

component of the histogram is the 0% shaded condition. 
8

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Figure 6. Shading histogram data from site surveys of three representative systems – Light, 

Medium and Heavy. The numerical values of this figure are reproduced in Appendix A.

3.3. Weighting Shading Results by Residential Histogram

The experimental Normalized Performance data of Fig. 4 and the residential histogram data of 

Fig. 6 are combined in the following way. Interpolation of experimental data creates values at 

system shading increments of 5%, to match the bin values of Appendix A and Fig. 6. Values for 

n assuming three parallel strings of 36 submodules (108 total submodules) are given in Table 2.

Table 2. Interpolated n equivalents to match 5% system shading increments 

(n:0:0) shading Two-string (n:n:0) shading Three-string (n:n:n) shading

5% - 30% system 

shade

String 1,2 (5% - 65% system shade) String 1,2,3 (5% - 95% system shade)

n = 5.4, 10.8, 16.2, 21.6, 27, 

32.4

n= 2.7, 5.4, 8.1, 10.8, 13.5, 16.2, 18.9, 21.6, 

24.3, 27, 29.7, 32.4, 35.1

n = 1.8, 3.6, 5.4, 7.2, 9, 10.8, 12.6, 14.4, 16.2, 18, 

19.8, 21.6, 23.4, 25.2, 27, 28.8, 30.6, 32.4, 34.2

Although 38 interpolated datapoints are given in Table 2, some of them correspond to the same 

system shading fraction. For instance, 5% system shading is achieved by the following three 

shading amounts: (5.4:0:0), (2.7:2.7:0) and (1.8:1.8:1.8). If multiple values exist for a given 

system shade fraction, the various values should be averaged1 to create one equivalent 

 

1 Different weighted averages were investigated with slight impact on the final performance score. Judging by Fig. 

9 of [1], uniform shading is more prevalent than distributed shading in the moderate shading case. Because of this, 

the n:0:0, n:n:0, and n:n:n series are weighted in a ratio of 1:2:3. If only two strings are used in a comparison, the 

n:0 and n:n series are weighted in a ratio of 1:2.

1

10

100

1000

10000

0%5%

10%15%20%25%30%35%40%45%50%55%60%65%70%75%80%85%90%95%

Total:

Available Irradiance, kWh/m2

(Before Shading)

Percent of System Shaded

Light

Medium

Heavy
9

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Normalized Performance score for each of the 5% shading fractions from 5%-95%. Zero-shade 

conditions are assigned a Normalized Performance score of 1 by definition since the system must 

perform identically to itself in unshaded conditions.

The interpolated Normalized Performance values, averaged to one number for each 5% shading 

bin are multiplied by the corresponding Annual Irradiance of Appendix A. These weighted 

performance scores are then summed to create the energy score for a given shading histogram 

(e.g., ERef-Light or EDUT-Heavy). Unshaded Energy is the total unshaded irradiance summed over all 

histogram bins.

EX−X = � (Normalized Performance)XX × (Irradiance per bin)

95% shade

0% shade

Eq. (3)

Eunshaded = � (Irradiance per bin)

95% shade

0% shade

Eq. (4)

EDUT and ERef indicate the relative weighted annual performance of each system under the 

various shading conditions: light, moderate, and heavy.

To calculate the percentage of shading loss that can be recovered by the use of the DUT in a 

particular use scenario, a Shade Mitigation Factor (SMF) is determined from the relative 

difference between total Energy for the two systems. SMF is defined as follows:

Shade Mitigation Factor (SMF) = EDUT − ERef

Eunshaded − ERef

Eq. (5)

An advantage of reporting the SMF value for a particular DUT is that its value does not depend

very strongly on the extent of the shade being considered (light vs. heavy). An average value 

can be taken over the three shade histograms used in the analysis. This SMF value can then be 

used directly in performance modeling software such as PVWatts to compare the annual 

performance of a conventional inverter system versus one equipped with the DUT. If the annual 

shading loss is known from a site-survey tool, the correct annual shading derate value with use of 

the DUT is calculated as follows:

Annual Shade derate = 1 − [(Shade Loss %) ∗ (1 − SMF)] Eq. (6)

This is a rough approximation because there is uncertainty in the calculation of the SMF as well 

as the Shade Loss %. Shading Loss is typically reported as a percentage of solar irradiance loss, 

rather than a percentage of electrical performance loss. As stated previously, Eq. (6) assumes a

1:1 correlation between a site survey’s irradiance loss and the resulting PV electrical loss, which 

may not be an accurate assumption.
10

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When using annual performance software, the conversion efficiency of the power electronics 

also needs to be considered. For string inverters or microinverters, the California Energy 

Commission (CEC) efficiency of the device is included in the annual performance calculation. 

For DC power optimizers, the CEC efficiency of the module-level converter is multiplied by the 

CEC efficiency of the string inverter to determine the overall DC-to-AC conversion efficiency.

Comparison with original analysis method: It should be noted than in the original publication 

of this methodology [1], the normalization method fit a linear function through all of the 

Normalized Performance data, rather than maintaining the nonlinear character of the Reference 

inverter data. This ignored the fact that different results existed for the same percentage of 

system shade, according to the distribution of the shade among the various strings. The 

methodology presented here is more representative of reality and yields more consistent (and 

lower) results than the original methodology.

The original methodology also reported a Performance Score for the DUT, defined as the annual 

energy improvement of the DUT system, vs. the Reference system.

Performance Score = EDUT

ERef

Eq. (7)

This Performance Score may or may not be reported in the results of this method, because it 

neglects a number of important factors relevant to annual production such as the conversion 

efficiency of the DUT.

3.4. Example Weighted Results 

When Eqs. (3–5) are applied to the original experimental results of Fig. 4, we can obtain 

weighted-average total Energy and Shade Mitigation Factor values for the example experimental 

data of Fig. 4.

Table 3. Summary of shade study results based on original Enphase M215 data 

Parameter Light Moderate Heavy

% of System Shading 7.6% 19.0% 25.5%

Unshaded Energy [kWh/m2] 1813 1893 1784

Enphase Energy [kWh/m2] 1754 1699 1542

Reference Energy [kWh/m2] 1718 1606 1408

Shade Mitigation Factor 38% 32% 36%

Average Shade Mitigation Factor 35%

Comparison with original analysis method: The original analysis methodology returned a 

Performance Score that was somewhat higher than expected, as explained above. The following 
11

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table describes the difference between the prior analysis method, and the current updated 

method, which returns a somewhat lower value.

Table 4. Comparison between original analysis (Ref [1] table 10) and this updated analysis

Parameter Old analysis New analysis

Performance Score, Light 1.04 1.02

Performance Score, Moderate 1.08 1.06

Performance Score, Heavy 1.12 1.095

Average Shade Mitigation Factor 43% 35%

The new analysis method provides results that are somewhat more consistent with independent

experiments and simulations [8,9], showing Shade Mitigation Factors between 30%–40%, rather 

than the 40%–55% claimed before. In addition, the method is more repeatable and transparent, 

not relying on tables and multiplication factors of unknown origins.

4. Additional experiment results using the current methodology

Several additional experiments were conducted following the updated methodology of this 

shading test. Results are presented here and starting in Appendix D for multiple such 

experiments. Here, we compare Solar Edge power optimizer devices with Enphase M215 

microinverters and a standard string inverter [10]. A second experiment investigates the shade 

response of submodule embedded converters under inter-row shading conditions. This 

submodule experiment features Maxim VT8012 module-embedded power converters, compared 

with a reference string inverter.

4.1. Solar Edge, Enphase M215, and String Inverter test

PV Evolution Labs (PVEL) of Davis, California, was contracted by Solar Edge to perform a test 

on a 6.24 kW Solar Edge system side-by-side with a comparable Enphase system, and a 

reference system using an SMA string inverter. Details of the three comparison systems are 

provided in Table 5 below.
12

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Table 5. System parameters for the two DUT arrays and the Reference array

Reference Array Test Array #1 Test Array 2

Inverter

SMA SolarEdge Enphase

SunnyBoy 6000US OP250-LV optimizers M215

(string inverter) with SE6000A-US 

string inverter

(single-module 

inverter)

Grid Connection 240-volt single-phase

Module Sharp ND240QCJ

# of Strings 2

# of Modules/String 13

Nameplate DC System 

Power 6.24 kW

CEC Efficiency 95.5% 98.8% * 97.5% 96%

System Location PV-USA (Davis, CA)

System Orientation 20-degree south-facing, portrait orientation

Testing Dates June 19 to June 21, 2013

In contrast with the results presented in [1] and in Fig. 4 above, the configuration considered here 

consists of two parallel strings of modules, rather than three parallel strings per system. As such, 

the results are not entirely comparable to the previous results. The Shade Mitigation Factor 

determined for a two-string system will tend to be lower than SMF for a three-string (or larger) 

system because the mismatch between parallel strings will be lower for the smaller system. 

However, the comparison includes the same Enphase M215 microinverter as previously used, 

which helps to benchmark the new experiment configuration against a three-string configuration.

Partial shading performance is monitored over 22 shading conditions as described in 2.1. With 

13 PV modules and 3 diodes per module, there are a total of 39 submodules per string. Because

there are two parallel strings per system, the two shading configurations tested were n:0 and n:n.
13

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Figure 7. Close-up view of shading mesh on a single string.

The Normalized Performance of the two DUT systems and the Reference system are shown in 

Fig. 8, calculated by Eq. (2). The shaded results are compared with unshaded data, measured 

within three days of the shaded experiments. By translating data to STC conditions, as well as 

comparing against unshaded data at the same time of day, variable conditions such as

temperature, irradiance, and differences in PV module nameplate rating are removed from the 

comparison.

Figure 8. Normalized Performance of the three systems under 22 partial shading conditions.

Inspection of the Normalized Performance in Fig. 8 indicate that the SolarEdge and Enphase 

DUT arrays are closely matched, while the Reference array follows a similar nonlinear response 

to that of the Reference Array in Fig. 4.

0.2

0.4

0.6

0.8

1.0

1:04:08:0

12:016:020:024:028:032:035:038:0

1:14:48:8

12:1216:1620:2024:2428:2832:3235:3538:38

Normalized Perormance

Shading Configuration

SolarEdge Enphase Reference
14

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The above experimental results are analyzed according to the method described in Section 3.3. 

Namely, linear interpolation of data points match the n:0 and n:n results to the 5% shading bins 

of Appendix A. For 0%–50% system shading where both n:0 and n:n results contribute, the 

values are weighted with n:n results counting for twice the value of n:0 results. This weighted 

average is based on Fig. 9 of [1], which shows a greater proportion of uniform (n:n) shading than 

isolated (n:0) shading; the sensitivity of the analysis to the weighting value is very small.

Following interpolation, the Normalized Performance is used to calculate total Energy and Shade 

Mitigation Factor for each system under different shading conditions, according to Eqs. (3–5). 

These results are provided in Table 6.

Table 6. Summary of shade study results – SolarEdge OP250 and Enphase M215

Parameter Light Moderate Heavy

% of System Shading 7.6% 19.0% 25.5%

Unshaded Energy [kWh/m2] 1813 1893 1784

SolarEdge Energy [kWh/m2] 1729 1616 1438

Enphase Energy [kWh/m2] 1727 1610 1431

Reference Energy [kWh/m2] 1696 1539 1328

Shade Mitigation Factor 27-28% 20-22% 23–24%

Average Shade Mitigation Factor 23–25%

As expected, the close match of Normalized Performance data of Fig. 8 results in similar average 

SMF for the two DUT arrays: 23% for the Enphase array, and 25% for the SolarEdge array. 

These values can be contrasted with the 35% average SMF value for the three-string experiment.

The difference in results between Table 3 and Table 6 can be explained by the size difference 

between the two experiments. The original comparison was conducted on a three-string system, 

in which case the use of module-level electronics resulted in the recovery of 35% of the shade 

losses. The greater shade-mitigation factor indicates that a larger portion of the shading losses 

are indirect losses from mismatch between parallel strings, as opposed to direct losses from 

irradiance reduction. Distributed electronics only recover losses due to mismatch, and an 

increased number of parallel strings increases the opportunity for mismatch between shaded and 

unshaded strings.

5. Shading histograms for inter-row shading applications

The previously described Light, Medium, and Heavy shade histograms are intended to replicate 

horizon shading on residential rooftops, e.g., from nearby tree or building obstructions. In the 

application considered here of inter-row shading, new shading histograms are required that are 

more representative of large, free-field installations. In this case, regular row spacing and rows 
15

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of infinite length are assumed, as well as representative system configurations of 20-degree tilt 

and south-facing orientation. 

In keeping with the spirit of the previous test configuration, three shading conditions are again 

chosen to represent partial shading from different row spacing. The representative shading 

conditions are defined by a ground coverage ratio (GCR), defined as the ratio of the PV array 

area to the total ground area. The three GCR values evaluated here are: 0.64, 0.74, and 0.8.

Inter-row shading histograms are required for both portrait and landscape mounting orientations. 

Given the typical configuration of ground-mount systems, both 2-up portrait configuration, and 

3-up landscape configuration were chosen for further analysis (Fig. 9). Both histograms assume 

infinite spatial extent in all directions to limit edge effects. Therefore, the fact that the first row 

of a PV system is unshaded is neglected from this analysis. 

Figure 9: 2-up portrait configuration (left) and 3-up landscape configuration (right). Row spacing is 

defined from the front of one row to the front of the next.

Annual simulations were conducted in NREL’s System Advisor Model to model the extent of 

shading loss, using the inter-row shade calculation function described in [11]. Array dimensions 

are calculated assuming a typical 60-cell PV module size of 1.65 m × 0.99 m in either 2-up 

portrait or 3-up landscape orientation. A 0.5 MWac central inverter was assumed, along with 

150 parallel strings of 250 W panels at 20-degree fixed tilt, 180-degrees azimuth. Such a large 

installation was chosen to limit edge effects. The Sacramento TMY2 weather file was chosen as 

a representative meteorological dataset, as well. 

Given the above parameters, simulations were conducted for three GCR values and two module 

orientations. Simulated shading loss is calculated relative to unshaded system performance, and

separated into beam shading loss (transient opaque shading leading to large intra-panel

mismatch) and diffuse loss (persistent small irradiance loss across the system due to reduced 

field-of-view of the diffuse sky dome). A detailed discussion of diffuse shading loss in this 

system is given in [12]. For the inter-row shading procedure considered here, only the beam 

shading loss is considered for recovery. The test methodology does not allow the extremely 

slight mismatch from diffuse irradiance loss to be monitored or measured for recovery. Even if 

the DUT were to recover some of this type of diffuse irradiance mismatch, the experimental 

methodology is not set up to capture it. Therefore, the resulting Shade Mitigation Factor 

considers only the recovery of beam shading loss, not beam + diffuse shading loss.

Row spacing S Row spacing S
16

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It can be seen that the various shading simulations result in total annual estimated losses between 

4% and 14%, with the beam shading loss accounting for roughly half of the total loss. Note that 

these simulated values are specific to the orientation and weather data assumed above. 

Table 7. Inter-row shading configuration and beam shading loss (Reference system)

Parameter GCR:0.64 GCR:0.74 GCR:0.8

Row spacing (landscape) [m] 4.6 4.0 3.7

Row spacing (portrait) [m] 5.1 4.5 4.1

Annual beam loss (3x landscape) 1.5% 3.7% 5.7%

Annual diffuse loss (3x landscape) 2% 3.7% 5.3%

Annual beam loss (2x portrait) 2.3% 5.6% 8.6%

Annual diffuse loss (2x portrait) 2% 3.7% 5.3%

More detailed beam-shading histograms are calculated based on [13] and hourly solar position 

and irradiance values from the Sacramento, CA TMY2 dataset. As before, the hourly histogram 

of shade extent is weighted by the unshaded POA irradiance during that period of time. Figure 

10 shows the annual histogram of shade extent for each of the three GCR values, in the 2-up 

portrait configuration. The annual irradiance for this simulation is 1993 kWh/m2, with the 

majority of that irradiance occurring under unshaded conditions. At higher GCR values, greater 

amounts of shading occur. 

It is interesting to note that 100% system shading accounts for the same kWh/m2 value in this 

histogram, regardless of GCR value. Shading of the entire system occurs only at sunrise and 

sunset, when shadows are cast far enough to shade everything regardless of row spacing.

Figure 10. Shading histogram data for 2-up portrait inter-row shading. The numerical values of this 

figure are reproduced in Appendix B. 

0.1

1.0

10.0

100.0

1000.0

Available Irradiance, kWh/m2

(Before Shading)

Percent of System Shaded

Portrait 2-up inter-row shading

GCR 0.64

GCR 0.74

GCR 0.8
17

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In practice, 2-up portrait shading performance data requires two strings connected in parallel to

the same string inverter. Because shading is applied artificially, modules do not need to be 

physically mounted in a 2-up portrait configuration – the two strings can be located in separate 

rows and shaded separately. The first string is considered to be the “bottom” string and is shaded 

along its entire length (all modules). It may be easier to drape the shading fabric from the top 

edge of the modules down, rather than pulling from the bottom up. Either way, the shading 

fabric is pulled down (or up) along all of string #1 in 10% module height increments.

At the 50% system shade condition, the first string is fully covered by the shading fabric. For 

performance data from 50% to 100% system shading, the first string is kept fully shaded, and

shading fabric is next applied to string #2 in 10% height increments until it too is fully shaded.

A similar shading histogram is generated for the 3-up landscape system configuration 

(Appendix C). Because there are three modules high instead of two modules, the first module is 

fully shaded at 33% system shading, rather than 50% system shading.

Diffuse irradiance component: The previous shading methodology used a shading fabric with 

0.36 measured transmittance (McMaster-Carr P/N 87655K134). This fabric was chosen to 

maintain a diffuse fraction of irradiance that is less than 50%. Although this choice was 

appropriate for the horizon and obstruction shading conditions of residential rooftops, the diffuse 

fraction of irradiance is somewhat greater for inter-row shading conditions. The ratio of Diffuse

irradiance to Global irradiance (D/G) ranges from D/G = 0.3 at unshaded conditions to D/G ≈ 1 

at large amounts of system shading (Fig. 11). 

Annual weighted averages of D/G (neglecting unshaded conditions) for the greatest row spacing 

(GCR = 0.64) are D/G = 0.55. This is considerably higher than the 0.36 transmittance value of 

the shading fabric used for the residential shading test. A different shading fabric is proposed 

here with a higher measured transmittance: McMaster-Carr P/N 88275K39 with a measured 

transmittance of 0.62. This type of fabric is considered to be more appropriate for the more 

diffuse shade conditions experienced during inter-row shading.
18

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Figure 11. Weighted diffuse fraction (D/G) for inter-row shading. The overall annual weighted 

diffuse fraction is D/G = 0.55 for GCR = 0.64. Other annual weighted values are D/G = 0.49 and D/G = 

0.44 for GCR = 0.74 and GCR = 0.8, respectively. Results are identical for portrait and landscape 

configurations.

5.1. Results: Maxim sub-module converters

The above methodology for inter-row shading comparison was verified on a field installation at 

NREL’s Regional Test Center site in Aurora, CO. The Device Under Test is the Maxim VT8012 

embedded electronic module, which uses six DC-DC converters per 72-cell panel. This 

embedded module is designed to reduce inter-row shading losses when installed in portrait 

configuration, so the 2-up portrait shading histogram of Appendix B is used in this experiment. 

More details on this technology can be found in [12].

The VT8012 embedded devices are built around a standard JA Solar 300W panel, integrated at 

the factory. Two parallel strings of 10 panels each are used in the DUT array (with VT8012 chips 

embedded) and the Reference array (without VT8012 chips). 

Both the DUT array and the Reference array are connected to conventional string inverters 

(Power-One PVI-6000) to provide DC-to-AC conversion. String-level performance is monitored 

by independent current and voltage transducers, as well as calibrated onboard inverter

monitoring.

0.2

0.4

0.6

0.8

1

0% 20% 40% 60% 80% 100%

Irradiance diffuse fraction (D/G)

Percent of System Shaded

GCR 0.64

GCR 0.74

GCR 0.8
19

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Table 8. System parameters for the DUT array and the Reference array

Reference Array DUT Array 

Inverter

Power-One Maxim VT8012 embedded DC 

converters with PVI-6000-US

string inverter PVI-6000-US

(string inverter)

Grid Connection 277-volt single-phase

Module JA Solar JAP6-72-300-3BB

# of Strings 2

# of Modules/String 10

Nameplate DC System 

Power 6 kW

CEC Efficiency 96.5% 96.5%*

System Location Aurora, CO

System Orientation 30-degree south-facing, portrait orientation

Testing Dates April 8 to April 14, 2014

*DUT conversion efficiency is included in the 300W factory flash value of the PV module

Figure 12: Maxim installation at the Aurora, CO, site (Unshaded panels in the foreground are not 

included in the partial-shade experiment).
20

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Direct shading was applied using the 62% transparent mesh suggested above (McMaster-Carr 

P/N 88275K39). Unshaded measurements were collected over a full day. A total of 14 partial 

shading configurations were collected in 10-min intervals over the next several days. Shading 

fabric was extended over the entire length of String #1 of the DUT array and the Reference array, 

and lowered in increments of 1.5 cells (12.5%). Once the first string of each array is fully 

covered, the second string is shaded in 12.5% increments until both strings of both arrays are 

fully covered. The raw data are aligned with the 10% interval of Appendix B by linear 

interpolation. 

All data were acquired under clear-sky conditions with POA irradiance greater than 500 W/m2

. 

The mesh was applied and a wait time of several minutes was allowed to ensure that the inverters

stabilize prior to collecting energy data. Normalized Performance results are given in Fig. 13. 

The results are consistent with the Maxim-equipped system responding in a linear fashion to 

increased amounts of shade, whereas the Reference system has a very large performance 

reduction when partial shading is introduced. In this particular comparison where shading is 

applied horizontally across all substrings of the Reference system, any amount of shading on a 

particular string results in a very large drop in performance. For instance, a large performance 

drop occurs from 0% to 6.25% system shading when String 1 is just beginning to be shaded, and 

from 50% to 56.25% shading when String 2 is just beginning to be shaded.

Figure 13. Normalized Performance of the Maxim VT8012 system and Reference system under 2-

up portrait inter-row shading.

Following linear interpolation, the performance results are weighted by the irradiance histogram 

values shown in Appendix B for the 2-up portrait configuration. Results are given in Table 9, 

including a Shade Mitigation Factor for the beam shading loss.

0.5

0.6

0.7

0.8

0.9

1.0

Normalized Perormance

Shading Configuration

Maxim Reference
21

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Table 9. Summary of shade study results – Maxim 2-up portrait

Parameter GCR:0.64 GCR:0.74 GCR:0.8

Modeled beam loss (Reference) -2.3% -5.6% -8.6%

Modeled diffuse loss (Reference) -2.0% -3.7% -5.3%

Unshaded Energy [kWh/m2] 1988 1988 1988

Maxim Energy [kWh/m2] 1975 1954 1934

Reference Energy [kWh/m2] 1953 1905 1866

Actual beam loss (Reference) -1.7% -4.2% -6.2%

Actual beam loss (Maxim) -0.6% -1.7% -2.7%

Shade Mitigation Factor 64.1% 59.1% 55.9%

Average Shade Mitigation Factor 60%

The Shade Mitigation Factor of the VT8012 Maxim integrated power electronics is very good in 

this application, resulting in a recovery of ~60% of the beam shading loss. One reason for this 

large performance benefit is the particularly high loss that occurs in the Reference system. For 

conventional modules in portrait orientation, inter-row shading is oriented perpendicular to the 

orientation of the bypass-diode submodules. Consequently, all modules are equally shaded, and 

bypass diodes are not providing any performance benefit. If the reference modules were instead 

oriented in landscape rather than in portrait, the Reference system shading loss would likely be 

lower, as would Maxim’s calculated SMF value. 

As previously stated, this experimental procedure is unable to assess the slight and persistent 

mismatch from diffuse irradiance screening. It is expected that the DUT would have a reduced 

ability to mitigate such a small mismatch, but this is speculation because the effect has not been 

assessed. In a worst-case scenario where the diffuse irradiance loss is included in the SMF 

calculation, but no additional performance benefit is provided by the DUT, the overall shade 

recovery is ~35%. This reflects the fact that beam shading loss accounts for slightly over half of 

the total shading loss simulated in the reference system.

From inspection of Table 9, a comparison can be made between the modeled and experimental

beam shading losses. The modeled beam losses for the Reference system are slightly higher than

what was determined by following the partial-shading procedure. For instance, at GCR = 0.8, 

modeled beam shading loss for the Reference system is -8.6%, but the experimental results show 

only a -6.2% actual shading loss. This slight discrepancy could likely be corrected by the use of 

a more opaque shading fabric during the partial shading experiment. It was originally calculated 

that a 62% transparent shading fabric would be more appropriate than the 37% transparent fabric 

used before. However, preliminary estimates suggest that the use of the more opaque shading 

fabric would result in a greater experimental shading loss, bringing experimental shading losses

more in line with the modeled annual shading losses. Preliminary estimates have the 37% 

transparent fabric increasing the experimental losses to -9% for GCR: 0.8. However, the SMF 

value is predicted to remain essentially unchanged, because shading losses will increase in both 

the Reference system and the Maxim system. Based on this assumption, either the 62% 

transparent or the 37% transparent shading fabric would be adequate for this type of shading test.
22

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

6. Conclusion

The original NREL Partial-Shading Test Procedure has been updated, bringing experimental 

results more in line with modeled behavior of module-level power electronics, and making the 

test procedure more robust and repeatable. An analysis was conducted of how these updates 

affect initially published performance results, slightly reducing the expected performance benefit 

of distributed electronics. Additional performance results are detailed for electronics 

manufacturers including Solar Edge. Results collected to date indicate that Shade Mitigation 

Factor (SMF) values range between 25% and 35%, depending on the number of parallel strings 

in the test array (two or three). Only slight performance differences were apparent between the 

different module-level electronics under test.

A new test protocol and weighting histogram has been provided for the investigation of inter-row 

shading losses. An initial application of the protocol using Maxim Integrated VT8012 panels in 

portrait configuration shows that 60% of beam shading losses can be recovered from the use of 

this embedded technology. A caveat should be stated that the method described here is not 

suitable to assess the very slight but persistent performance loss arising from field-of-view 

reduction of diffuse irradiance. An additional performance improvement might be achieved 

from devices in the field if this type of mismatch could be monitored.

Additionally, the orientation of the PV modules has a large impact on the system performance; 

the use of a landscape orientation would have a different, likely lower, SMF score for this 

particular technology.

Further performance results will be continuously updated, beginning in Appendix D for partner 

experiments occurring after initial publication of this technical report.

We hope that the test methodology described here can be of use at different test installations or 

by equipment manufacturers to gauge the benefit of their equipment in these various 

applications. In particular, the Shade Mitigation Factor can be of particular value to consumers 

evaluating performance benefits of distributed power electronics, relative to conventional 

equipment. Combined with the CEC efficiency of the device (or the CEC efficiency of the 

inverter upstream of the device), this SMF score provides an annual derate that could be used in 

many PV simulation programs such as NREL’s PVWatts or SAM to more accurately predict 

annual system performance.

Acknowledgements

Test data included here were collected under test service agreements between PV Evolution 

Laboratory, Enphase Energy, and Solar Edge. Testing methods were developed and data 

analysis was independently conducted by the National Renewable Energy Laboratory under 

Contract No. DOE-AC36-08GO28308 with the Department of Energy. Maxim Integrated 

performance data were collected under a Cooperative Research and Development Agreement 

with the Department of Energy’s Regional Test Centers. Testing was conducted at PV Evolution 

Labs by Rajeev Singh, Filiberto Alex Pineda, and Dang H. Dang. Additional performance data 

included in the Appendices may be covered under additional agreements.
23

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

References

1. C. Deline, J. Meydbray, M. Donovan, J. Forrest, Photovoltaic (PV) Shading Testbed for 

Module-level Power Electronics, NREL Report No. TP-5200-54876. Golden, CO: National 

Renewable Energy Laboratory, May 2012. http://www.nrel.gov/docs/fy12osti/54876.pdf

2. C. Deline, B. Marion, J. Granata, S. Gonzalez. A Performance and Economic Analysis of 

Distributed Power Electronics in Photovoltaic Systems. NREL Report No. TP-5200-50003. 

Golden, CO: National Renewable Energy Laboratory, December 2010. 

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3. California Energy Commission. New Solar Homes Partnership Committee Final Guidebook. 

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[9] Hanson A, Deline C, MacAlpine S, Stauth J, Sullivan C, “Partial-Shading Assessment of 

Photovoltaic Installations via Module-Level Monitoring”, IEEE Journal of Photovoltaics 2014 

(in review) 

[10] Solar Edge white paper “Performance of PV Topologies under Shaded Conditions”, July 

2013 

http://www.solaredge.com/files/pdfs/performance_of_pv_topologies_under_shaded_conditions.p

df

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uniform shading in large photovoltaic arrays” Solar Energy 96, 274-282 

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[13] J Appelbaum, J. Bany, “Shadow effect of adjacent solar collectors in large scale systems”. 

Solar Energy 23, 497-507 1979
24

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Additional Bibliography

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A. Woyte, J. Nijs, R. Belmans. “Partial Shadowing of PV Arrays with Different System 

Configurations: Literature Review and Field Test Results.” Solar Energy; Vol. 74, 2003; pp. 

217–233.

N. Chaintreuil, F. Barruel, X. Le Pivert, H. Buttin, J. Merten. “Effects of Shadow on a Grid 

Connected PV System.” 23rd European Photovoltaic Solar Energy Conference and Exhibition, 

2008; p. 3417.

C. Deline. “Partially Shaded Operation of a Grid-Tied Photovoltaic System.” 34th IEEE 

Photovoltaic Specialists Conference, Philadelphia, PA, 2009.

S. MacAlpine, M. Brandemuehl, R. Erickson. “Analysis of Potential for Mitigation of BuildingIntegrated PV Array Shading Losses Through the Use of Distributed Power Converters.” ASME 

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C. Deline. “Characterizing Shading Losses on Partially Shaded PV Systems.” PV Performance 

Modeling Workshop, Albuquerque, NM, 2010. NREL Report No. PR-5200-49504.

B. Burger, B. Goeldi, S. Rogalla, H. Schmidt. “Module Integrated Electronics – An Overview.” 

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P. Tsao. “Simulation of PV Systems with Power Optimizers and Distributed Power Electronics.” 

IEEE Photovoltaic Specialists Conference, Honolulu, HI, 2010.

S. MacAlpine, M. Brandemuehl, L. Linares, R. Erickson. “Effect of Distributed Power 

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Geometries.” ASME 3rd International Conference on Energy Sustainability, San Francisco, CA, 

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A. Kimber, L. Mitchell, S. Nogradi, H. Wenger. “The Effect of Soiling on Large Grid-Connected 

Photovoltaic Systems in California and the Southwest Region of the United States.” IEEE 4th

World Conference on Power Conversion, Waikoloa, HI, 2006.

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Transactions on Power Electronics, in press; doi: 10.1109/TPEL.2011.2173353
25

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Appendix A: Shading histogram data – Residential Shading

% System 

Shade

Annual Irradiance (kWh/m2)

Light Medium Heavy

0% 1490.85 1180.17 866.45

5% 61.88 57.67 39.62

10% 39.43 53.11 100.54

15% 50.20 58.68 82.15

20% 15.01 73.83 42.96

25% 30.41 52.93 80.99

30% 25.21 37.45 68.64

35% 13.26 29.18 51.97

40% 16.48 25.01 56.08

45% 7.62 35.92 49.17

50% 5.76 34.84 74.89

55% 11.16 22.71 33.53

60% 4.47 21.74 14.41

65% 16.55 32.99 21.19

70% 4.62 27.11 62.55

75% 6.18 23.73 41.99

80% 6.63 36.38 17.51

85% 1.49 36.22 22.43

90% 4.07 31.26 31.57

95% 1.25 21.55 25.04

Table A1: Tabulated values for partial shading irradiance shown in Fig. 5, matched to a 5% bin frequency (the bin 

label represents the minimum value in the bin)
26

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Appendix B: Shading histogram data – Inter-row Shading (Portrait 2-up)

% System 

Shade

Annual Irradiance (kWh/m2)

GCR: 0.6 GCR: 0.7 GCR: 0.75

0% 1825.4 1602.0 1421.9

5% 88.9 90.4 115.0

10% 25.9 77.7 116.0

15% 17.2 106.5 87.8

20% 7.6 51.0 93.2

25% 8.0 28.1 87.1

30% 7.2 8.3 33.6

35% 1.4 9.5 9.1

40% 0.8 7.1 10.2

45% 0.9 1.2 6.9

50% 1.0 1.0 1.3

55% 1.1 1.1 1.1

60% 1.2 1.2 1.3

65% 0.9 1.4 1.4

70% 0.3 1.1 1.6

75% 0 0.2 0.5

80% 0 0 0.1

85% 0 0 0

90% 0 0 0

95% 0 0 0

100% 4.5 4.5 4.5

Table B1: Tabulated values for 2-up portrait inter-row shading shown in Fig. 10, matched to a 5% bin frequency 

(the bin label represents the maximum value in the bin)
27

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Appendix C: Shading histogram data – Inter-row Shading (Landscape 

3-up)

% System 

Shade

Annual Irradiance (kWh/m2)

GCR: 0.6 GCR: 0.7 GCR: 0.75

0% 1827.0 1594.1 1415.8

5% 87.5 93.6 118.6

10% 26.0 79.4 113.0

15% 17.0 101.3 89.1

20% 7.7 58.1 92.7

25% 8.1 29.1 91.4

30% 7.0 8.3 33.6

35% 1.4 9.2 8.6

40% 0.8 7.6 10.5

45% 0.9 1.3 7.4

50% 1.0 1.0 1.3

55% 1.1 1.1 1.1

60% 1.2 1.2 1.3

65% 0.9 1.4 1.3

70% 0.3 1.1 1.6

75% 0 0.2 0.5

80% 0 0 0

85% 0 0 0

90% 0 0 0

95% 0 0 0

100% 4.5 4.5 4.5

Table C1: Tabulated values for inter-row shading irradiance (3-up landscape) matched to a 5% bin frequency (the 

bin label represents the maximum value in the bin)
28

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Appendix D: Measured data from additional partners (To be included at 

a later date)