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

Field Guide for Testing Existing 

Photovoltaic Systems for 

Ground Faults and Installing 

Equipment to Mitigate Fire 

Hazards

November 2012 — October 2013

William Brooks

Brooks Engineering

Vacaville, California

NREL Technical Monitor: Thomas Basso

NREL Task Leader: Michael Coddington 

Prepared under Subcontract No. LGN-3-23371-01

Subcontract Report

NREL/SR-5D00-61018

February 2015
NREL is a national laboratory of the U.S. Department of Energy

Office of Energy Efficiency & Renewable Energy

Operated by the Alliance for Sustainable Energy, LLC

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

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

Contract No. DE-AC36-08GO28308

National Renewable Energy Laboratory

15013 Denver West Parkway

Golden, CO 80401

303-275-3000 • www.nrel.gov

Field Guide for Testing 

Existing Photovoltaic Systems 

for Ground Faults and 

Installing Equipment to 

Mitigate Fire Hazards

November 2012 — October 2013

William Brooks

Brooks Engineering

Vacaville, California

NREL Technical Monitor: Thomas Basso

NREL Task Leader: Michael Coddington 

Prepared under Subcontract No. LGN-3-23371-01

Subcontract Report

NREL/SR-5D00-61018

February 2015
NOTICE

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

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

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iii

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Nomenclature

ac alternating current

dc direct current

NEC National Electrical Code

OCPD overcurrent protection device

PPE personal protective equipment

PV photovoltaic

RCM residual current monitor

Voc open circuit voltage
iv

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Executive Summary 

Experience from the field suggests that ground faults and arc faults are the two most common 

reasons for fires in photovoltaic (PV) arrays; methods are available that can mitigate the hazards. 

This report provides field procedures for testing PV arrays for ground faults, and for 

implementing high-resolution ground fault and arc fault detectors in existing and new PV system 

designs. 

Recent research done by the Solar America Board for Codes and Standards has shown that some 

PV system ground faults go undetected, which can lead to fires in PV arrays [1,2,3,4]. These 

undetected faults have been termed blind spots in the ground fault detection circuits used in most

U.S. PV installations. These blind spots can be effectively eliminated by detection systems that 

monitor ground current at much higher resolution than is currently required. Arc fault detectors 

are now available that can detect and remove series arc faults as required by the 2011 National 

Electrical Code [5].

The combination of good maintenance procedures, high-resolution ground fault detectors, and 

arc fault detectors effectively addresses fire hazards in existing and new PV system installations. 

Moving forward, new system designs and construction should incorporate these features, 

because the cost of retrofitting is considerably higher than having the features initially installed. 
v

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Contents

List of Figures ............................................................................................................................................ vi

List of Tables .............................................................................................................................................. vi

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

2 Testing for Ground Faults ................................................................................................................... 3

2.1 Testing Photovoltaic Systems With Indicated Ground Faults......................................................... 3

2.1.1 Locating a Known Ground Fault....................................................................................... 4

3 Testing Photovoltaic Systems With No Known Ground Faults....................................................... 9

3.1 Insulation Testing Procedure ........................................................................................................... 9

3.2 Field Procedure ................................................................................................................................ 9

3.2.1 Phase 5: Testing the Whole Array at the Photovoltaic Output Circuit Combiner .......... 10

3.2.2 Phase 6: Testing Subarray at Individual Source Circuit Combiners............................... 11

4 Retrofitting Existing Photovoltaic Systems With High-Resolution Ground Fault Detectors ..... 13

4.1 Installing a Residual Current Monitor on a Photovoltaic Array With a Large Inverter................. 13

4.1.1 Selecting and Installing the Appropriate Residual Current Monitor............................... 15

4.1.2 Additional Installation Notes.......................................................................................... 17

5 Retrofitting Existing Photovoltaic Systems With Arc Fault Detectors ......................................... 19

5.1 Cost-Effective Ways To Implement Arc Fault Detectors on Larger Inverters.............................. 19

6 Closing Remarks ................................................................................................................................ 21

References................................................................................................................................................. 22

Appendix: Cost Analysis.......................................................................................................................... 23
vi

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List of Figures

Figure 1. Typical ground fault fuse holder.............................................................................................. 4

Figure 2. A 5-amp ground fault fuse ........................................................................................................ 5

Figure 3. PV array diagram with disconnects at source and output circuit combiners ...................... 6

Figure 4. Test setup showing a single monitor...................................................................................... 14

Figure 5. Single monitor setup ................................................................................................................ 15

Figure 6. Multiple monitor setup ............................................................................................................. 15

Figure 7. Multiple current transducers in PV output circuit combiner................................................ 17

Figure 8. Monitor in external enclosure.................................................................................................. 18

Figure 9. PV output circuit combiner equipped with residual current monitor.................................. 18

Figure 10. Single arc fault detector for the whole system.................................................................... 20

Figure 11. Multiple arc fault detector system......................................................................................... 20

List of Tables

Table 1. UL 1741 [6] Ground Fault Detection Specifications Versus Inverter DC Rating.................... 3
1

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1 Introduction

The primary audience for this guide includes field technicians who work on photovoltaic (PV)

systems of all sizes and generation capacities. The guide also provides an educational resource 

for all stakeholders involved in PV system ownership (owners, financiers, insurance providers, 

etc.) of potential hazards and the need for equipment retrofit to mitigate these hazards. Proper 

work practices while working on systems with and without direct current (dc) ground faults are 

critical for safety and to accurately diagnose system problems. Dc ground faults in PV arrays are 

among the most hazardous electrical problems that can occur in a PV array and should be 

approached carefully according to the best safety practices. PV systems, and especially ground 

faults, are hazardous because of lethal voltages; ground faults are also hazardous to property 

because they can start fires. All field and testing procedures recommended in this guide are 

intended for experienced field technicians who are qualified and authorized to perform the work. 

The definition of qualified personnel in Article 100 of the National Electrical Code (NEC) is, 

“One who has skills and knowledge related to the construction and operation of the electrical 

equipment and installations and has received safety training to recognize and avoid the hazards 

involved.” The definition of authorized personnel for the purpose of this guide is, “One who has 

been granted permission to work on the PV system by the system owner.”

This guide focuses on typical PV systems installed in the United States over the past 12 years. 

The distinguishing “typical” feature for this guide is that a typical system has a current-carrying 

conductor that is either solidly grounded with an unbroken grounding electrode conductor to a 

grounding electrode system or is functionally grounded through an overcurrent protection device

(OCPD) to a grounding electrode system. Grounding of exposed metal surfaces likely to become 

energized, also known as equipment grounding, is a requirement for all electrical systems 

governed by the NEC. Other system topologies have also been implemented in the United States 

over the past several years. These include non-isolated inverter designs, often referred to as 

transformerless inverters, such as those implemented by manufacturers such as Advanced 

Energy, KACO new energy, Power-One, and SMA America. Systems with these types of 

inverters have more comprehensive ground-fault detection systems than the grounded systems 

that make up the larger number of installed systems in the United States. Although the methods 

and tools shown in this guide can be used for non-isolated systems, the guide does not focus on

those systems.

This guide includes the following major sections:

• Section 2: Testing for Ground Faults deals with proper techniques to address ground 

faults in arrays having indicated ground faults. Ground fault detectors are located in 

nearly all currently manufactured PV inverters. 

• Section 3: Testing Photovoltaic Systems With No Known Ground Faults deals with 

proper techniques for testing arrays with no known ground faults. These techniques are 

similar to those in Section 2; however, additional equipment and methods may be needed

to detect faults that do not appear in typical ground fault detection systems. 

• Section 4: Retrofitting Existing Photovoltaic Systems With High-Resolution Ground 

Fault Detectors discusses mitigation methods, based on high-resolution detection of very 

low-level ground faults. These methods will likely obviate the need to perform the testing 
2

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required for systems with no known ground faults, because high resolution methods can 

detect virtually all ground faults. 

• Section 5: Retrofitting Existing Photovoltaic Systems With Arc Fault Detectors discusses

mitigation methods for detecting arc faults. The combination of high-resolution groundfault detection and arc-fault detection can effectively reduce the likelihood of fires caused 

by PV systems to levels comparable to or better than that of conventional alternating 

current (ac) electrical safety protection systems throughout the United States. 

By improving the safety of PV system wiring to levels consistent with, or better than 

conventional ac systems, the solar PV industry can confidently operate as part of the U.S. 

electrical industry knowing they maintain adequate electrical safety.
3

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2 Testing for Ground Faults

2.1 Testing Photovoltaic Systems With Indicated Ground Faults

Whenever a ground fault detector indicates a ground fault, field technicians must assume that 

conductors or equipment are damaged and need repair. Unless extensive field testing shows that 

no fault exists, the only safe assumption is that damage has occurred and there is an existing 

electrical hazard to the system and repair is required. False detections of ground faults are not 

unheard of, but are far fewer than properly detected faults. Intermittent ground faults are the 

most problematic to find, because testing may not resolve their location. In this case, field 

technicians may make the false assumption that no fault exists and give the system a clean bill of 

health, only to have the fault resurface later. These intermittent faults underline the need for fault 

detectors that are permanently installed and are highly sensitive so faults can be identified when 

they occur and be properly corrected.

A ground fault can result from a failure of the insulation that isolates current-carrying conductors 

from contact with grounded, conductive surfaces. For grounded systems, a ground fault will 

result in unintended current in the equipment grounding conductors and grounded equipment. 

This current depends on the voltage at the ground fault location and the impedance in the 

unintended circuit. Previously installed grounded systems with ground fault detectors in the 

inverter are required to detect ground faults of 1–5 amps, depending on the power rating of the 

inverter. Table 1 shows the specified maximum ground fault OCPD sizes based on inverter dc

rating.

Table 1. UL 1741 [6] Ground Fault Detection Specifications Versus Inverter DC Rating

Inverter DC 

Rating (kW)

Maximum Ground Fault 

OCPD Rating (Amps)

0–25 1

25–50 2

50–100 3

100–250 4

> 250 5

It is normal for PV systems to have small leakage currents flowing between the PV cells and 

ground. The magnitude of these currents depends on a variety of factors, including the size of the 

system, the amount of conductive surface in contact with circuits, the presence of conductive 

media (e.g., moisture), and damage to the integrity of the circuit. For PV arrays constructed with 

crystalline silicon modules, typical ground currents for properly operating residential systems are 

a few microamps; typical current flows for a 500-kW PV array are a few milliamps. Thin film 

array technologies may have leakage currents either less than or greater than those of crystalline 

array PV systems depending on their construction. Field technicians need to become familiar 

with the products that are being tested before they can assume that an abnormal ground current is 

flowing. Any ground currents exceeding those listed in Table 1 are abnormal and can be 

hazardous. However, a ground current as low as 100 mA can still indicate a severe fault on a 

grounded conductor. Since current standards may not require such low detection levels, better 

ground fault detection methods must therefore be retrofitted to many existing PV systems to 

prevent the potential for injury and property damage.
4

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2.1.1 Locating a Known Ground Fault

For a system with an indicated ground fault, the process of finding the ground fault can be quite 

simple, depending on whether the system has one series string as a source circuit or many source 

circuits. Large 500-kW inverter systems may have 10 or more combiner boxes—each with 10–

20 source circuits. A process of elimination must be used for these larger systems. If the fault 

cannot be found with the following procedure, the fault may be intermittent so Section 3 has 

procedures for testing systems with no obvious ground faults. 

2.1.1.1 Field Procedure

Tools include:

• Personal protective equipment (PPE) rated for maximum system voltage (hand, head, 

etc.)

• Other PPE as necessary (eye, fall, etc.)

• Screwdriver or combiner box key if applicable

• Dc clamp-on ammeter.

DC Voltmeter

• Electrical tape

• System drawings—source circuit wiring diagram, disconnect locations

• Recording device (pen and paper, laptop, or tablet).

2.1.1.2 Phase 1—Initial Testing

1. Record the information shown on the display of the inverter or 

ground fault detector.

2. Confirm that the information on the display is indicative of a 

ground fault as compared to specifications in the product manual.

3. Consult any available information on the data acquisition system 

to determine when the system shutdown occurred (if the system is 

shut down).

4. After recording all available information with the equipment 

active, follow the installation manual instructions to disconnect 

all power sources to the inverter or ground fault detector. Apply 

lock-out, tag-out procedures, using approved devices to open 

and secure all disconnecting means.

5. Allow at least 5 minutes for capacitors in the inverter to discharge (consult the inverter 

manual for minimum discharge time for capacitors).

Figure 1. Typical ground

fault fuse holder

CAUTION

Throughout this document, the term “no current” is used. Dc clamp-on ammeters may not 

measure accurately below a few hundred milliamps. Currents below 500 mA, while still 

being able to draw a brief arc, are not uncommon. 
5

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6. With proper PPE in place, test for voltage on the inverter side of the dc disconnect to 

ensure the inverter has no hazardous voltage.

7. Test for current on the grounding circuit used by the ground fault detector.

8. For ground fault detectors using circuit breakers, observe and record whether the breaker 

is in the closed, tripped, or open position.

2.1.1.3 Phase 2a—No Current in Grounding Circuit (with current, go to Phase 2b)

If the grounding circuit has no current, open the fuse holder (Figure 1) to the

ground fault fuse, or open the circuit breaker if the breaker is in the closed 

or tripped position. 

1. For ground fault detectors using fuses (Figure 2), remove the fuse 

and note whether the fuse is blown. NOTE: Some fuses have 

indicator pins that contact a circuit in the holder when blown, and 

some fuses may still show some continuity even after being blown. 

Review the manufacturer’s guidance on testing whether a fuse is 

good.

2. With the ground fault fuse holder or circuit breaker open, proceed 

to the first source circuit combiner box and start phase 3 of the 

testing (skip Phase 2b).

2.1.1.4 Phase 2b—Current in Grounding Circuit

1. If the grounded circuit has a current, record the current level.

2. When current is present, the source of the current must be located and disabled. For 

systems with multiple combiner boxes and dc disconnecting means, open all the dc 

disconnects prior to opening the PV output circuit combiner box disconnects (often called 

a recombiner), (see Figure 3). 

NOTE: This step will not eliminate the current flow to a fault, but it may reduce that 

current and it will prevent circulating currents that normally exist due to variations in the 

open circuit voltage (Voc) among combiner boxes in the array. (Safety Note: If no 

DANGER

Larger three-phase inverters that predate 2005 may not have an OCPD in the ground fault detector,

so large currents may be flowing.

DANGER

For safety while testing a resolving ground-faults in a PV array, the PV system ground bond must be 

opened to prevent circuit paths through the system ground bond.

Figure 2. A 5-amp 

ground fault fuse

CAUTION

Inverters with an OCPD in the ground fault detector may have a current in that device as high as the 

device rating.
6

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disconnects are installed between the PV source combiners and the PV output circuit 

combiner, this step is hazardous during daylight hours.) 

PV OUTPUT CIRCUIT COMBINER

F15

F1

EQUIPMENT GROUNDING CONDUCTOR

SOURCE COMBINER A

F2

CB

B

CB

J

FUSE A

FUSE B

FUSE J

G

G

G

INVERTER

 AC

DC

Figure 3. PV array diagram with disconnects at source and output circuit combiners

3. With all source circuit combiner and PV output circuit switches open, test the grounded 

conductor current at the PV output circuit combiner. The conductor with current on the 

grounded conductor that matches the current measured at the ground fault protector is the 

conductor with the fault. (Note: more than one circuit may have a grounded conductor 

fault, but this is highly unlikely.)

4. Proceed to the combiner box associated with the grounded conductor current and verify 

that the current is present in the combiner box’s grounded feeder (Phase 3).

2.1.1.5 Phase 3—Testing of Source Circuits at the Combiner Box 

1. At the selected source circuit combiner, test and record the ungrounded conductor current 

at each fuse holder (select the combiner in consecutive order if proceeding from Phase 2a 

or according to a faulted PV output circuit if proceeding from Phase 2b.)

2. Open all fuse holders in the combiner box connected to ungrounded conductors with 

current below 1 amp (usually only a few tenths of an amp in crystalline silicon arrays). 

a. NOTE 1: Small currents flow in source circuit combiners because each string has 

a slightly different Voc. The currents should be low and similar to one another. 

b. NOTE 2: If all fuses have current because of a faulted string, wait until ground 

fault is cleared before opening any fuse holders. The faulted string is generally the 

string with the most current. Open both ends of the faulted string using 

appropriate PPE including insulated gloves and any necessary tool to release the 

connector, unplugging the connectors with as rapid a motion as possible to 

prevent arcing from damaging the connector. Opening both ends should stop the 

flow of current to the fault. Once the current ceases and is verified with a clampon ammeter, open all the fuse holders in the source circuit combiner box.

3. Test each fuse, one at a time, by removing it from the holder, performing the 

manufacturer’s recommended continuity test, and then reinserting the good fuses into 

their respective open fuse holders (Do not close the fuse holder at this step—wait until

step 19).
7

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4. Note the string from which the fuse was removed and set aside any blown fuses. Blown 

fuses are a common indicator of a faulted string.

5. Test the grounded conductor current on each string in the combiner. A blown fuse may 

also be predictive of current in the grounded conductor caused by a ground fault.

6. Test and record the Voc of each string in the combiner box with the fuse holders open. 

The faulted circuit will have a lower Voc than the other circuits unless the ground fault is 

on the grounded conductor home run. 

a. NOTE: If the ground fault is on the grounded conductor, the fuse must be good 

for current to flow. If the fuse is blown and there is ground current, the Voc of the 

faulted string will be lower than that of the other source circuits. If the Voc is 

similar to the other strings, the fault may be intermittent.

7. Record the Voc of all the strings. Divide the voltage of one of the good strings by the 

number of modules in series to determine the module voltage (example: Voc = 480 V; 12 

modules in series; Voc per module = 480 V ÷ 12mod = 40 V/mod).

8. The modules in most PV source circuits are in series, so the ground fault location can be

based on the voltage of the faulted string (example: Vfaulted = 400 V; 400 V/40 V/mod = 

10 modules; fault location may be 10 modules back from the high voltage (output) side of 

the string).

9. Once the faulted circuit is identified, find its location in the array. Ideally, a circuit map 

will be available in the combiner box or on the as-built drawings, but often the circuits 

must be manually traced. A circuit with current can be found with the use of a dc clampon ammeter to clamp around various array conductors.

10. Once the faulted string in the array is identified, find each end. Use insulated gloves and 

any necessary, appropriate tool to release the connector, then unplug the connector with 

as rapid a motion as possible to minimize damage to the connector (if this was not done 

as part of step 1 in this phase). This should stop the flow of current (if any) to the fault.

11. Verify that any current on the grounded conductor is gone.

12. Examine the faulted string, module by module, starting at the estimated fault location 

(based on the measured voltage at the combiner box in step 7) until the fault is located.

13. Remove and replace the damaged module and/or repair the damaged conductors.

14. Verify that the damaged string has no solid voltage reading by testing the voltage at the 

combiner box for that string. (Note: if the circuit does not have a ground fault, the voltage 

reading will wander—particularly when the voltmeter is first connected to the circuit.)

15. Plug in the grounded conductor end of the string. Verify that no current is on the circuit 

and that the voltage on the string at the combiner box is consistent with all the other 

source circuit Voc readings in the combiner.

DANGER

Do not close the fuse holder at this step—wait until step 19
8

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16. Replace blown source circuit fuse if necessary (Do not close the fuse holder at this step—

wait until step 19).

17. Verify that the grounded feeder in the combiner box has no current. 

18. Verify that none of the grounded feeders in the PV output circuit combiner have current 

on them.

19. Close all the fuse holders and dc disconnects on the array side of the main dc disconnect 

at the inverter.

2.1.1.6 Phase 4—Final Verification and Startup

1. Verify that there is no solid voltage reading between the grounded conductor and the 

ground. (Note: if the circuit does not have a ground fault, the voltage reading will 

wander—particularly when the meter is first connected to the circuit.)

2. If the ground fault fuse is blown, place a replacement fuse back in the holder, and close 

the fuse holder. For circuit breaker systems, close the circuit breaker.

3. Verify that no current is flowing through the grounding conductor to the ground fault 

protector as measured with a dc clamp-on ammeter. A reading below 0.5 amps with a dc 

clamp-on ammeter is considered zero since these meters are not accurate at very low 

current levels. (Note: It is normal for less than 10 mA to flow without ground faults in a 

500-kW PV array.)

4. Begin the startup procedures for the inverter according to the manufacturer’s installation 

manual. This generally includes closing the ac breakers and disconnects before closing 

the dc disconnecting means.

5. Turn the system on and verify that there is no current on the equipment grounding 

conductor. (Note: it is normal for less than 10 mA to flow without ground faults in a 500-

kW PV array.)

DANGER

Do not close the fuse holder at this step—wait until step 19
9

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3 Testing Photovoltaic Systems With No Known 

Ground Faults

Electrical insulation testing is one of several ways to sense or predict the failure of conductors in 

a PV system. “Megger” testing, as insulation testing is often called, is a name brand of a product 

from a company that pioneered this particular type of testing. This product typically imposes a 

selectable voltage of 50–1500 Volts on conductors and equipment designed to operate at lowvoltage (1000 Volts or less). Conductor damage of any kind, whether caused by installation 

damage, thermal cycling of conductors and conduit, or overheating from poor connections may 

cause the conductor insulation to deteriorate. This damage can lead to small leakage current that 

is considerably greater than normal leakage from undamaged conductors. Insulation tests are 

often used during construction in system acceptance and commissioning procedures to detect 

damage during construction. These tests are not commonly used in maintenance and operation 

unless troubleshooting is required to find a ground fault. PV modules and 600-Volt rated wire

should be capable of being tested at 1000 V, because they must have passed certification tests at

twice the rated voltage plus 1000 V (600-V cable: Nationally Recognized Testing Laboratory 

required test is 600 V × 2 + 1000 V = 2200 V). Furthermore, the insulation testing is a short-term 

test and does not cause damage to the wire or module insulation. 

3.1 Insulation Testing Procedure

Before testing specific products and installations, including strings of modules, confirm that the 

testing (above rated voltage) will not void the warranties. Written permission should be obtained 

from the module manufacturer for testing procedures if they did not already provide approved 

insulation testing guidelines. Some manufacturers explicitly disallow insulation testing on their 

modules. Nevertheless, the most common locations of ground faults in PV systems are in the 

module wiring and modules.

Testing using the 500-V setting may be appropriate for some modules. When testing at a 500-V 

setting, any surge protection devices (SPDs) must be removed from the circuit to keep from 

damaging the SPD. These SPDs may be wired directly to the fused bus of the combiner box, may 

be wired to a tilt-out fuse holder, or may be a plug-in device. Lower testing voltages are 

necessary if the SPDs are not removed. Insulation testers are now available with 50-V settings 

that will not damage the SPDs. The added benefit of a low-voltage insulation test is that it can 

detect problems with SPDs. Leaking SPDs are common in older PV systems. 

Some expected resistance values are covered in the procedures; however, using a specific 

resistance threshold for insulation resistance testing often creates problems for field technicians. 

The key to insulation testing is to look for relative differences in resistance values rather than 

absolute values of resistance. Gathering data is simple with insulation resistance testing. 

Interpreting the data requires experience.

3.2 Field Procedure

Tools include:

• Insulation tester (with 50-V setting—e.g., Megger model MIT420, or MIT430 testers, or 

equivalent)
10

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• PPE rated for maximum system voltage (hand, head, etc.)

• Other PPE as necessary (eye, fall, etc.)

• Screwdriver or combiner box key if applicable

• Dc clamp-on ammeter

• Dc voltmeter

• Electrical tape

• System drawings—string wiring diagram, disconnect locations

• Recording device (pen and paper, laptop, or tablet).

3.2.1 Phase 5: Testing the Whole Array at the Photovoltaic Output Circuit 

Combiner

1. Perform Phase 1 testing.

2. Perform Phase 2a or Phase 2b testing depending on, respectively, whether or not current 

exists in the grounding circuit.

3. Record test conditions including ambient temperature and plane of array irradiance. 

(NOTE: temperature, irradiance, moisture, and wind can all affect resistance 

measurements.)

4. If testing at more than 50 V, remove any surge protection devices from the circuits being 

tested.

4. Remove voltage from the PV output circuit combiner fuses, if it is equipped with fuses. 

Remove PV output circuit combiner fuses or open PV output circuit combiner circuit 

breakers as equipped.

5. Check for current on the grounded PV output circuit conductors using a clamp-on current 

meter.

6. At the PV output circuit combiner, remove the grounded conductors one at a time from 

the grounded conductor busbar. Ensure the uninsulated end of the conductor does not 

touch anything. It is good practice to install a twist-on wire splice (wire nut) or to cover 

the exposed end with electrical tape to prevent unintended contact, as this conductor can 

have several hundred volts on it when not grounded. 

7. Set the insulation tester in a stable location. Attach the red lead to the red terminal on the 

tester. Attach the black lead to the black terminal on the tester.

DANGER

If no disconnects are available to de-energize PV output circuit combiner fuses, consider removing 

fuses at night. If fuses are removed while energized, confirm that NO CURRENT is on the fuse holder 

before opening it. For large PV systems (up to 500-kW per inverter), full electrical PPE, including arcfault suit is necessary to perform this fuse removal during daylight hours. This is due to the danger 

involved with removing energized fuses in a PV array.
11

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8. Set the meter to the lowest voltage setting—50 V if available.

9. For each circuit, attach the black (negative) lead from the tester to the ground busbar in 

the PV output circuit combiner. Attach the red (positive) lead from the tester to the 

negative conductor of the circuit under test.

10. Press and hold the “Test” button for a specific and consistent time interval—at least 15 

seconds and preferably 30–60 seconds. (NOTE: The product instruction manual for the 

tester may have a recommended time interval. Record the time interval used.)

11. Closely monitor the readings throughout the duration of each test and look for abnormal 

fluctuations. NOTE: At the beginning of each test, the insulation tester will generally 

display low resistance for a brief period as current flows into the circuit and voltage 

builds. The voltage and insulation resistance reading should build to a similar value for 

similar circuits when the circuits have no faults.

12. Record the result at the end of each timed interval. Insulation resistance measurements 

will vary based on system age, moisture, temperature, and the size of the circuit under 

test. Because absolute numbers vary based on these and other conditions, typically a PV 

output circuit conductor with a value greater than 100 kΩ is considered passing 

(reference readings taken during commissioning if available). Look for outliers. If one or 

more readings show a resistance that is 10% or less than “good” conductors, this may be 

an indication of a damaged conductor or module. 

13. Repeat the test for each output circuit until all output circuits are tested. 

a. If an output circuit fails the test, isolate the conductors from the source circuit 

combiner and test the insulation of the positive and negative source circuit home 

run conductors relative to the ground separately. Replace the faulted conductor 

and repeat steps 9-12.

b. If all source circuit home run conductors pass the test, the problem is in the source 

circuit combiner box associated with the PV output circuit registering low 

insulation resistance. Proceed to Phase 6.

3.2.2 Phase 6: Testing Subarray at Individual Source Circuit Combiners

Having completed the tests in Phase 5 proceed with the following steps.

1. Record test conditions, including ambient temperature and plane of array irradiance. 

2. If testing at more than 50 V, remove any surge protection devices from the circuits being 

tested.

3. After confirming that there is no current on each circuit, open all source circuit combiner 

fuses. 

4. At the source circuit combiner, remove grounded conductors one at a time from the 

grounded conductor busbar. Ensure the uninsulated ends of the conductors do not touch 

anything conductive. It is good practice to install a twist-on wire splice (wire nut) or to 

cover the exposed end with electrical tape to prevent unintended contact.

5. Set the insulation tester in a stable location. Attach the red lead to the red terminal on the 

tester. Attach the black lead to the black terminal on the tester.
12

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6. Set the meter to lowest voltage setting—50 V if available. 

7. For each circuit, attach the black (negative) lead from the tester to the ground busbar in 

the PV source circuit combiner. Attach the red (positive) lead from the tester to the 

negative conductor of the circuit under test.

8. Press and hold the “Test” button for a specific and consistent time interval—at least 15 

seconds (record the time interval used).

9. Closely monitor the readings throughout each test and look for fluctuations. NOTE: At 

the beginning of each test, the insulation tester will generally display low resistance for a 

brief period as current flows into the circuit and voltage builds. The voltage and 

insulation resistance reading should build to a similar value for similar circuits where the 

circuits have no faults.

10. Record the result at the end of each timed interval. Insulation resistance measurements 

will vary based on the system age, moisture, temperature, and the size of the source 

circuit under test. Because absolute numbers vary based on these and other conditions, 

typically a source circuit conductor, including PV modules, with a value greater than

1MΩ is considered passing (reference readings taken during commissioning if available). 

Look for outliers. If one or more readings show a resistance that is 10% or less than 

“good” conductors, this may be an indication of a damaged conductor or module. 

11. Repeat the test for each source circuit until all source circuits are tested. 

c. If a source circuit fails the test, isolate the conductors from the PV modules and 

test the insulation of the positive and negative source circuit home run conductors 

relative to the ground separately. Replace the faulted conductor and repeat steps 

7-10. 

d. If all source circuit home run conductors pass the test, the problem is in the PV 

modules or PV module wiring associated with the source circuit. Return to step 5 

of Phase 3 and complete the remaining Phase 3 tests.
13

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4 Retrofitting Existing Photovoltaic Systems With 

High-Resolution Ground Fault Detectors

This section provides guidance on recommended approaches for installing high-resolution 

ground current detectors that can be retrofitted to existing PV systems by qualified field 

personnel. This approach involves the permanent installation of high-resolution ground current 

detectors. These detectors are more sensitive than typical detection equipment required in a 

grounded PV system. Products are now available that accurately measure ground currents less 

than 10 mA. Previously, a PV system using a 800-kW inverter was required only to detect 

ground current above 5000 mA. However, current above 100 mA may indicate faulty conductor 

insulation on most 800-kW PV arrays. The 100 mA value is 1/50th of the previously required 

detection value for the inverter ground fault fuse or circuit breaker. In a 800-kW PV array, 

potentially dangerous faults will go undetected if the current does not exceed 5000 mA. The 

solution for more sensitive fault level detection is to install a high-resolution residual current 

monitor (RCM), also called a residual current detector. By installing permanent high-resolution 

RCMs, faulty insulation can then be detected as it occurs, allowing the damage to be repaired

long before it becomes a fire hazard. 

The baseline ground current of the system needs to be determined when the system is known to 

be functioning normally, ideally as part of the commissioning process. This information can be 

used to establish the appropriate RCM trigger setting. Data from Solar America Board for Codes 

and Standards research projects shows that a “normal” ground current value is unique to each 

system and depends on a variety of factors, including the inverter and the climate [4]. Solar 

America Board for Codes and Standards research also shows that sufficiently long data 

averaging can be employed to identify and differentiate storm-related transient currents from 

persistent ground fault currents [4].

The setting of an RCM requires an understanding of the above conditions. Most plant owners 

and operators are concerned about system operation and availability. One option is to respond to 

a current trigger by tripping an alarm rather than by shutting down the PV system. By using an 

alarm, a low threshold can be chosen for the RCM ground fault detection without incurring lost 

production from false alarms. This provides maximum protection against potential ground faults. 

When the alarm is triggered, the output of the RCM can be monitored to see if the reading was a 

legitimate fault, a transient fault, or a possible false alarm. Upon reviewing RCM triggers, and 

accounting for variables such as baseline ground current and storm-related transients, revised 

alarm threshold parameters can be established to prevent false alarms.

4.1 Installing a Residual Current Monitor on a Photovoltaic Array 

With a Large Inverter

This section describes the process to install and set an RCM at a large PV inverter. The product 

that will be discussed is made by Bender Corporation. Other products by other manufacturers 

may have similar specifications, accuracy, and field experience.
14

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The RCM discussed in this section uses solid-core, rather than split core, current transducers; 

thus, the inverter input circuit conductors must be removed from the inverter input so the 

corresponding pairs of circuit conductors can be run through the transducers. This may be most 

easily accomplished in the PV output circuit combiner. The largest transducer that Bender makes 

is 21 cm (8-1⁄4 in.) inner diameter. This is large enough for the output conductors of most PV 

output circuit combiners for 800-kW units. The output of a PV output circuit combiner might 

have six pairs of 750-kcmil, which would be less than 40% conduit fill in a 6-in. conduit. It 

would then be possible to run all conductors from that 800-kW unit through one of these 8-1⁄4 in. 

transducers. Figure 4 is a photo of an installed monitor, and Figure 5 shows a diagram of another 

method in which a single residual current detector could be installed on the output of a PV output 

circuit combiner.

Figure 4. Test setup showing a single monitor

If higher resolution measurements are desired, breaking the array into sets of one to three source 

circuit combiner feeders can be an attractive solution. Figure 6 shows where a transducer is 

placed around each source circuit combiner feeder circuit entering a PV output circuit combiner. 

A 800-kW PV system with 200-amp fuses installed in the PV output circuit combiner will have 

about 10–12 source circuit combiner circuits. The Bender RCMA460 can measure up to 12 

individual current transducer channels and provides a single alarm circuit. The array can be 

divided into 2, 3, 4, 6, or even 12 separate circuits. One advantage to this method is that the 

alarm threshold can be reduced to extremely low levels (less than 50 mA for most PV arrays) 

without concern about false alarms. Another advantage with multiple transducers is that they 

drastically reduce troubleshooting time by narrowing down fault location. This is especially 

helpful with intermittent faults, as data are time stamped and can be compared with other 

operating conditions such as weather. The Bender RCMA490 can provide 12 alarm circuits if it 

is deemed necessary to alarm or control separate circuits. One application of this alarm system 

would be to automatically open individual contactors associated with specific PV output circuits. 

By alarming an individual circuit and opening its contactor, a section of the PV array could be 

automatically isolated from the rest of the system if a fault were to occur.
15

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Figure 5. Single monitor setup

Figure 6. Multiple monitor setup

It is recommended that grounded PV systems have ground fault detection circuits capable of 

accurately measuring 100 mA of residual current and be set to detect no higher than 300 mA of 

residual current. By detecting residual currents in this low range, alarms can be monitored and 

service personnel dispatched in a timely manner long before a leakage current causes a 

catastrophic failure. Normal residual currents for 800-kW PV systems are less than 30 mA for 

most flat-plate PV systems that have been measured to date [4]. By incorporating moving 

averages into the measurements, current spikes caused by lightning or inverters turning on and 

off can be effectively smoothed so the monitor alarms only the higher residual current that is 

abnormal and indicative of faults.

4.1.1 Selecting and Installing the Appropriate Residual Current Monitor

The following is a set of decision steps for selecting and installing a Bender residual current 

monitor for PV systems up to 800 kW per inverter. Decision steps for other manufacturer’s 

equipment would follow steps similar to the following. 

PV OUTPUT

CIRCUIT COMBINER

F15

F1

COMBINER BOX A

F2

CB

B

CB

J

FUSE A

FUSE B

FUSE J

G

RCMS460

or

RCMS490

TO ALARM OR

TRIP

FUNCTION

G

INVERTER

 AC

DC

W60AB

(typical) EQUIPMENT GROUNDING CONDUCTOR

PV OUTPUT CIRCUIT COMBINER

F15

F1

EQUIPMENT GROUNDING CONDUCTOR

SOURCE COMBINER A

F2

CB

B

CB

J

FUSE A

FUSE B

FUSE J

G

G

RCMA420

or

RCMA423

TO ALARM OR

TRIP

FUNCTION

G

INVERTER

 AC

DC

W60AB

or

W210AB
16

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1. Decide whether a single measurement is sufficient or if multiple measurements are 

preferred.

a. Single—RCMA420 for up to 100 kW; RCMA423 for up to 800 kW

b. Multiple—RCMA460 for up to 12 inputs and one alarm; RCMA490 for up to 12 

inputs and 12 alarms

2. Select the current transducers necessary for method selected in step 1.

a. Single—W60AB for up to 100 kW (with RCMA420); W210AB for over 100 kW up 

to 500 kW (with RCMA423)

b. Multiple—W60AB per circuit up to 100 kW—need an AN420 power supply for 

every six transducers (with either RCMA460 with one alarm or RCMA490 for up to 

12 alarms)

3. Choose what the alarms will interface with in the PV system.

a. Alarm interface with real-time data system output to provide remote notification of a 

fault.

b. Shut down whole system—use the emergency stop or similar function in the inverter 

while providing remote notification of a fault.

c. Shut down individual circuits—operate shunt-trip breakers or contactors in the 

combiner boxes related to faulted circuits to interrupt only faulted circuits (this 

requires opening both the positive and negative conductors so the circuit is fully 

isolated from the remainder of the system). Provide remote notification of a fault 

(requires RCMA490).

4. Install equipment— it is important that wherever the transducers are installed the 

equipment certifications are properly maintained. Sensing circuits connected to the 

current transducers must be rated according to the highest voltage to which cables are 

exposed (usually 600 V or higher). Factory-installed conductors in certified electrical 

hardware will have their certification voided if conductors are disconnected and 

reconnected without a field certification. Therefore, it is best to install current transducers 

on field installed conductors so that factory certifications are not voided. All gridconnected inverters built after 2005 have built-in ground fault detectors that met the 

requirements of 2005 through 2011 NEC.

NOTE: The 2014 NEC has revised the language of section 690.5 requirements updating the 2011 

edition. The 2014 NEC version of 690.5 requires that ground fault devices detect and interrupt

ground faults on all conductors, including intentionally grounded conductors. An alarm circuit 

alone would not be sufficient to meet the 2014 NEC. The ground fault device would have to 

interface with something that interrupts the ground fault to meet the 2014 NEC. This interruption 

could be as simple as opening the connection to ground and shutting off the inverter, or it could 

be more elaborate and isolate the circuit with the ground fault while allowing the inverter to 

continue to operate.
17

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4.1.2 Additional Installation Notes

Figure 7 shows the installation of Bender current transducers in a PV output circuit combiner 

with 600-V rated conductors. The accompanying monitor is located in an external box on the 

inverter (Figure 8) so that the display can be viewed without shutting down the inverter or 

exposing the technician to energized conductors or busbars in the PV output circuit combiner. 

Figure 9 shows a new PV output circuit combiner product with the Bender components factory 

installed.

Figure 7. Multiple current transducers in 

PV output circuit combiner
18

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Figure 8. Monitor in external enclosure Figure 9. PV output circuit combiner equipped 

with residual current monitor
19

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5 Retrofitting Existing Photovoltaic Systems With Arc 

Fault Detectors

Another relevant known fire hazard that must be addressed for PV systems is series arc faults. 

Several PV system arc fault fires have occurred throughout the United States in the past several 

years, but very few have been widely publicized. Efforts are underway to have information 

released on these fires; however, this document focuses on how to mitigate the hazard rather than 

providing information on previous arc fault fire events. 

The most common type of arc faults are series arc faults caused by “failure of intended 

continuity”—as quoted from the 2011 NEC. The 2011 NEC, Article 690.11 requires arc fault 

detection on all PV systems operating above 80 volts and mounted on buildings. The 2014 NEC 

extends that requirement by removing the limitation of PV systems mounted on buildings so that 

ground-mounted systems must also have arc fault detection. 

A series arc fault refers to the situation where current continues to circulate even when an 

intentional connection becomes disconnected. This can occur when a module connector or a wire 

connected to a terminal in a combiner box becomes loose, or a solder joint separates in a module. 

If the circuit is carrying current when the connection begins to open, an arc can occur and remain 

for a long time. 

The biggest issue with mitigating arc faults today is that few products are available. As of early 

fall 2013, the only certified products available for the PV market containing arc fault detection 

were string inverters and a few battery charge controllers. Few certified products for 800-kW 

inverter PV systems are available. These products are designed for source circuit combiners, may 

not address PV output circuits, and have yet to see widespread use.

5.1 Cost-Effective Ways To Implement Arc Fault Detectors on Larger 

Inverters

Manufacturers of arc fault detectors are developing cost-effective products to address arc faults. 

The most cost-effective PV system designs should consider the overall installed cost, and be 

based on available, certified, reliable products. An important basic issue with arc fault detection 

is their signal-to-noise ratio. Detecting a one amp arc on a string may be challenging when the 

inverter is processing more than 1000 A of dc current. Ideally, inverter-level products will be 

developed that can detect arcs at this level. However, in the near term, products may be available 

sooner that operate at the string or source circuit combiner box level since the required current 

resolution is more manageable at the source circuit combiner box. Current product literature 

should be consulted for up to date specifications. 

Source circuit-level devices can provide very high resolution and pinpoint the location of a fault 

in a PV array; however, these may be too costly to implement on a 1000-kW PV array feeding an 

800-kW inverter. Combiner box devices are likely to be the first cost-effective products for 

central inverter PV system designs. These combiner box-level devices are currently being

implemented at the source circuit combiner box level rather than at the PV output circuit 

combiner box.
20

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Given the low likelihood of arc faults, it may be acceptable to use either the inverter shutdown or 

the source circuit combiner shutdown method with little difference in system availability. 

However, if nuisance tripping by the arc fault detector is a concern, one method to reduce its

impact is for the arc fault detector to trip only the circuit in which the arc was detected. Figures 

10 and 11 show two methods for implementing an arc fault detection system. As certified 

products become available, the options and costs can be refined to develop the best design to 

meet the NEC requirement. The two methods shown are remarkably similar to the RCM options 

discussed earlier. In fact, the location for arc fault devices is similar, if not the same as for 

RCMs. In the future, devices may be developed that perform both functions. Because the NEC 

requires that the arc fault detector interrupt the arcing current, the arc-fault device must be 

incorporated into a system that stops the flow of current on the arcing circuit.

PV OUTPUT CIRCUIT COMBINER

F15

F1

EQUIPMENT GROUNDING CONDUCTOR

SOURCE COMBINER A

F2

CB

B

CB

J

FUSE A

FUSE B

FUSE J

G

G

ARC FAULT

DETECTOR TO TRIP

FUNCTION

G

INVERTER

 AC

DC

Figure 10. Single arc fault detector for the whole system

Figure 11. Multiple arc fault detector system

PV OUTPUT

CIRCUIT COMBINER

F15

F1

COMBINER BOX A

F2

CB

B

CB

J

FUSE A

FUSE B

FUSE J

G

TO TRIP

FUNCTION

G

INVERTER

 AC

DC

EQUIPMENT GROUNDING CONDUCTOR

ARC FAULT

DETECTOR
21

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6 Closing Remarks

The ground fault blind spot results from the way most PV systems installed in the U.S. are 

grounded for safety. These system safety methods are generally different from the way safety is 

approached in other countries. The ground fault detection resolution methods can be improved in 

current systems to achieve similar levels as is implemented in non-U.S. PV system designs. 

Some inverter manufacturers selling to the U.S. market already offer upgrade options to factory 

install higher resolution ground fault detection systems.

Inverters used outside the United States generally operate non-isolated from the utility grid, with 

the dc PV array referenced to Earth through the utility ac connection, or isolated from the 

ground. In isolated ungrounded PV arrays, an isolation monitor operates continuously on the PV 

array, detecting and alarming failures of electrical insulation. These alternative system designs 

have superior ground fault detection systems and are beginning to be accepted in the U.S. design 

and construction community. As the electrical codes and standards that govern PV systems more 

explicitly accept these designs, the combination of these “new” designs and upgrades to existing 

ground fault detector designs will effectively eliminate the ground fault blind spot.

As higher current and higher resolution arc fault detection equipment becomes more readily 

available, system designers need to specify this equipment for their designs. As these products 

mature over the next few years, retrofit products will emerge that can cost-effectively address the 

ongoing concern about fires started by series arc faults in PV arrays. 
22

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References

1. B. Brooks. (2012). The Ground-Fault Protection Blind Spot: Safety Concern for Larger 

PV Systems in the U.S. Solar America Board for Codes and Standards.

http://www.solarabcs.org/about/publications/reports/blindspot/pdfs/BlindSpot.pdf. 

2. J. Flicker, J. Johnson. (2013). Photovoltaic Ground Fault and Blind Spot Electrical 

Simulations. Sandia National Laboratories Technical Report. 

http://energy.sandia.gov/wp/wp-content/gallery/uploads/SAND2013-3459-PhotovoltaicGround-Fault-and-Blind-Spot-Electrical-Simulations.pdf.

3. J. Flicker, J. Johnson. (2013). Analysis of Fuses for “Blind Spot” Ground Fault Detection 

in Photovoltaic Power Systems. Solar America Board for Codes and Standards. 

http://www.solarabcs.org/about/publications/reports/blindspot/pdfs/analysis_of_fusesJune-2013.pdf. 

4. G. Ball, B. Brooks, J. Johnson, J. Flicker, A. Rosenthal, J. Wiles, L. Sherwood, M. 

Albers, T. Zgonena (2013). Inverter Ground-Fault Detection “Blind Spot” and Mitigation 

Methods. Solar America Board for Codes and Standards. 

http://www.solarabcs.org/about/publications/reports/blindspot/pdfs/inverter_groundfault2013.pdf.

5. NFPA70, National Electrical Code 2011 edition, National Fire Protection Association, 

Quincy, MA, 2011.

6. UL1741, Inverters, Converters, Controllers and Interconnection System Equipment for 

Use With Distributed Energy Resources. Underwriters Laboratories. Northbrook, IL. 

2010.
23

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Appendix: Cost Analysis

The following are scenarios for PV systems of various sizes from 500–100 kWac. These 

scenarios illustrate example costs for installing RCMs for larger PV systems. Costs include the 

monitors, current transducers, and installation labor. In some cases, computer interface hardware 

may be necessary to connect to various data systems. The Bender monitors offer an analogue 4-

20-mA output that can be input directly into a data acquisition system that can translate that 

signal. 

Item Description Qty Cost/Item Cost

Bender RCMA423-D-2 Residual Current Monitor 1 $ 527.00 $ 527.00

Bender W210AB Current Transducer 1 $ 675.00 $ 675.00

$ -

$ -

$ -

Total Equipment Cost $ 1,202.00

Labor and Materials: $ -

Equipment x 1.0 $ 1,202.00

(range from 0.5 to 1.5) $ -

Total Cost $ 2,404.00

Total Cost/Wdc $ 0.004

Item Qty Cost/Item Cost

Bender RCMA423-D-2 Residual Current Monitor 1 $ 527.00 $ 527.00

Bender W210AB Current Transducer 1 $ 675.00 $ 675.00

Data System Interface Communication Device 1 $1,600 $ 1,600.00

$ -

$ -

Total Equipment Cost $ 2,802.00

Labor and Materials: $ -

Equipment x 1.5 $ 4,203.00

(range from 0.5 to 1.5) $ -

Total Cost $ 7,005.00

Total Cost/Wdc $ 0.012

Minimum Requirements

Scenario #1--500kWac/600kWdc PV System with 1 Transducer

Scenario #1a--500kWac/600kWdc PV System with 1 Transducer

Maximum Requirements
24

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Item Qty Cost/Item Cost

Bender RCMA460-D-2 Residual Current Monitor 1 $ 1,324.00 $ 1,324.00

Bender W120AB Current Transducer 3 $ 555.00 $ 1,665.00

Bender AN420-2 CT Power Supply 1 $ 215.00 $ 215.00

$ -

$ -

Total Equipment Cost $ 3,204.00

Labor and Materials: $ -

Equipment x 1.0 $ 3,204.00

(range from 0.5 to 1.5) $ -

Total Cost $ 6,408.00

Total Cost/Wdc $ 0.011

Item Qty Cost/Item Cost

Bender RCMA460-D-2 Residual Current Monitor 1 $ 1,324.00 $ 1,324.00

Bender W120AB Current Transducer 3 $ 555.00 $ 1,665.00

Bender AN420-2 CT Power Supply 1 $ 215.00 $ 215.00

Data System Interface Communication Device 1 $1,600 $ 1,600.00

$ -

Total Equipment Cost $ 4,804.00

Labor and Materials: $ -

Equipment x 1.5 $ 7,206.00

(range from 0.5 to 1.5) $ -

Total Cost $ 12,010.00

Total Cost/Wdc $ 0.020

Scenario #2--500kWac/600kWdc PV System with 3 Transducers

Minimum Requirements

Scenario #2a--500kWac/600kWdc PV System with 3 Transducers

Maximum Requirements

The cost per dc Watt is computed to help owners understand the relative cost of the upgrade 

relative to the system size. For scenario 1 with the 500-kW inverter, the lowest cost solution is a 

single current transducer with a single monitor. If no data system interface equipment is 

necessary, the total cost of the installation may be as low as $2,500, which equates to 

$0.004/kW. This configuration may not be possible if all the conductors cannot be routed 

through a single 210-mm diameter transducer. To bound costs on the upper end, scenario 3 for 

the 500-kW inverter system includes six current transducers, data system interface hardware, and 

installation costs on the high end. This results in a higher end cost of $0.022/W.
25

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Item Qty Cost/Item Cost

Bender RCMA460-D-2 Residual Current Monitor 1 $ 1,324.00 $ 1,324.00

Bender W60AB Current Transducer 6 $ 338.00 $ 2,028.00

Bender AN420-2 CT Power Supply 1 $ 215.00 $ 215.00

$ -

$ -

Total Equipment Cost $ 3,567.00

Labor and Materials: $ -

Equipment x 1.0 $ 3,567.00

(range from 0.5 to 1.5) $ -

Total Cost $ 7,134.00

Total Cost/Wdc $ 0.012

Item Qty Cost/Item Cost

Bender RCMA460-D-2 Residual Current Monitor 1 $ 1,324.00 $ 1,324.00

Bender W60AB Current Transducer 6 $ 338.00 $ 2,028.00

Bender AN420-2 CT Power Supply 1 $ 215.00 $ 215.00

Data System Interface Communication Device 1 $1,600 $ 1,600.00

$ -

Total Equipment Cost $ 5,167.00

Labor and Materials: $ -

Equipment x 1.5 $ 7,750.50

(range from 0.5 to 1.5) $ -

Total Cost $ 12,917.50

Total Cost/Wdc $ 0.022

Scenario #3a--500kWac/600kWdc PV System with 6 Transducers

Maximum Requirements

Scenario #3--500kWac/600kWdc PV System with 6 Transducers

Minimum Requirements
26

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Item Description Qty Cost/Item Cost

Bender RCMA423-D-2 Residual Current Monitor 1 $ 527.00 $ 527.00

Bender W120AB Current Transducer 1 $ 555.00 $ 555.00

$ -

$ -

$ -

Total Equipment Cost $ 1,082.00

Labor and Materials: $ -

Equipment x 1.0 $ 1,082.00

(range from 0.5 to 1.5) $ -

Total Cost $ 2,164.00

Total Cost/Wdc $ 0.007

Item Qty Cost/Item Cost

Bender RCMA423-D-2 Residual Current Monitor 1 $ 527.00 $ 527.00

Bender W120AB Current Transducer 1 $ 555.00 $ 555.00

Data System Interface Communication Device 1 $1,600 $ 1,600.00

$ -

$ -

Total Equipment Cost $ 2,682.00

Labor and Materials: $ -

Equipment x 1.5 $ 4,023.00

(range from 0.5 to 1.5) $ -

Total Cost $ 6,705.00

Total Cost/Wdc $ 0.022

Scenario #1--250kWac/300kWdc PV System with 1 Transducer

Minimum Requirements

Scenario #1a--250kWac/300kWdc PV System with 1 Transducer

Maximum Requirements

The cost per dc Watt is computed for scenario 1 with the 250-kW inverter. The lowest cost 

solution is a single current transducer with a single monitor. If no data system interface 

equipment is necessary, the total cost of the installation may be as low as $2,200, which equates 

to $0.007/kW. This configuration may not be possible if all the conductors cannot be routed 

through a single 120-mm diameter transducer. To bound costs on the upper end, scenario 2a for 
27

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

the 250-kW inverter system includes three current transducers, data system interface hardware, 

and installation costs on the high end. This results in a higher end cost of $0.0035/W.

Item Qty Cost/Item Cost

Bender RCMA460-D-2 Residual Current Monitor 1 $ 1,324.00 $ 1,324.00

Bender W60AB Current Transducer 3 $ 338.00 $ 1,014.00

Bender AN420-2 CT Power Supply 1 $ 215.00 $ 215.00

$ -

$ -

Total Equipment Cost $ 2,553.00

Labor and Materials: $ -

Equipment x 1.0 $ 2,553.00

(range from 0.5 to 1.5) $ -

Total Cost $ 5,106.00

Total Cost/Wdc $ 0.017

Item Qty Cost/Item Cost

Bender RCMA460-D-2 Residual Current Monitor 1 $ 1,324.00 $ 1,324.00

Bender W60AB Current Transducer 3 $ 338.00 $ 1,014.00

Bender AN420-2 CT Power Supply 1 $ 215.00 $ 215.00

Data System Interface Communication Device 1 $1,600 $ 1,600.00

$ -

Total Equipment Cost $ 4,153.00

Labor and Materials: $ -

Equipment x 1.5 $ 6,229.50

(range from 0.5 to 1.5) $ -

Total Cost $ 10,382.50

Total Cost/Wdc $ 0.035

Scenario #2a--250kWac/300kWdc PV System with 3 Transducers

Maximum Requirements

Scenario #2--250kWac/300kWdc PV System with 3 Transducers

Minimum Requirements
28

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

Item Description Qty Cost/Item Cost

Bender RCMA423-D-2 Residual Current Monitor 1 $ 527.00 $ 527.00

Bender W60AB Current Transducer 1 $ 338.00 $ 338.00

$ -

$ -

$ -

Total Equipment Cost $ 865.00

Labor and Materials: $ -

Equipment x 1.0 $ 865.00

(range from 0.5 to 1.5) $ -

Total Cost $ 1,730.00

Total Cost/Wdc $ 0.014

Item Qty Cost/Item Cost

Bender RCMA423-D-2 Residual Current Monitor 1 $ 527.00 $ 527.00

Bender W60AB Current Transducer 1 $ 338.00 $ 338.00

Data System Interface Communication Device 1 $1,600 $ 1,600.00

$ -

$ -

Total Equipment Cost $ 2,465.00

Labor and Materials: $ -

Equipment x 1.5 $ 3,697.50

(range from 0.5 to 1.5) $ -

Total Cost $ 6,162.50

Total Cost/Wdc $ 0.049

Scenario #1--100kWac/125kWdc PV System with 1 Transducer

Minimum Requirements

Scenario #1a--100kWac/125kWdc PV System with 1 Transducer

Maximum Requirements

The cost per dc Watt for scenario 1 with the 100-kW inverter. The lowest cost solution is a single 

current transducer with a single monitor. If no data system interface equipment is necessary, the 

total cost of the installation may be as low as $1,750, which equates to $0.014/kW. This 

configuration may not be possible if all the conductors cannot be routed through a single 60-mm 

diameter transducer. To bound costs on the upper end, scenario 1a for the 500-kW inverter 

system still includes one current transducer, data system interface hardware, and installation 

costs on the high end. This results in a higher end cost of $0.049/W. To summarize, the cost of 

implementing high-resolution RCMs into PV systems of 500- to 100-kW inverter size is 

approximately $0.004/kWdc to $0.049/kWdc.