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The Southwest Technology Development Institute web site maintains a PV Systems Inspector/Installer Checklist and all copies of the previous “Perspectives on PV” articles for easy downloading. A color copy of the latest version (1.93) of the 150-page, Photovoltaic Power Systems and the 2005 National Electrical Code: Suggested Practices, written by the author, may be downloaded from this web site:


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Updates: Grounding PV Systems and Fine Stranded Conductors

Posted By John Wiles, Friday, July 01, 2005
Updated: Tuesday, January 22, 2013


In the "Perspectives on PV” article in the September-October 2004 issue of the IAEI News, the subject of grounding PV systems was covered in some detail. In the March-April 2005, IAEI News, we discussed the changes to Article 690 that appear in the 2005 National Electrical Code. As normally happens over the three-year code development cycle, new thoughts and ideas come to the forefront about how things should be done. Here are some of those thoughts as they apply to grounding smaller PV systems with single inverters sized below about 10 kW. Figure 1 shows the dc grounding for a PV system as spelled out in Section 690.47 of NEC-2005 and as described in the above-mentioned article. Inspector Russ Coombs of Bakersfield, California, suggested that if the ac ground rod cannot be found, then the dc grounding electrode conductor might be spliced (irreversibly) to the ac grounding electrode conductor. I think this is a good suggestion because in many older buildings, the ac grounding electrode is buried in non-accessible locations.

PV system designers, PV integrators and installers are always looking for ways to meet the code safety requirements, install the system at the lowest cost, and make the system look good. The grounding system shown in figure 2 has been proposed as an alternate grounding system to meet most of the NEC requirements for grounding these systems. There is no dc grounding electrode (ground rod) located at the inverter. An unspliced 8 AWG (if allowed, based on the type of existing ac grounding electrode) bare or insulated conductor (marked green) is routed from a grounding terminal in the inverter along with the ac inverter output circuit conductors to and through (no stopping) to the ac ground rod. In this example, the 8 AWG conductor serves as both the dc grounding electrode conductor (unspliced, minimum size) and the ac equipment-grounding conductor. It should be noted that all grounding terminals and lugs (equipment-grounding and grounding electrode conductor) are electrically connected together in the inverter and may generally be used interchangeably depending on the size of the conductors they will accept.

Figure 1. Shows the dc grounding for a PV system as spelled out in Section 690.47 of NEC-2005 and as described in the above-mentioned article.


Figure 2. This grounding system has been proposed as an alternate grounding system to meet most of the NEC requirements for grounding these systems.

This method only works on the smaller string inverters where the ac equipment grounding conductor is 8 AWG or less and the ac grounding electrode is not something like a UFER (concrete-encased electrode) that may require a 4 AWG grounding electrode conductor. It is usually not appropriate for the 10 kW and larger three-phase inverters.

Multiple, Small String Inverters

Where multiple small inverters are installed in a single location, it is probably best to install a 6 AWG (if allowed based on the type of grounding electrode) bare, grounding electrode conductor from the first inverter in the set to a dc grounding electrode, which is then bonded to the ac grounding electrode. As allowed by NEC-2005, this dc grounding electrode conductor may also be routed and connected directly to the ac grounding electrode. If the ac ground rod cannot be found, then this conductor might be spliced (irreversibly) to the ac grounding electrode conductor. This dc grounding electrode conductor is routed beneath each of the other inverters in the set. A short, 6 AWG grounding electrode conductor is connected to a grounding terminal in each of the other inverters and then irreversibly spliced to the dc grounding electrode conductor running beneath each inverter (see figure 3). In this manner, only one dc grounding electrode conductor is required for the entire set. This is similar to the way multiple service disconnects are grounded in an apartment complex as shown in Exhibit 250.28 in the 2002 NEC Handbook.

Figure 3. Grounding multiple small inverters

Lightning Surge Protection

PV installers should note that the single-inverter grounding method runs the dc negative grounding system and the dc equipment-grounding conductors all the way back to the ac grounding electrode along with the ac output conductors from the inverter. Lightning induced surges may also travel this path and this may increase the possibility of lightning-induced surge damage to the PV equipment with this method of grounding the dc systems. Placing a dc grounding electrode at the inverter (bonded to the ac grounding electrode) may help to reduce surge damage. Also adding supplementary equipment grounding electrodes for the PV array mounting racks/module frames as shown in figures 1 and 2 and not bonding them to other grounding electrodes may reduce the potential for lightning damage (see NEC, 250.54).

Fine Stranded Cables

Since the Perspectives on PV article on fine stranded cables was published in the January-February issue of the IAEI News, I have received calls from people in other industries about connections failing where fine stranded cables have been used improperly. These failures have been associated with electric vehicle power cables, motor connections, and a few other high-current applications. At Underwriters Laboratories, the principal engineer for Distributed Energy Resources Equipment and Systems is going to process a bulletin and UL 1741 (PV Inverters and Charge Controllers) revision to clarify the use of appropriate connectors and terminals with fine stranded conductors.
Photo 1. Residential PV Installation

If you are in another industry that uses these conductors and associated connectors improperly, or you inspect such equipment, notifying UL might get some additional corrective actions taken. Inspectors can contact UL and file a field report at the following UL web site: ( Others can file a report to UL at this site: ( I can supply a PDF of the original article, if needed.

Germany Does It Right

I spent ten days in Germany in early March visiting PV equipment manufacturers, looking at PV installations (photo 1) and touring residential construction projects (photo 2). I was pleasantly surprised to find that trained electricians are installing most PV systems in Germany. Germany is second only to Japan in the number of PV installations.

Photo 2. PV system being installed

The electricians that I talked with were familiar with the use of fine stranded conductors and the equipment-production facilities I visited used them regularly. All locations had a wide range of crimp-on wire-end ferrules and sleeves available, and they also had the proper crimping tools for placing these devices on fine stranded cables before inserting them into terminals. Even the building supply stores (equivalent to Home Depot and Lowes) had these ferrules readily available (photo 3).

Photo 3. Ferrules on the shelf

I discovered that the typical residential and commercial wiring in Germany is accomplished with a jacketed, sheathed, three-four conductor cable where each of the main conductors consists of flexible, fine stranded wires (photo 4). These types of cables have been used for decades. Where our type NM cables typically have solid conductors up to 10 AWG, the German equivalents use fine stranded flexible conductors. The German electric dryer and range cords use fine stranding like ours do, but theirs have ferrules attached (photo 5).

Photo 4. Fine stranded cables used for residential wiring

Photo 5. Ferrules installed on dryer cord

It appears that the lack of familiarity with the proper use of fine-stranded cables here in the U.S. can possibly be traced to the fact that the typical electrician (and home owner) rarely deals with these cables. In Germany, where these cables are used daily, everyone seems to know how to properly install them. I wish we could import that knowledge base to the U.S. (along with the excellent German rail system).

For Additional Information

If this article has raised questions, do not hesitate to contact the author by phone or e-mail.; Phone: 505-646-6105

1 A PV Systems Inspector/Installer Checklist will be sent via e-mail to those requesting it. A draft copy of the 143-page, 2005 edition of the Photovoltaic Power Systems and the National Electrical Code: Suggested Practices, published by Sandia National Laboratories and written by the author, may be downloaded from this web site ( The Southwest Technology Development web site ( maintains all copies of the "Code Corner Columns” written by the author and published in Home Power Magazine over the last ten years. Copies of previous "Perspectives on PV” are also available on this web site.

The author makes 6–8 hour presentations on "PV Systems and the NEC” to groups of 40 or more inspectors, electricians, electrical contractors, and PV professionals for a very nominal cost on an as-requested basis.

Read more by John Wiles

Tags:  Featured  July-August 2005  Perspectives on PV 

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Permitting or Inspecting a PV System?

Posted By John Wiles, Sunday, May 01, 2005
Updated: Tuesday, January 22, 2013

Inspectors are more and more frequently faced with permitting or inspecting PV systems as these systems proliferate throughout the country due to increasing regional financial incentive programs. Photovoltaic power is a relatively young technology and industry. While well-qualified people are installing many excellent, code-compliant PV systems, others are designing and installing these systems with little or no prior experience with electrical systems. Unfortunately, as financial incentives continue and even increase, more unqualified people are installing these systems. The electrical inspector, through the permitting and inspection process, can help the PV industry focus on the design and installation of safe, code-compliant PV systems. Inspector involvement early in the process often proves beneficial to all.

Photo 1. Double lugging and worse are common in PV installations

The information below will help the inspector determine if the basic design of a PV system meets the specific requirements of the National Electrical Code as outlined in Article 690 and in other sections of the Code. Additional information will be provided to highlight areas that should receive special attention during the inspection. Inspectors need to be at least as well informed, if not better informed, than the designers and installers of these systems.

The Permit

As a part-time inspector and plan reviewer (for utility companies and municipalities who require code-compliant PV systems), I always require that the vendor/installer provide a neat, legible system diagram, a list of the conductors and parts used (with model numbers), and the calculations used for conductor and conduit sizing and overcurrent device rating. Although I don’t require engineering drawings, or even CAD drawings, unreadable, messy scribbles on the backs of envelopes are rejected. Since both inspectors and installers have not done thousands of PV systems, the inspector should accept nothing less.

Conductor Types

Module junction box temperatures may be 30–35°C higher than ambient temperatures, and 75–80°C temperatures are not uncommon. The conductor types selected for connection to the PV modules should be rated for wet, 90°C conditions. In conduit, these are normally THHN/THWN-2 or RHW-2 types. If in free air, as allowed by the Code, the conductors most commonly used are USE-2, and if these are to be also run in conduit, they should be USE-2/RHW-2—particularly if the conduit is inside the building. [See "Perspectives on PV" in the July/August 2004 issue of the IAEI News for more information.]

Photo 2. Improper color codes and exposed, energized bus bars

Conductors in outside conduits or in PV combiners or junction boxes exposed to the sun may be operating at 17°C or higher than the ambient temperature [see the fine print note No. 2 in Section 310.10 in the 2005 NEC]. In PV systems we suggest adding 20°C to the ambient temperature to accommodate the temperature rise in aging, dull-colored conduits. Again, this usually dictates the use of wet rated conductors with temperature ratings of 90°C, although some installations in cold climates might squeeze by with 75°C insulated conductors.

Currents, Cables, and Overcurrent Devices

The process for calculating cable sizes for PV systems in the Code is somewhat complex, particularly when conditions of use are applied that include temperature deratings and conduit fill as well as the temperature limitations of the terminals of overcurrent devices. See Appendix I of the author’s PV Power Systems and the National Electrical Code: Suggested Practices (available free as a download—see endnote1). A slightly abbreviated version is presented here.

Photo 3. Grounded conductor improperly switched

Due to the unique characteristics of solar energy and PV modules, worst-case currents are always used and are considered continuous [see ""Perspectives on PV"" in the July/August 2004 IAEI News]. In any PV source circuit (one module or a series connected string of modules) the individual module short-circuit current (Isc) is multiplied by 1.56 to get the basic conductor ampacity rating (at 30°C) and the overcurrent device (where required) to protect this conductor and the internal module conductors. Temperature correction factors, for the conductors connected to the modules, of either 65°C (cooling air to the back of the modules—4 inches or more of space) or 75°C (no cooling air—less than 4 inches of space) are applied to the 30°C ampacity.

Overcurrent devices (where required) are installed electrically and physically away from the modules in combiner circuit boxes where the PV source circuits are combined in parallel. If the combiner boxes are exposed to sunlight and ambient temperatures over 40°C (104°F), then it is likely that the overcurrent devices will be exposed to temperatures in excess of their normal 40°C maximum. In practice, a 10–15 percent derating should be applied to the overcurrent device rating and then it should be verified that it would still protect the conductor.

When dealing with temperature deratings on 90°C conductors connected to overcurrent devices with terminals rated for conductors operating at no more that 75°C or possibly even 60°C, that 1.56 x Isc calculated current must be below the 75°C (or 60°C) ampacity values for the conductor size being used [see 110.14(C)].

When PV module source circuits are paralleled in PV combiners, then the short-circuit currents of the paralleled circuits sum together, and new conductors and overcurrent devices must be selected to handle the increased currents.

The voltage rating of conductors, overcurrent devices, and disconnects must be based on the maximum system voltage, which is the sum of the open-circuit voltage (Voc) of all modules connected in series times a temperature dependent factor found in NEC Table 690.7. A factor of 1.25 can be used for any system that is installed in locations where the record low temperature is no lower than -40°C (-40°F).


On utility-interactive PV systems, disconnects are generally required for the main PV circuit input to the inverter and the inverter ac output (which may be a backfed breaker in a load center). The addition of batteries in some systems will necessitate additional disconnects. Most utilities require an outside, visible blade, lockable disconnect between the ac output of a PV system and the point where that output connects to the utility. While not a Code requirement, it must be installed in a code-compliant manner.

The disconnect must have a rating of 1.56 Isc at that point, and must have a voltage rating and be connected in a manner consistent with the maximum system voltage.

Inverter AC Outputs

The ac output circuits from an inverter should be sized and protected at 125 percent of the rated steady-state output currents even when the connected PV array will never produce currents at or near that level. One never knows how many additional PV modules may be connected in the future.

Photo 4. Improperly grounded enclosure violates 250.8

The connection to the utility must meet the requirements of NEC 690.64(B)(2). In residential systems, this section of the Code will allow a relatively small PV system to backfeed the residential load center. In commercial systems, either the size of the load center must be adjusted or a second service entrance must be added to accommodate the PV system.

The Inspection

Good workmanship

For some reason, even experienced electricians frequently forget to use good workmanship when installing PV systems. In all cases, conduit should be fastened to structures for protection against wind and ice loading. Modules and mounting racks as well as other equipment should be firmly mounted to structures in a manner that will resist environmental stresses of sunlight, wind, and rain at the very least. Areas of the country subject to earthquakes or hurricanes will require specialized, more rugged installations.

Double lugging and worse are common in PV installations (see photo 1 for an example).


Grounded conductors, both ac (neutral) and dc (negative), should be white or marked white and should never be interrupted by a switch pole, fuse, or circuit breaker —particularly on dc source circuits from the PV modules (see photos 2 and 3).

Grounding of module frames, combiner enclosures and disconnects in the dc circuits is important because they may operate up to 600 volts in commonly installed systems. No sheet metal or "”tech”" screws should be used to ground disconnect enclosures with tin-plated aluminum lugs; proper grounding/ground bar kits should be used (see photo 4). [See "Perspectives on PV" in the September/October 2004 issue of the IAEI News for more details on grounding PV modules.]

When metal conduit has been used, proper bonding of the conduit to the enclosures should be verified, particularly when the dc PV voltages are above 250 volts.

Photo 5. Fine stranded cable, improperly terminated

The ac portion of most PV systems should have only one neutral-to-ground bond, and that bond will frequently be in the ac load center for the system. Since the inverter uses a transformer that isolates the dc grounded conductor from the ac grounded conductor, the dc negative should also have a single bond to ground. Many utility-interactive inverters make this dc bond internally and there should be a separate dc grounding electrode conductor routed to either a dc grounding system or to the ac grounding system. Any roof top PV system on a dwelling should have a Section 690.5 ground-fault protection system and these may be either external to the inverter or built in. The grounding electrode conductor will be connected to this device when it is external to the inverter.

Overcurrent Protection

Overcurrent devices in disconnect enclosures and PV combiners located in readily accessible locations that have exposed internal circuits should be accessible only by qualified persons. If these devices have exposed internal terminals and/or bus bars that could be energized when opened, the covers should require at least a tool for access. Although not required (yet) by the Code or UL Standards, these devices would benefit from a warning label—on the outside: "”Warning: Electric Shock—No User Serviceable Parts Inside”" (see photo 2).


The location of the main PV disconnect must comply with 690.14, and unless the PV source circuit conductors are installed in metallic raceways, they must remain outside the structure until that first, readily accessible disconnect is reached (see 690.31(E) in the 2005 Code). Although the NEC allows this disconnect to be either outside the structure or immediately inside the structure at the point of first penetration, the PV disconnect is normally mounted in the same manner as the ac service disconnect for the particular jurisdiction.

On the system with batteries and larger systems that use larger conductors (e.g., 2/0 AWG and above), the inspector should verify that fine stranded cables (where used) are properly terminated with connectors and terminals listed for use with such cables (see photo 5).


Photovoltaic power systems have the potential to produce significant amounts of energy for many years. The well-informed inspector can make a significant contribution to the safety, quality, durability, and even performance of these systems. Compliance with the requirements of the NEC and the recognition that the Code gives minimum requirements should result in a safe, durable system, particularly if these minimums are exceeded. A well-qualified team that includes the designer, installer and the inspector will help ensure that these systems remain safe for their entire life.

For Additional Information
If this article has raised questions, do not hesitate to contact the author by phone or e-mail. E-mail: Phone: 505-646-6105.

1 A PV Systems Inspector/Installer Checklist will be sent via e-mail to those requesting it. A draft copy of the 143-page, 2005 edition of the Photovoltaic Power Systems and the National Electrical Code: Suggested Practices, published by Sandia National Laboratories and written by the author, may be downloaded from this web site ( The Southwest Technology Development web site ( maintains all copies of the "”Code Corner Columns”" written by the author and published in Home Power Magazine over the last ten years. Copies of previous "”Perspectives on PV”" are also available on this web site.

The author makes 6–8 hour presentations on "”PV Systems and the NEC”" to groups of 40 or more inspectors, electricians, electrical contractors, and PV professionals for a very nominal cost on an as-requested basis.

Read more by John Wiles

Tags:  Featured  May-June 2005  Perspectives on PV 

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Photovoltaic Power Systems and 2005 NEC

Posted By John Wiles, Tuesday, March 01, 2005
Updated: Tuesday, January 22, 2013

The 2005 NEC has been published and Article 690 has some changes that will benefit the Photovoltaic (PV) Power Industry and electrical inspectors by making theCodeeasier to understand and by allowing modified installation procedures. As jurisdictions adopt the Code (some as early as January 1, 2005—others possibly not for years), the new requirements may be applied. These requirements and other significant changes will be covered in this article.

Optional Inverter Locations

The intent of the 2002 NEC was to have utility-interactive inverters mounted in readily accessible locations. However, these devices are relatively robust, require little maintenance, and generally are constructed with outdoor enclosures. Section 690.14(D), new to the 2005 NEC, allows utility-interactive inverters to be mounted in areas that are not readily accessible. A readily accessible area is one that can be approached without opening a locked door, removing building materials, or using a ladder or other device to reach the location. In the 2005 Code, utility-interactive inverters may now be mounted on the roof of a building near the PV array. However, dc and ac disconnects must be located at the inverter and an additional ac disconnect must be located in a readily accessible location as required by 690.14(A)–(C), usually at ground level. These disconnects are Code requirements and may not satisfy any utility requirements for a readily accessible, visible-blade, lockable ac disconnect for the PV system. These disconnect requirements were covered in the article on PV systems in the March/April 2004 issue of the IAEI News.

PV Source and Output Conductors Allowed Inside the Building

Section 690.14 generally requires that PV source and output conductors remain outside a building until they reach a readily accessible disconnect at the point of first penetration. Section 690.31(E) now permits conductors from the PV array on the roof of a building to be run inside the building before reaching the first readily accessible disconnect if those conductors are installed in metallic raceways. Metallic raceways would include the various types of rigid metal conduit and flexible metal conduits. Non-metallic raceways (PVC) are not allowed by this provision because they do not provide the physical protection, fire containment or ground-fault detection afforded by metallic raceways. Now, the PV installer can legally hide the conductors from the roof inside the building without running unsightly conduits down the outside of the structure as was required in the 2002 Code. While Section 690.14(A and B) read the same in the 2005 NEC as they did in the 2002 Code, an exception addressing 690.31(E) has been added to 690.14(C)(1) to address the allowance for metallic raceways inside the building. If metallic raceways are not used, then the PV source and output circuits must remain outside the building until they reach the readily accessible disconnect at the point of first penetration.

Ungrounded PV Systems Now Permitted

Section 690.35 was added to permit the use of ungrounded PV arrays where neither of the circuit conductors is grounded as is currently required for systems operating over 12 volts nominal. This permissive (not mandatory) requirement was added to the Code to allow utility-interactive inverters to be used that have no internal or external isolation transformer. Without a transformer, the inverter efficiency can be increased while the weight and cost can be reduced. The equipment grounding system still must be present and there are several other requirements that will help to ensure that these ungrounded systems are as safe as the grounded systems. These additional requirements for ungrounded systems are loosely based on PV design and installation practices used in Europe where the Europeans have had far more experience with ungrounded power systems than we have had in the United States.

  1. Disconnects and overcurrent protection will be required in both of the now-ungrounded conductors.
  2. A ground-fault protection device will be required on all ungrounded PV systems even when the PV array is not mounted on the roof of dwellings where such a device is currently required (see 690.5).
  3. The conductors from the PV array will be installed in raceways (conduit) or be part of a multi-conductor sheathed cable. This requirement is to duplicate the protection provided by a double-insulated cable that is not presently available in the US. Underwriters Laboratories (UL) is developing a new standard for double-insulated cables, and such cables are being designed for use with PV modules. Until such cables are available, the current use of modules with single-conductor pigtail wiring and MultiContact® connectors will not be allowed on ungrounded PV arrays.
  4. Because many people think that ungrounded PV systems are inherently safer than grounded systems, a warning label will be required at all points where the ungrounded conductors are terminated. Labels with the following warning will have to be attached by the installer at points like junction boxes and disconnects where the conductors are attached to terminals that may require service.

Electric shock hazard. The direct current circuit conductors of this photovoltaic power system are ungrounded but may be energized with respect to ground due to leakage paths and/or ground faults.

5. Inverters or charge controllers used in ungrounded systems must be specifically listed for that purpose by Underwriters Laboratories or other acceptable testing and listing agencies like ETL or CSA.

Installers and inspectors should note that most of the currently-available PV equipment intended for use on 12 to 48-volt PV systems is designed to be used only on grounded PV systems and would generally not meet the requirements listed above for ungrounded PV systems. This equipment frequently has overcurrent devices and disconnects installed in only one of the current-carrying conductors and the other current-carrying conductors are frequently connected to a common bus without overcurrent protection. Also, most 12 to 48-volt PV systems will continue to use inverters that have transformers to obtain the necessary 120-volt ac output voltage from the lower dc input voltage.

Grounding System Clarifications

Section 690.47(C) clarifies the requirements for grounding systems that have both ac and dc grounding requirements. Typically, all PV systems with inverters must have both the ac and the dc side of the system grounded since the internal transformer in the inverter isolates the dc grounded conductor from the ac grounded conductor. The inverter essentially creates a separately derived dc system when this isolation is considered. Normally the ac part of the PV system is grounded at the ac service disconnect (utility-interactive systems) or the ac load center (stand-alone systems) and is accomplished by the existing ac system. The Code allows the dc grounding electrode conductor to be routed to one or two locations: (1) to a dc grounding electrode which then must be bonded to the ac grounding electrode, or (2) directly to the ac grounding electrode where it is connected to that electrode with a separate clamp. The size of the grounding electrode conductor is determined by 250.66 (ac) and 250.166 (dc), and a bonding conductor, when used, must be sized the larger of the two. See the "Perspectives on PV” in the September/October issue of the IAEI News for additional details on grounding.

Backfed Breakers May Not Need To Be Clamped

The addition of Section 690.64(B)(5) takes precedence over the code requirement [in Section 408.16(F)] that all backfed circuit breakers must be clamped to the internal busbar. This revision does not require that backfed circuit breakers be clamped to the internal load center busbar where they are connected to a listed utility-interactive inverter and where all circuit breakers in the panel are secured with a front panel. Installers (and inspectors) were having a great deal of difficulty in finding load centers that had provisions for clamping backfed breakers that were not in the main breaker position. Since a backfed breaker connected to a utility-interactive inverter immediately goes dead when unplugged, the dangers associated with such breakers connected to a rotating generator (which may stay energized) do not exist. Furthermore, if an unqualified person uses a "tool” to remove the cover from a load center (thereby allowing any breaker to be removed), the main lug or main breaker terminals and the exposed bus bars may present greater hazards than an unplugged backfed breaker.

Section 690.72(B)(2)(2) clarified the requirements of diversion loads in relation to diversion charge controllers in systems with batteries. The current rating of the load must be equal to or less than the current rating of the controller (a technical requirement), the voltage rating of the diversion load must be greater than the maximum battery voltage, and the diversion load must have a power rating of 150 percent of the power rating of the PV array. These modified requirements allow the PV system designer to properly specify a diversion load that is consistent with the requirements of the diversion load controller while maintaining the required safety margins for the system.


These are the major changes for the 2005NEC. It is unfortunate that some large PV markets, like California, will not immediately adopt the 2005 NEC. Inspectors in those regions are encouraged to review the changes in the Article 690 for 2005, and apply them judiciously where appropriate. I encourage all PV systems designers and installers to get a copy of the 2005 NEC and better yet the 2005 NEC Handbook that has significantly expanded comments on the intent of the Code requirements.

The PV Industry Forum has already started formulating proposals for the 2008 NEC and they must be finalized before the end of November 2005. Send me your comments and suggestions on PV safety for the 2008 NEC and I will ensure they get the thorough review they deserve.

Inspector comments and suggestions for changes to Article 690 are particularly welcome. The "best” PV systems (safest, most durable, most reliable, highest performing) have usually resulted from a close collaboration between the PV designer, the code–familiar installer, and the electrical inspector.

For Additional Information

If this article has raised questions, do not hesitate to contact the author by phone or e-mail. E-mail: Phone: 505-646-6105

A PV Systems Inspector/Installer Checklist will be sent via e-mail to those requesting it. A copy of the 100-page Photovoltaic Power Systems and the National Electrical Code: Suggested Practices, published by Sandia National Laboratories and written by the author, will be sent at no charge to those requesting a copy with their address by e-mail. The Southwest Technology Development web site ( maintains all copies of the "Code Corner Columns” written by the author and published in Home Power Magazine over the last ten years.

The author makes 6–8 hour presentations on "PV Systems and the NEC” to groups of 40 or more inspectors, electricians, electrical contractors, and PV professionals for a very nominal cost on an as-requested basis.

Read more by John Wiles

Tags:  Featured  March-April 2005  Perspectives on PV 

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Do You Know Where Your Cables Are Tonight?

Posted By John Wiles, Saturday, January 01, 2005
Updated: Tuesday, January 22, 2013

The use of fine stranded, flexible cables appears to be increasing each year. This is particularly true with relatively "young” industries like the photovoltaic (PV) industry, the fuel cell industry, and the uninterruptible power supply (UPS) industries. In many cases, technicians and installers in these fields prefer to use fine-stranded flexible cables in the larger sizes (1/0 AWG and up) due to the perceived easier installation of these cables compared to the more rigid conventional cables.

Photo 1 shows the differences between a typical standard Class B cable and a typical fine stranded cable (sometimes incorrectly known as diesel locomotive cable or welding cable). Both cables are 2/0 AWG (67.4 mm2). The THHN Class B cable on the left has 19 separate conductors, each with a diameter of 0.084 in. (2.13 mm). The THW fine stranded cable on the right has 1330 separate conductors, each with a diameter of 0.01 inch (0.25 mm).

Photo 1. The differences between a typical standard Class B cable and a typical fine stranded cable

Note that both types of cables are listed in NEC Table 310.13 as suitable for code-compliant installations. Cables marked with only the DLO (Diesel Locomotive) marking are not suitable for code-compliant installations, and listed welding cables are only to be used when attached to the secondary of welding machines under the requirements of NEC Article 630.

Photo 2. Examples of setscrew types of terminals

Also of note, based on the values in NEC Table 5, chapter 9, is the overall diameter of the 2/0 THHN cable at 0.532 in. (13.51 mm) compared with an overall diameter of 0.610 in. (15.49 mm) for the THW. The greater diameter of the fine stranded THW cable is mainly due to the thicker insulting jacket required for THW cables. This generally indicates that fewer THW cables will fit in a given size of conduit.

Reports (unfortunately, mostly anecdotal) have been received over the last several years about field-made connections in PV and UPS systems that have failed when flexible, fine-stranded cables have been used with mechanical terminals or lugs that use a set screw to hold the wire in the terminal.

Photo 3. Failed terminal and cable

These terminals are found on nearly all circuit breakers (except those with stud-type terminals), fuse holders, disconnects, PV inverters, charge controllers, power distribution blocks, some PV modules, and many other types of electrical equipment. Photo 2 shows examples of a few of these set screw types of terminals.

Fine-stranded conductors and cables are considered as those cables having stranding more numerous than Class B or C stranding. Class B stranding (the most common) will normally have 7 strands of wire per conductor in sizes 18-2 AWG, 19 strands in sizes 1-4/0 AWG, and 37 strands in sizes 250-500 kcmil. Conductors having more strands than these are widely available and are in different classes such as K and M used for portable power cords and welding cables. Commonly used building-wire conductors such as USE, THW, RHW, THHN and the like are most commonly available with Class B stranding but are also readily available (in some locations) with higher quantities of stranding. Fine-stranded cables are frequently used by PV installers to ease installation and are used in PV systems for battery cables, power conductors to large utility-interactive inverters and elsewhere.

Photo 4. Failed terminal

Some PV modules are supplied with fine-stranded interconnecting cables (14 AWG–10 AWG) with attached irreversible compression connectors. While these crimped-on connectors listed with the module are suitable for use with the fine-stranded conductors, an end-of-string conductor with mating connector may also be supplied with the fine-stranded conductor, and the unterminated end of that conductor will not be compatible with mechanical terminals.

According to Underwriters Laboratories (UL) Standard 486 A-B, a terminal/lug/connector must be listed and marked for use with conductors stranded in other than Class B and C. With no marking or factory literature/instructions to the contrary, the terminal may only be used with conductors with the most common Class B and C stranded conductors. These terminals and lugs are not suitable and should not be used with fine-stranded cables. UL engineers have said that few (if any) of the normal screw-type mechanical terminals that the PV industry commonly uses have been listed for use with fine stranded wires. The terminal must be marked or labeled specifically for use with fine-stranded conductors [see NEC 110.3(A) and (B)].

UL suggests two problems, both of which have been experienced in PV systems. First, the tightening screw tends to break the fine wire strands, reducing the amount of copper available to meet the listed ampacity. Second, the initial torque setting does not hold and the fine strands continue to compress (creep) after the initial tightening. Even after subsequent retorquing, the connection may still loosen. The loosening connection creates a higher-than-normal resistance connection that heats, loosens even further, and may eventually fail. A recent example of a failed mechanical terminal from a large PV system is shown in photos 3 and 4. The terminal had been torqued properly less than three months before the failure.

Over-tighten or Retighten?

Some installers over-tighten or retighten a connection to get fine stranded cable to hold in screw-type terminals. UL standards for connectors require that the terminal be tightened once to the specified torque and there is no retightening specified. Tightening the terminal beyond the specified torque value may cause binding of the threads thereby giving a false torque reading. Both over-tightening and retightening of listed connectors and terminals on overcurrent devices and other equipment would appear to violate the provisions of the listing and therefore be a violation of NEC Section 110.3(B).

Photo 5. A typical copper light-duty crimp-on lug that is not marked as being suitable for use with fine stranded cables.

A quick review of NFPA Standard 70B-2002, Recommended Practice for Electrical Equipment Maintenance, does not find any suggestions that electrical equipment terminals be periodically retorqued. The terminals are to be inspected and examined for signs of looseness or overheating and that situation should be corrected where found. There is a retorquing recommendation for mechanical fasteners on box covers and the like.


Electrical equipment listed to UL Standards has:

  • Terminals rated for the required current and sized to accept the proper conductors
  • Sufficient wire bending space to accommodate the Class B stranded conductors in a manner that meets the wire bending requirements of the NEC
  • Provisions to accept the appropriate conduit size for these conductors where conduit is required.

It is therefore unnecessary to use the fine-stranded cables except possibly when dealing with conductors 4/0 AWG and larger. Experienced electricians and electrical contractors routinely install the normal, relatively stiff Class B conductors without difficulty and use parallel-connected smaller conductors where very large conductors are required.

Photo 6. Lug - suitable for fine-stranded cable

In those cases where a fine-stranded cable must be used, a few manufacturers make a limited number of crimp-on compression lugs in various sizes that are suitable for use with fine-stranded cables. These lugs are attached to a stud on the device using a washer and nut. Most of the commonly used overcurrent devices (both circuit breakers and fuse holders/terminals) come with screw-type terminals so there is no stud available. Most of these special crimp-on lugs are solid copper or tinned solid copper. Photo 5 shows a typical copper light-duty crimp-on lug that is not marked as being suitable for use with fine stranded cables.

Factory-supplied markings and literature indicate which lugs are suitable. An example is the ILSCO FE series of lugs in sizes 2/0 AWG and larger (see photo 6). Burndy makes the YA-FX series of lugs in sizes 8 AWG and larger that have been listed for use with fine stranded cables. In both cases the lugs are solid copper. It should be emphasized: Most crimp-on lugs are not listed for use with fine-stranded wire. Where the crimp-on compression lugs can be used, they must be installed using the tools recommended by the manufacturer and, of course, they must be attached to a stud with a nut and washer.

Other terminal manufacturers also make pin adapters (a.k.a. pigtail adapters) that can be crimped on fine-stranded cables. These pin adapters provide a protruding pin (solid or stranded) that can be inserted into a standard screw-type mechanical connector. Again, not all pin adapters/pigtail adapters are listed for use with fine-stranded conductors; some are intended for use with aluminum wire and others provide only a conversion to a smaller AWG size for a B Class conductor.

It is suggested that the use of fine-stranded conductors be avoided wherever possible. Where such cables must be used, they should only be terminated with the appropriate connectors/lugs. Previously installed systems should be revisited and the cables replaced where possible or terminated properly.

For Further Thought

Some of the requirements established by UL Standards are of the form: "Don’t do something unless it is specifically allowed by markings on the product or in the instructions.” An example is the use of fine-stranded cables discussed above. They are not to be used with a connector or terminal unless that connector or terminal is specifically marked allowing their use. Another example may be the Line and Load markings on circuit breakers where the absence of such markings indicate they are deemed suitable for backfeeding. Most of the dc circuit breakers used in the PV industry are marked with Line and Load, but are routinely used in a backfeed configuration on listed equipment.

Many of these "invisible” requirements were developed decades ago in the early days of the electrical power industry. Old-line firms like Square D, GE, T&B, Westinghouse, and the other manufacturers and users of electrical equipment have developed in-house procedures and standards to preserve the "old” corporate knowledge of these hidden requirements over the years as people come and go. It appears that "youngster” industries like PV, fuel cells, uninterruptible power systems and the like, may not have developed a means of first discovering and then preserving these "hidden” requirements. Additionally, the testing agencies may be overlooking some of these "’invisible” requirements in the testing and listing of equipment as their corporate memory retires.

The PV Industry (and possibly others) may have to implement a "”search and discover”" activity to ferret out these hidden requirements, develop methods to preserve the knowledge, and then ensure that they are met by our equipment and systems that must remain safe, reliable, and durable for 30+ years.

Installed or inspected any fine conductor cables recently?

For Additional Information

If this article has raised questions, do not hesitate to contact the author by phone or e-mail. E-mail:, Phone: 505-646-6105

A PV Systems Inspector/Installer Checklist will be sent via e-mail to those requesting it. A copy of the 100-page Photovoltaic Power Systems and the National Electrical Code: Suggested Practices, published by Sandia National Laboratories and written by the author, will be sent at no charge to those requesting a copy with their address by e-mail. The Southwest Technology Development web site ( maintains all copies of the "”Code Corner Columns”" written by the author and published in Home Power Magazine over the last 10 years.

The author makes 6–8 hour presentations on "”PV Systems and the NEC”" to groups of 40 or more inspectors, electricians, electrical contractors, and PV professionals for a very nominal cost on an as-requested basis.

Read more by John Wiles

Tags:  Featured  January-February 2005  Perspectives on PV 

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Stalking the Elusive and Somewhat Strange PV System

Posted By John Wiles, Monday, November 01, 2004
Updated: Wednesday, January 23, 2013

Even as PV sales and installations are booming (especially in states or regions providing financial incentives), PV systems are still relatively rare. While many inspectors have neither seen nor inspected one, some inspectors are inundated with inspection requests for these systems. Some inspectors never want to see or inspect a PV system. The rarity of PV systems does not prepare the typical inspector when he or she comes upon one for the first time. These systems and the equipment used in them are unlike other common electrical power systems.

PV Modules

The first things the inspector sees are the PV modules. While most of them have glass fronts, aluminum frames (colored mill-finish aluminum or anodized brown or black (photo 1) and plastic backs, some will be made with plastic frames or with no frames. Others will be used as roofing materials (photo 2) or laminated directly to standing seam metal roofs (photo 3). PV modules come in many sizes and shapes. The inspector needs to determine the listing of the modules and the electrical ratings. These are usually printed on the back of the module or are available in the instruction manual. Some unlisted, custom modules are being installed in architect-designed projects and it is the inspector’s call as to whether they meet Code requirements. Although appearances may differ, these PV modules all

Photo 1. Framed PV modules

Photo 2. PV modules as roofing meterial

produce electricity when illuminated and the normal cautions associated with any electrical power system should be followed. PV modules come in differing power and voltage ratings. They must be connected in a manner that produces the needed voltage, current, and power since the output of a single module is usually not sufficient.

PV Combiners

PV combiners (PV j-boxes or PV combining enclosures) are common in PV systems operating at dc nominal voltages of 12, 24, and 48 volts and sometimes are used on higher voltage systems (up to 600 volts). In these systems, it is a normal practice to connect modules

Photo 3. PV modules laminated to metal roof

in series (called a source circuit) to get the proper voltage and then connect each series string of modules in parallel through a PV combiner to increase the current to get the desired power level. These combiners will usually contain the overcurrent devices (fuses or circuit breakers) that are required to protect the module interconnecting conductors from fault currents and the individual modules from reverse currents. The reverse currents may originate from parallel-connected strings of modules, from reverse currents from the batteries in a system that has them, or from backfeed currents from a utility-interactive inverter. The ratings of the overcurrent devices must be consistent with the ampacity of the conductors connecting the modules and the maximum series fuse marked on the back of the module. The combiner might be viewed as a branch circuit load center connected in

Photo 4. PV combiner with fuses

reverse acting like a PV source panel. The overcurrent devices in this enclosure are located in the proper place in the PV circuits to meet NEC and UL requirements. Most of these enclosures are white since they may be exposed to sunlight and white minimizes the internal temperature rise (see photos 4 and 5). Inspectors should check for screw-cover enclosures and warning labels if the combiner contains circuit breakers or fuses and has internal, exposed, energized terminals. Several units have been listed with no external labels warning that there are no user serviceable parts inside. UL Standard 1741 will be changed to reflect the requirement for such warning labels because there are internal, exposed busbars in these units that pose shock hazards. It may seem strange, but these enclosures containing normally user-serviceable

Photos 5. PV combiner with circuit breakers

items like fuses and circuit breakers are not required to have a dead-front interior panel.

Charge Controllers

Stand-alone systems and utility-interactive (U-I) systems with battery banks will also have charge controllers that regulate the state-of-charge to the battery bank. Charge controllers come in many sizes, shapes, and colors (see photos 6, 7 and 8). When properly adjusted, they protect the batteries from being overcharged. The installer is responsible for adjusting these devices

Photo 6. 40 A PV charge controller with remote display

properly. Inspectors should verify good field terminations, proper conductor sizes, and appropriate overcurrent devices protecting those conductors. For example, if a charge controller has a continuous 60-amp rating, then the connected conductors should be rated at least at 75 amps (1.25 x 60) and have appropriate overcurrent protection.


Inverters are found in both stand-alone systems and U-I systems. They essentially convert direct current (dc) energy from the PV system (and the dc energy stored in batteries) to alternating current (ac) energy for use by local loads or for feeding into the utility system. Some U-I inverters have the capability to power

Photo 7. 60 A PV charge controller

standby load circuits from batteries when the utility is down (see photos 9, 10, and 11). Unfortunately installation manuals for these complex inverters (particularly the stand-alone types) can be several hundred pages long. The inspector should verify the proper dc and ac conductor sizes and overcurrent protection. Both are based on the rated ac power output of the inverter. [See 690.8 and 690.9 in the NEC Handbook.]

The last, somewhat unique, piece of equipment found in PV systems is the NEC 690.5 required ground-fault protection device.

Ground-Fault Protection Devices

Section 690.5, Ground-Fault Protection, of the 1987 NEC added new requirements for

Photo 8. 60 A max power tracking PV charge controller

photovoltaic (PV) systems mounted on the roofs of dwellings. The requirements are intended to reduce fire hazards resulting from ground faults in PV systems mounted on the roofs of dwellings. There is no intent to provide any shock protection, and the requirement is not to be associated with a direct current (dc) GFCI. The ground-fault protection device (GFPD) is intended to deal only with ground faults and not line-to-line faults.

The requirements for the ground-fault protection device have been modified in subsequent revisions of the Code and the current requirements for the device are as follows.

1. Detect a ground fault

2. Interrupt the fault current

3. Indicate that there was a ground fault

4. Open the ungrounded PV conductors

To understand how these GFPDs work, it must be understood that nearly all currently available inverters, both stand-alone and utility-interactive, employ a transformer that isolates the dc grounded circuit conductor (usually the negative) from the ac grounded circuit conductor (usually the neutral). With this transformer isolation, the dc side of a PV system may be considered to be similar to a separately derived system and, as such, must have a single dc bonding connection (jumper) that connects the dc grounded circuit conductor to a common grounding point where the dc equipment-grounding conductors and the dc grounding electrode are connected. Like grounded ac systems, only a single dc bonding connection is allowed. If more than one bonding connection were allowed on either the ac side of the system or on the dc side of the system, unwanted currents would circulate in the equipment-grounding conductors and would violate NEC 250.6.

Photo 9. Stand-alone 4 kW inverter

GFPDs are available as separate devices for adding to stand-alone PV systems and as internal circuits in most utility-interactive inverters. These devices contain and serve as the dc bonding connection.

Figure 1. Ground-fault paths

In any ground-fault scenario on the dc side of the PV system, ground-fault currents from any source (PV modules or batteries in stand-alone systems) must eventually flow through the dc bonding connection on their way from the energy source through the fault and back to the energy source. This includes single ground faults involving the positive conductor faulting to ground or in the negative conductor faulting to ground. In ground faults involving the negative conductor (a grounded conductor), the fault creates unwanted parallel paths for the negative currents and the fault currents will also flow through the dc bonding connection. The diagram in figure 1 shows both positive (red) and negative (blue) ground faults and the paths that the fault currents take. As noted above, all ground-fault currents must pass through the dc bonding connection where the GFPD sensing device is located.

Photo 10. Utility-interactive 2.5 kW inverter

To meet the NEC 690.5 requirements, a typical GFPD has a 1/2 amp to 1 amp and sometimes 5 amp overcurrent device installed in the dc bonding connection. When the dc ground-fault currents exceed the current rating of the device, it opens. By opening, the overcurrent device interrupts the ground-fault current as required in 690.5. If a circuit breaker is employed as the overcurrent device, the tripped position of the breaker handle provides the indicating function. When a fuse is used, an additional electronic monitoring circuit in the inverter provides an indication that there has been a ground-fault. The indication function is also a 690.5 requirement. There is no automatic resetting of these devices.

In the GFPD using a circuit breaker as the sensing device, an additional circuit breaker is mechanically connected (common handle/common trip) to the sensing circuit breaker (see photo 12). These types of GFPDs may be found in both stand-alone and 48-volt utility-interactive systems. This additional circuit breaker (usually rated at 100 amps and used as a switch rather than an overcurrent device) is connected in series with the ungrounded circuit conductor from the PV array. In this manner, when a ground fault is sensed and interrupted, the added circuit breaker disconnects the PV array from the rest of the circuit providing an additional indication that something has happened that needs attention.

Photo 11. Utility-interactive 3.5 kW inverter

Even though the GFPD uses a 100-amp circuit breaker in the ungrounded PV conductor, the 100-amp circuit breaker should not be used as the PV disconnect because in normal use of the system, turning off this breaker would unground the system and this is undesirable in non-fault situations.

Photo 12. Stand-alone PV ground-fault protection device

In the GFPD installed in utility-interactive inverters using a fuse as the sensing element, the electronic controls in the inverter that indicate that there has been a fault, also turn the inverter off and open the internal connections to the ac line. The inverters in photos 10 and 11 have internal fuses as part of the required ground-fault protection device. In listing these inverters, UL has indicated that this method of turning off the inverter to provide an additional indication of trouble meets the requirements of 690.5(B) for disconnecting the ungrounded PV conductor.

It should be noted that the dc GFPD detects and interrupts ground faults anywhere in the dc wiring and the GFPD may be located anywhere in the dc system. GFPDs installed in the utility-interactive inverters or installed in dc power centers on stand-alone systems are the most logical places for these devices. There is no requirement to install them at the PV module location. Installing them at the modules would significantly increase the length of the dc grounding electrode conductor and complicate the routing of that conductor. To achieve significant additional safety enhancements would require a GFPD at each and every module. Equipment to do this does not exist and there are no requirements for such equipment.

These devices are fully capable of interrupting ground faults occurring anywhere in the dc system including faults at the PV array or anywhere in the dc wiring from the PV module to the inverter and even to the battery in stand-alone systems. All of this can be done from any location on the dc circuit. Fire reduction and increased safety are achieved by having these GFPD on residential PV systems.

Yes, during a ground fault, the dc bonding connection is opened, and if the ground fault cures itself for some reason, the dc system remains ungrounded until the system is reset. A positive-to-ground fault may allow the negative conductor (now ungrounded) to go to the open-circuit voltage with respect to ground. This is addressed by the marking requirements of 690.5(C). A very high value resistance is usually built into the GFPD and this resistance bleeds off static electric charges and keeps the PV system loosely referenced to ground (but not solidly grounded) during ground-fault actions. The resistance is selected so that any fault currents still flowing are only a few milliamps—far too low to be a fire hazard.

PV equipment may look a little strange. However, most, if not all, of it is listed and can be installed safely according to the requirements established by theNational Electrical Code. Jump in, inspect away, the water’s fine, and the PV industry needs all the help it can get.

For Additional Information

If this article has raised questions, do not hesitate to contact the author by phone or e-mail. E-mail: Phone: 505-646-6105

A PV Systems Inspector/Installer Checklist will be sent via e-mail to those requesting it. A copy of the 100-page Photovoltaic Power Systems and the National Electrical Code: Suggested Practices, published by Sandia National Laboratories and written by the author, is available on the SWTDI web site or can be mailed at no charge to those requesting a copy with their address by e-mail. The Southwest Technology Development web site ( maintains all copies of the "Code Corner Columns” written by the author and published in Home Power Magazine over the last 10 years.

The author makes 6–8 hour presentations on "”PV Systems and the NEC”" to groups of 40 or more inspectors, electricians, electrical contractors, and PV professionals for a very nominal cost on an as-requested basis. Call for more information.

Read more by John Wiles

Tags:  Featured  November-December 2004  Perspectives on PV 

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Should They Be Grounded?

Posted By John Wiles, Wednesday, September 01, 2004
Updated: Wednesday, January 23, 2013

At first glance, the obvious answer is: Photovoltaic (PV) systems are no different from other electrical power systems, and of course they should be grounded as required by the National Electrical Code. The real question is: How critical is grounding PV systems?

Let us examine the various features of PV systems that relate to grounding. Most PV modules have aluminum frames and circuit conductors. They must be installed where trees, poles, or other high objects do not shade them. These systems are frequently installed on the roofs of buildings and are frequently the highest metallic objects in the vicinity. As such, they are subject to surges from nearby lightning strikes. In fact, mounted high on buildings, they may act like air terminals (lightning rods).

Photo 1. Stand-alone PV system near power lines

With the significant monetary incentives in California, New Jersey, New York, Pennsylvania and elsewhere, numerous PV systems are being installed in urban areas near power transmission lines (see photos 1 and 2). As a result of severe weather, earthquakes, or man-made disasters, these transmission lines may come into contact with the PV array in its exposed location.

Photo 2.Utility-interactive PV system under power lines

The most common types of utility-interactive PV systems use inverters that operate up to 600 volts direct current (dc). This voltage is significantly higher than the normal 208–240-volt ac found in dwellings and small commercial buildings. Keeping those voltages safely under control during the rare fault condition is certainly important, a strong case for proper grounding.

PV modules can be expected to generate dangerous amounts of energy (shock and fire hazards) when exposed to the sunlight for the next 40–50 years or longer. This is significantly longer than the life expectancy of most other electrical generators. Today, deterioration of residential wiring systems only slightly older is becoming a problem, and the wiring systems used in PV systems are exposed to the harsher outdoor environment. Durable grounding can help to minimize future problems.

Photo 3. Aluminum-framed PV modules

Do PV systems require quality grounding? Yes, they do, for all of the reasons identified in the Code and then some. All PV systems will require equipment grounding with the equipment grounding conductors. Most of the equipment has metal enclosures that should be grounded by the normal methods. If we look closely at PV systems, we see two areas where they present some unique grounding issues. The first is the grounding of the frames of PV modules (see the sidebar). The second area relates to grounding the circuit conductors.

PV Inverters Create Separately Derived Systems

The second area focuses on the fact that PV systems have dc circuits and ac circuits and both must be properly grounded. Although the NEC has parts of Article 250 that deal with the grounding of ac systems and parts that deal with the proper grounding of dc systems, it does not specifically deal with systems that have both ac and dc components.

In Article 100, the definition of separately derived systems includes PV systems and, in most cases, this is correct. Most, but not all, PV systems (both stand-alone systems and utility-interactive systems) employ an inverter that converts the dc from the PV modules to ac that is used to feed loads or the utility grid. These inverters use a transformer that isolates the dc side of the system from the ac side. The grounded dc circuit conductor is not directly connected to the grounded ac circuit conductor. Although we normally think of separately derived systems as applying only to ac systems with transformers, in fact, the isolation between ac and dc circuits in PV inverters makes many PV systems also separately derived.

AC Grounding

As in any separately derived system, both parts must be properly grounded. There is usually no internal bond between the ac grounded circuit conductor and the grounding system inside either stand-alone or utility-interactive inverters. Both of these PV systems rely on the neutral-to-ground main bonding jumper in the service equipment (utility-interactive systems) or the bonding jumper in the first load center (stand-alone systems) for grounding the ac side of the system.

Photo 4. ILSCO GBL4 DBT lug attached to PV module

DC Grounding

The dc side of the system must also be grounded when the system voltage (open-circuit PV voltage times a temperature-dependent constant) is above 50 volts. See NEC 690.41 for more details. NEC Table 690.7 gives the temperature-dependent constant, and the application of this constant usually indicates that PV systems with a nominal voltage of 24-volts or greater must have the dc side grounded. Only infrequently, do we find 12-volt dc systems that do not have one of the dc circuit conductors grounded, and even those systems must have an equipment grounding system (see NEC 690.43). Nearly all utility-interactive PV systems operate with a nominal voltage of 48 volts or higher so they must have one of the dc circuit conductors grounded.

Photo 5. Improperly installed grounding hardware

Properly grounding the dc side of a PV system is somewhat complicated by NEC 690.5 that requires a ground-fault protection device (GFP) on some PV systems. If the PV array is mounted on the roof of a dwelling, 690.5 requires that this device be included in the system to reduce fire hazards. Many utility-interactive inverters have an internal GFP. Inverters (both stand-alone and utility-interactive) that are used in systems with PV modules mounted on the roofs of dwellings that do not have the internal GFP must have an external GFP installed in the system (see photo 6). In nearly all cases, these GFPs (either inside the inverter or externally mounted) actually make the grounded circuit conductor-to-ground bond.

For systems employing a GFP, there should be no external bonding conductor, and to add one to these systems would bypass the GFP and render it inoperative. A fine print note has been proposed for the 2005 NEC to alert installers and inspectors to the danger.

690.42 FPN: Equipment containing ground-fault protection devices as required by 690.5 will have the single-point for dc grounding included as a part of the equipment. Any grounding point installed externally to the equipment would bypass any internal ground-fault protection device.

In most dc systems, the negative conductor is the grounded conductor.

Photo 6. External ground-fault protection device

A dc bond inside the inverter with a GFP or a dc bond in a GFP external to the inverter establishes the need for and connection location of a dc grounding electrode conductor. Some inverters with an internal GFP have a terminal designated for connecting the usual 8 AWG to 4 AWG grounding electrode conductor. Other inverters are lacking this connection. Some inverter manufacturers are providing a field-installed lug kit for this connection that has been evaluated by their listing agency. PV systems with externally installed GFP devices will have an appropriate connection place (and instructions) for the grounding electrode conductor.

PV systems that do not have PV modules mounted on the roofs of dwellings are not required to have the 690.5 GFP, but many inverters in those systems will have it anyway. In those systems not requiring or having a GFP, then the dc bonding jumper may be installed at any single point on the PV output circuits, and this is where the dc grounding electrode conductor should be connected.

And The Other End of the Grounding Electrode Conductor?

There are two options for routing the ac and dc grounding electrode conductors, and these should be clarified in a proposed change to the 2005 NEC. Here is the wording of the proposal:

690.47(C) Systems with Alternating-Current and Direct-Current Grounding Requirements

Photovoltaic power systems with both alternating-current (ac) and direct-current (dc) grounding requirements shall be permitted to be grounded as described in (1) or (2).

(1) A grounding electrode conductor shall be connected between the identified dc grounding point to a separate dc grounding electrode. The dc grounding electrode conductor shall be sized according to 250.166. The dc grounding electrode shall be bonded to the ac grounding electrode to make a grounding electrode system according to 250.52 and 250.53. The bonding conductor shall be no smaller than the largest grounding electrode conductor, either ac or dc.

(2) The dc grounding electrode conductor and ac grounding electrode conductor shall be connected to a single grounding electrode. The separate grounding electrode conductors shall be sized as required by 250.66 (ac) and 250.166 (dc).


Grounding PV systems is at least as important as grounding other electrical power systems. Unique PV hardware such as the aluminum framed modules and inverters that isolate the dc circuits from the ac circuits dictate that extra attention should be directed toward making the grounding system reliable and durable.

By the way, a proposal for the 2005 NEC may eliminate the requirement to ground one of the circuit conductors in some PV systems.

For Additional Information
If this article has raised questions, do not hesitate to contact the author by phone or e-mail. E-mail: Phone: 505-646-6105

A PV Systems Inspector/Installer Checklist will be sent via e-mail to those requesting it. A copy of the 100-page Photovoltaic Power Systems and the National Electrical Code: Suggested Practices, published by Sandia National Laboratories and written by the author, will be sent at no charge to those requesting a copy with their address by e-mail. The Southwest Technology Development web site ( maintains all copies of the "Code Corner Columns” written by the author and published in Home Power Magazine over the last 10 years.

The author makes 6–8 hour presentations on "”PV Systems and the NEC”" to groups of 40 or more inspectors, electricians, electrical contractors, and PV professionals for a very nominal cost on an as-requested basis.


Grounding PV Modules

Grounding PV modules to reduce or eliminate shock and fire hazards is necessary but difficult. We typically use copper conductors for electrical connections and the module frames are generally aluminum (see photo 3). Copper and aluminum don’t mix as was discovered in numerous fires in houses wired with aluminum wiring in the 1970s. Many have a mill finish, some are clear coated, and some are anodized for color. The mill finish aluminum and any aluminum that is scratched quickly oxidizes. This oxidation and any clear coat or anodizing form an insulating surface that makes for difficult long-lasting, low-resistance electrical connections (e.g., frame grounding). The oxidation/anodizing is not a good enough insulator to prevent electrical shocks, but it is good enough to make good electrical connections difficult.

Underwriters Laboratories (UL) who tests and lists all PV modules sold in the U. S. requires very stringent mechanical connections between the various pieces of the module frame to ensure that these frame pieces remain mechanically and electrically connected over the life of the module. These low-resistance connections are required because a failure of the insulating materials in the module could allow the frame to become energized at up to 600 volts (depending on the system design). The National Electrical Code requires that any exposed metal surface be grounded if it could be energized. The installer of a PV system is required to ground each module frame. The Code and UL Standard 1703 require that the module frame be grounded at the point where a designated grounding provision has been made. The connection must be made with the hardware provided using the instructions supplied by the module manufacturer.

The designated point marked on the module frame must be used since this is the only point tested and evaluated by UL for use as a long-term grounding point. UL has established that using other points such as the module structural mounting holes coupled with typical field installation "techniques” do not result in low-resistance, durable connections to aluminum module frames. If each and every possible combination of nut, bolt, lock washer, and star washer could be evaluated for electrical properties and installation torque requirements and the installers would all use these components and install them according to the torque requirements (we all have and use torque wrenches and torque screw drivers don’t we?), it might be possible to use the structural mounting holes for grounding.

Most U.S. PV module manufacturers are providing acceptable grounding hardware and instructions. Japanese module manufacturers are frequently providing less-than-adequate hardware and unclear instructions. Future revisions of UL 1703 should address these issues. BP Solar is to be congratulated for getting their module listing to include making new grounding points at other locations than the marked points.

In the meantime, installers have to struggle with the existing hardware and instructions, even when they are less than adequate. Southwest Technology Development Institute has identified suitable grounding hardware and provides that information when installers ask about grounding—a frequent topic. And, yes, we are using the hardware and methods described below to ground PV modules in our new inverter test facility when the modules have less than satisfactory grounding hardware or no hardware at all.

For those modules that have been supplied with inadequate or unusable hardware or no hardware at all, here is a way to meet the intent of the Code and UL Standard 1703. Of course, ignoring the manufacturer’s instructions and hardware (however poor) is done at one’s own risk.

For those situations requiring an equipment grounding conductor larger than 10 AWG, a thread-cutting stainless steel 10-32 screw can be used to attach an ILSCO GBL4 DBT lug to the module frame at, or adjacent to, the point marked for grounding (see photo 4).

A #19 drill is required to make the proper size hole for the 10-32 screw. The 10-32 screw is required so that at least two threads are cut into the aluminum (a general UL requirement for connections of this kind). The thread-cutting screw is required so that an airtight, oxygen-free mating is assured between the screw and the frame to prevent the aluminum from re-oxidizing. It is not acceptable to use the hex-head green grounding screws (even when they have 10-32 threads) because they are not listed for outdoor exposure and will corrode eventually. The same can be said for other screws, lugs, and terminals that have not been listed for outdoor applications. Hex-head stainless steel "tech” screws and sheet metal screws do not have sufficiently fine threads to make the necessary low-resistance, mechanically durable connection. The only thread-cutting, 10-32 stainless steel screws that have been identified so far have Phillips heads; not the fastest for installation.

The ILSCO GBL4 DBT lug is a lay-in lug made of solid copper and then tin-plated. It has a stainless steel screw to hold the wire. It accepts a 14–4 AWG copper conductor. It is listed for direct burial use (DB) and outdoor use and can be attached to aluminum structures (the tin plate). The much cheaper ILSCO GBL4 lug looks identical, but is tin plated aluminum, has a plated screw, and is not listed for outdoor use. I have not been able to identify an alternative to the GBL4 DBT, but continue to search.

If the module grounding is to be accomplished with a 14–10 AWG conductor, then the ILSCO lug is not needed. Two number 10 stainless-steel flat washers would be used on the 10-32 screw and the copper wire would be wrapped around the screw between the two flat washers that would isolate the copper conductor from contact with the aluminum module frame.

Yes, we would all like to use the module mounting structure for grounding. The Code allows metal structures to be used for grounding and even allows the paint or other covering to be scraped away to ensure a good electrical contact. We see numerous types of electrical equipment grounded with sheet metal screws and star washers. This works on common metals like steel, but not on aluminum due to oxidation.

Unfortunately, many PV systems are being grounded improperly even when the proper hardware has been supplied. Photo 5 shows that even the proper hardware can be misused. Here, the stainless-steel isolation washer has been installed in the wrong sequence and the copper grounding wire is being pushed against the aluminum frame, a condition sure to cause corrosion and loss of electrical contact in the future.

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Single Conductor Exposed Cables! Not In My Jurisdiction!

Posted By John Wiles, Thursday, July 01, 2004
Updated: Wednesday, January 23, 2013

So sayeth the inspector when faced with inspecting his or her first rooftop residential or commercial PV installation. Yes, PV systems have some unusual wiring methods allowed by the Code. However, since all of the usual wiring methods found in chapter 3 of the Code also apply, the inspector must sort through what is allowed and what has been installed by the typical do-it-yourselfer or other uninformed installer of electrical equipment. Business will be as usual, with only a few small twists to learn.


Before we address these "new” or unusual wiring methods for PV modules, let’s cover the old standbys found in chapters 3 and 4 of the Code. Any wiring system that is suitable for the environment is acceptable for a code-compliant installation. The environment is tough with wide ranging temperatures and moisture. (See sidebar A for the environment in which PV modules operate). This usually dictates a wiring method rated for outdoor, hot (70°–80°C) and wet conditions. Some wiring methods are not suitable for outdoor wet environments, some are not suited for hot environments, and some are not sunlight resistant. In addition to wiring methods using conductors in a raceway, tray cable (type TC) might be considered and it is found attached to some PV modules with a connector.

Photo 1. Modules on tracker

Some PV modules are mounted on devices called trackers that move slowly throughout the day to follow the sun, thereby increasing the PV module output (see photo 1). Section 690.31(C) permits (does not require) the use of appropriate portable power cables found in Article 400 as long as they are suitable for the environment. However, the "extreme” rotational rate of these devices (900 revolutions per decade J) does not usually indicate that these flexible portable power cables are required on trackers. Normal stranded cables in flexible conduits have passed the test of time. Of course, portable power cables may not be used on fixed, non-moving/vibrating electrical systems or on fixed PV module installations.

"New” PV Module Wiring Methods

Photo 2. Early PV module terminal

In addition to all of the normal wiring methods allowed in chapters 3 and 4 of the Code, 690.31(B) permits (does not require) the use of exposed single-conductor cables for interconnecting PV modules. Cable types USE, USE-2, SE, and UF (where marked sunlight resistant) are permitted. This allowance was added to the Code in the 1984 edition because many PV modules had separate positive and negative output terminals that were as much as six feet apart and the PV industry deemed that it was not practical or cost effective to run raceways or multiple-conductor cables to both locations for a single contact (see photo 2). Since this electrical wiring was usually roof-mounted in relative inaccessible locations, the code-making panel deemed that the safety issues were minimal. Somehow, it was not mentioned that some of those early PV modules had no junction boxes and some even had exposed terminals that had to be covered. Some ceiling heating panels have similar connection arrangements.

Photo 3. Conduit ready PV module

Since 1984, when Article 690 was first added to the Code, PV modules have improved significantly and there are two main types of electrical connections for the modules. Many have plastic terminal/junction boxes firmly attached to the back of the module. These junction boxes have conduit knockouts that will normally accept 1/2″ trade size conduit or cord grips for single conductor cables (see photo 3). Other modules use appropriate (usually USE-2) pigtail conductors permanently attached to the module with connectors on the ends (see photo 4). The two pigtail conductors (one for the positive output and one for the negative output) allow easy series connection of the PV modules to form strings of modules for the higher voltage systems (24, 48 and 200–600 volts).


Photo 4. PV module with attached cables and connectors


When modules with junction boxes are used, the single conductor cables should have adequate strain relief. Normally this dictates the use of a cord grip in the knockout and that device should be listed for use outdoors. A few modules have, in addition to the knockouts, a small hole (about 1/4″) that will accept the conductor directly. A silicon gasket in the side of the junction box provides a raintight seal where the conductor penetrates. Inside the junction box is a plastic post and the conductor must be wire-tied/wire-wrapped to this post for strain relief.

Photo 5. Combining box wiring

These single-conductor exposed cables should only be used to make connections between modules and from the modules to a nearby junction box where the wiring method transitions to a more conventional wiring method (see photo 5). The conductors should be securely fastened to the module frames and support structure to meet good workmanship standards. At the very least, outdoor rated plastic wire ties/wire wraps should be used, but for more durability, many installers use insulated metal clamps.

Conductor Selection

For the exposed single-conductor cables, the environment and the Code [690.31(B)] dictate that USE-2, SE, and UF (where marked sunlight resistant) be used. USE-2 and SE are inherently sunlight resistant and that feature is verified in the listing process; they are not marked with the sunlight resistant marking (see photo 6). Underwriters Laboratories (UL) has been listing some PV modules with attached RHW-2 cables marked sunlight resistant and UL maintains that these are equivalent to USE-2 cables.

Photo 6. USE-2 on top of PV cell

It should be noted that USE-2 cable with no other marking does not have the necessary flame-retardants for use inside buildings. Dual marked USE-2/RHW-2 cables and SE cables do have the necessary flame-retardants, and a single cable type can be used from the PV modules to the final utilization equipment. Of course, the sections inside the building would have to be installed in an approved raceway.

The environmental conditions in the module junction box and along the backs of the modules dictate that wet-rated 90°C conductors be used when in conduit. The 90°C requirement comes from the high operating temperatures of the modules, and the wet requirement comes from the fact that all outdoor locations are considered wet locations. In conduit, these cables would be THWN-2, XHHW-2, RHW-2 and similar cables.

Current and Voltage Ratings

Conductors must be able to withstand the voltages and currents impressed upon them by the widely varying outputs of the PV system. For several reasons, the electrical design of PV systems (as required in Article 690) is based on worst-case conditions. Only continuous (three hours or more) power production is used and that power production is estimated at the worst-case level. There are no non-continuous energy sources.

Early PV module manufacturers, inverter manufacturers, Underwriters Laboratories, and individuals involved with codes and standards recognized that these variations in temperature and irradiance from Standard Test Conditions affected the module output and had to be addressed. (See sidebar B for information on how PV modules respond to the environment).

Excessive, unexpected voltages could cause arcing in switchgear and overcurrent devices, deterioration and breakdown of the insulation on conductors, and damage to electronic devices like inverters, charge controllers, and the PV modules themselves. Higher-than-rated currents

Figure 1. Solar power vs. time

could cause nuisance tripping of overcurrent devices, overheating of conductors, and the subsequent deterioration of the conductors as well as failed switchgear, electronic devices, and power relay contacts.

PV Adjustment Factors

For the reasons stated above, the early PV pioneers developed mathematical tools to deal with the uncertain nature of the dc voltages and currents. The following instructions are found in the instruction manual supplied with every listed PV module—everyone reads the manuals don’t they?

The rated short-circuit current (at STC as marked on the back of the module) is to be multiplied by 125 percent to account for those bright, sunny days where the irradiance is above 1000

Figure 2. PV-IV operating curve

W/m2. This is done before any instructions/requirements in the NEC are implemented. This current then becomes the continuous current used for ampacity and rating calculations in the Code.

The rated open-circuit voltage (at STC as marked on the back of the module) is to be multiplied by 125 percent to account for those bright, sunny and cold, windy days. This is also done before any instructions/requirements in the NEC are addressed and the resulting voltage is the system voltage.

These new values of voltage and current are then used to determine the voltage ratings and the ampacity of the conductors. Future Perspectives on PV will address the application of these factors. In a hurry? See the last paragraph for more information.


At the other end of a PV system, the stand-alone (off-grid) PV system usually includes a battery bank (see photo 7). These battery systems usually operate at 12, 24 and sometimes 48 volts, and the inverters are rated to produce 120-volt ac power at power levels from 500 watts to over 10 kW depending on the size of the system. Residential PV systems usually employ stand-alone inverters in the 2.5 to 11 kW range, and when operating at 12, 24 or 48 volts, the battery currents can be in the hundreds of amps. Ampacity calculations show that the conductors between the inverter and the battery enclosure (required to be installed in conduit) are in the 2/0 AWG–500-kcmil range.

Photo 7. Battery bank

Photo 8. Welding cable cracke

Unfortunately, many PV installers have little experience in pulling these larger cables through conduit so many of them look for more flexible cables to ease the installation. The local auto supply shop has "battery” cables (unlisted) that appear to cover some of the size ranges, and local welding shops have welding cables (listed and unlisted) that appear to be suitable. However, neither battery cables nor welding cables have been tested and evaluated for use in fixed electrical power systems under the NEC. Article 630 mentions welding cables in conjunction with the secondary circuits of electric welding machines and installation in cable trays. Code-making panel 13 rejected a 2005 NEC proposal to use welding cable for battery connections as "Not listed for the application.” At least one sample of an unlisted welding cable used in conduit at nominal current levels for only 10 years was found to have the insulation cracked all the way to the conductor (see photo 8).

NEC chapter 3 conductors are available in fine-stranded versions in types RHW and THW; however, a special order is often required. Of course, the normal 7–13 strand THHN, RHW, THWN and similar conductors are suitable and can be used without significant difficulty (for the experienced) when the Code requirements for wire bending space and conduit fill are met in the equipment.

Future Perspectives on PV will address the ampacity calculations for the conductors used in PV systems.

For Additional Information

If this article has raised questions, do not hesitate to contact the author by phone or e-mail. E-mail: Phone: 505-646-6105

A PV Systems Inspector/Installer Checklist will be sent via e-mail to those requesting it. A copy of the 100-page Photovoltaic Power Systems and the National Electrical Code: Suggested Practices, published by Sandia National Laboratories and written by the author, will be sent at no charge to those requesting a copy with their address by e-mail. The Southwest Technology Development web site ( maintains all copies of the "Code Corner Columns” written by the author and published in Home Power Magazine over the last 10 years.

The author makes 6–8 hour presentations on "PV Systems and the NEC” to groups of 40 or more inspectors, electricians, electrical contractors, and PV professionals for a very nominal cost on an as-requested basis.

Sidebar A

PV Modules Operating in Extreme Environments

The environment in which PV modules operate affect the electrical safety of PV installations and drive the installation requirements found in the National Electrical Code.



The intensity of sunlight is called irradiance, and for PV systems the units are watts per square meter (W/m2). A square meter is about 11 square feet. A typical, clear sky, solar noon value of irradiance falling on the surface of the earth at sea level is 1000 W/m2. This value of irradiance is one of the Standard Test Conditions (STC) factors used to rate PV module and PV array output.

On clear, cloudless days, the magnitude of irradiance will peak at solar noon. A plot of the irradiance vs. time of day is presented in figure 1 and makes an arc-like curve. PV system designers need to know the amount of solar energy available each day (known as irradiation or insolation), and working with the irradiance vs. time curve is difficult since it requires mathematical integration of the data. To simplify the calculations used in PV system design, tables are provided that do the math and present the available solar energy as the period of time that the solar irradiance is at the 1000 W/m2 level. This is seen in figure 1 as the rectangular area with the top at 1000 W/m2. The width of the rectangle in hours is known as the peak sun hours. This peak level of irradiance will vary depending on a number of factors including orientation of the surface, altitude, and the local microclimate. The PV designer has access to this information for many regions and locations throughout the country. However, solar irradiance greater that 1000 W/m2 may be expected in many locations where PV systems are installed. At higher elevations, there is less air between the surface and the sun (atmospheric density is lower) and the range of irradiance values is higher than at sea level.

In many areas, the time period that the irradiance exceeds 1000 W/m2 can be three hours or more. This has an impact on the electrical design of the PV system. The peak may be any value above 1000 W/m2, and values in the range of 1100–1200 W/m2 are common. Short-term (10–15 minutes) peaks of over 1400 W/m2 have been measured when cumulus clouds have formed a refractive lens around the sun and concentrated the sunlight on the surface.


PV modules are rated (power, voltage, current) at a Standard Test Condition (STC) temperature of 25°C (77°F). Surfaces (including PV modules) mounted in exposed outdoor locations are subject to widely varying temperatures that are a result of the ambient temperatures, solar exposure and cooling by radiation and convection. A typical PV module mounted outdoors in a well-ventilated area and exposed to 1000 W/m2 of solar irradiance with no wind blowing can be expected to operate at 30–35°C above the ambient temperature. If the ambient temperature were 40°C (104°F), the typical PV module would operate in the 70–75°C range on hot sunny days during the peak solar period.

On the other hand, a PV module operating in cold, windy weather may have the cold winds remove heat so rapidly from the module that the sun never increases the module temperature more than a very few degrees above ambient temperatures. With winter ambient temperatures in some locations in the U.S. as low as –40°C (-40°F), modules can operate at these temperatures. Furthermore, surfaces facing the clear, nighttime and early-morning sky may be subject to radiation cooling and the surface may be a few degrees cooler than the ambient temperature.

Sidebar B

PV Module Characteristics

The rating of PV modules is done under a set of Standard Test Conditions. However, crystalline silicon PV modules respond to the widely varying environmental conditions addressed in sidebar A. From a performance perspective (needed to calculate the output of the PV module/system) the power output is directly proportional to the irradiance and has an inverse relationship with the module operating temperature. If irradiance increases by 10%, the power available from the module will also increase by 10%. As the module temperature increases above the 25°C (77°F) level, the module power output will drop about 0.5% per degree C increase in temperature. Conversely, if the module temperature decreases, the power output will increase about 0.5% per degree C. When a PV module operates at 75°C (experienced on hot sunny days with no wind), the output may be only 75% of the STC rated output due to the increased operating temperature. Module power output is the product of the output current and the output voltage. Typically at the peak-power point on the module operating curve (IV curve–see figure 2), the peak-power voltage will change about -0.5% per degree C and the module peak-power current will change very little with respect to temperature; voltage being the primary temperature-dependent factor in the power equation in this region of operation.

For safety purposes and to meet code requirements, the manner in which the open-circuit voltage and the short-circuit currents vary must be determined. For silicon PV modules, the open-circuit voltage is an inverse function of temperature. As temperature decreases, open-circuit voltage increases at about 0.38–0.4%/°C. At a module operating temperature of –40°C (-40°F), the open-circuit voltage may be 25% higher than the STC value. Open-circuit voltage is only slightly influenced by the irradiance. Obviously in total darkness, the voltage output is zero. However, even in dim light (dusk, dawn, heavy clouds) the open-circuit voltage is very nearly the STC rated value. Direct sunlight does not have to be shining on the module for the voltage to be on the output terminals; very little current may be available, but nearly full voltage can be expected in dim light. Thin film modules (as opposed to the more common crystalline silicon modules) may have different characteristics.

The short-circuit current is a direct function of irradiance. Increase or decrease the irradiance 20% and the short-circuit current changes by the same percentage and in the same direction. Short-circuit current also increases a slight amount as the module temperature increases, but this effect is generally ignored in PV design.

Overall Environmental Impacts on Module Performance

With the irradiance and temperature variations addressed in sidebar A, PV modules may be expected to have open-circuit voltages from about 15% below the STC value in hot, still weather to about 25% above the STC value in cold, windy weather. The short-circuit current may be 120% or more of the STC value on sunny, hot days and that output may exist for three hours or more.

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What Changed in Article 690?

Posted By John Wiles, Friday, January 01, 1999
Updated: Wednesday, January 16, 2013

Article 690, Solar Photovoltaic Power Systems, has been in the National Electrical Code (NEC) since 1984. An NFPA-appointed Task Group for Article 690 proposed changes to Article 690 for both the 1996 and 1999 codes. The Task Group, supported by more than 50 professionals from throughout the photovoltaic (PV) industry, met seven times during the 1999 code cycle to integrate the needs of the industry with the needs of electrical inspectors, and end users to ensure the safety of PV systems. The Task Group proposed 57 changes to Article 690 and all the changes were accepted in the review process. The performance and cost of PV installations was always a consideration as these changes were formed, but safety was the number-one priority. All of the proposals were well substantiated and coordinated throughout the PV industry, and with representatives of Underwriters Laboratories, Inc (UL). The Task Group was led by Ward Bower of the Photovoltaic System Applications Department at Sandia National Laboratories. Ray Weber, Chair of Code-Making-Panel #3 (CMP-3) requested the formation of the Task Group for Solar Photovoltaic Systems. Paul Duks of UL provided valuable background information and technical coordination with applicable UL standards.

The most significant changes that were made in Article 690 for the 1999 NEC, along with some of the rationale, are discussed in the remainder of this article.


Figure 690-1, often a source of confusion to many who thought it was a design diagram for a PV system, has been completely revised and expanded to identify the PV-unique components in various types of PV systems and to show how they may interrelate. A copy of the new Figure 690-1 is shown as Figure 1 and Figure 2 of this report.

Many definitions in Section 690-2 (Definitions) were updated and clarified and five new ones were added to define the terms used in Article 690. For example, the term "”power conditioner”" was replaced with the more commonly used term "”inverter.”" All references to solar hot water control systems were removed. The new and evolving ac PV module was defined as an Alternating Current Module to retain consistency of terms used in the NEC®. Definitions related to stand-alone, hybrid, and utility-interactive systems were added or revised to better define each and to include the hybrid PV systems. The common terminology appearing in Section 690-2 will aid the Authority Having Jurisdiction (AHJ) and PV installers to better understand the systems and to communicate more effectively during the installation and inspection process.

Section 690-4 (Installation) was revised to clarify the interconnections of modules. This change allows "”daisy chaining”" modules from junction box to junction box as long as ampacity and temperature requirements for wiring and devices are met. New language in 690-4 also allows interconnected modules in systems under 50 volts to be considered as a single-source circuit.


Section 690-5 (changed from Ground-fault Detection and Interruption to Ground-fault Protection) for the PV array on dwellings, was revised extensively to provide clarity and to allow alternative methods to satisfy the requirement for ground-fault protection while still maintaining system safety. Listed equipment that may be included in utility-interactive inverters, power centers, and as separate components is now available to meet this requirement. This fire-protection requirement on dwellings (which will hopefully never be needed) is now well defined. The hard-to-define term "”disable”" was removed from this section and from Section 690-18. Providing an indication of a fault and labeling the hardware is required in the 1999 edition. The fact that ground-fault protection equipment may automatically disconnect the grounded conductor of an array in the event of a fault is also covered with the requirement for a warning label placed near the ground-fault indicator.

A new Section 690-6 (Alternating-Current Modules) was added to fully define the connection requirements of ac PV modules. Among other things, a ground-fault protection device is required on the dedicated branch circuit used for connecting the ac module to the load center. That protection device is required to disable the ac module. Disabling an ac PV module is accomplished by removing the ac grid connection. Since the duplex outlet on a receptacle type GFCI violates the dedicated circuit requirement, a service entrance panel or blank face device must be used. This ground-fault protection requirement is intended for fire protection on dwellings and not shock protection. Ground-fault equipment protection circuit breakers that fit in the service entrance panel or in a separate panel and that trip at 20-30 milliamp are suitable.

The changes in the 1999 Article 690 will require changes in the documentation for calculating maximum voltages and currents for PV modules. Today, the UL requirements for PV modules are found in the instruction manual of listed modules. The old UL standard 1703 required the instruction manual to state the requirements for multiplying module open-circuit voltage and short-circuit current by 125% before going to the NEC. With the 1999 changes, those UL requirements have been included in Article 690-7 (Maximum Voltage) and 690-8 (Circuit Sizing and Current) of the NEC. Section 690-7 includes a new Table 690-7 that now makes the voltage multiplier a function of the lowest expected ambient temperature. Only when the expected temperature reaches -21°C (-5°F), does the factor increase to 1.25 as found in the old UL1703 standard. If the modules are to be installed where the coldest expected temperature is a balmy 10-25°C (50-77°F), then the correction factor on open-circuit voltage is only 1.06. Section 690-7 also limits the maximum voltage on one- and two-family dwellings to not more than 600 volts.

In a similar manner, Section 690-8 was revised to include the 125% solar enhancement multiplier required for PV source circuit and PV output circuit current calculations previously found in the PV module instruction manual as part of the listing documentation. Section 690-8 now includes both the 125% multiplying factor required to deal with daily variations in PV module output and the 125% multiplier used to derate all conductors and overcurrent devices throughout the code. The combined factor of both 125% multipliers for PV source and output circuits is 156%, while all other circuits in the system are subject to only a single 125% multi-plier or the 80% conductor-derate required throughout the code.

The new NEC language for system voltage and circuit current calculations for wire sizes requires careful coordination with the UL Standard 1703. The new 1999 NEC requirements may conflict with the UL Standard 1703 until it is modified to remove the solar enhancement and voltage temperature requirements from the module instruction manuals. In the meantime, there may be modules in the pipeline that still have the UL requirement in the instruction manual. Those using the 1999 NEC are now cautioned not to duplicate the solar enhancement requirement.

Section 690-9 (Overcurrent Protection) now has exceptions that do not require overcurrent devices on some types of circuits. These exceptions generally apply to small, single-module, direct-connected water pumping systems where there is no chance of high fault currents from other sources.

It should be noted that overcurrent devices in PV source and output circuits should be rated at 156% of the short-circuit currents from the modules. Obviously, with this rating, these overcurrent devices will not respond to fault currents solely from the connected modules. They will, however, protect the module conductors from backfeed currents from other sources such as parallel-connected modules, batteries, and even currents from ac sources back feeding through inverters.

Section 690-10 (Stand-Alone Systems) is a new section that should benefit the installer and owner of stand-alone PV systems. The code now allows the PV system inverter ac current output to be less than the rating of the building load center or service entrance equipment. A 500-watt inverter may now be connected to the input of a 120/240-volt, 200-amp load center for stand-alone applications. The conductor that is used for this connection has to be rated to carry only the 500-watt output of the inverter, not the 48,000 watts that the service entrance can carry. Also, Article 690-10 spells out that a single 120-volt inverter may be connected to a 120/240-volt load center when certain conditions are met. There must be no 240-volt circuits and no multi-wire branch circuits in the building. Of course, appropriate overcurrent devices must be installed at each end of this cable unless a tap rule as found in Section 240-21 (Location in a Circuit) can be applied.

Section 690-13 (Disconnection Means, All Conductors) was revised to clearly state that a switch, fuse, or circuit breaker should not be placed in a grounded conductor except where the grounded conductor is automatically interrupted to comply with the ground-fault protection required in Section 690-5.

AC PV modules may be grouped together on a single circuit, and a single disconnect-device for all modules is allowed according to additions in Section 690-15 (Disconnection of Photovoltaic Equipment). Ampacity calculations using the sum of the maximum output current of the ac modules still apply.

Section 690-17(Switch or Circuit Breaker) and 690-33 (Connectors) allow the use of a connector for a disconnect-device as long as it is listed for the use and meets other code requirements for polarization, guarding, personnel safety, and grounding. This applies to conventional systems and to ac PV modules.

The markings required on ac PV modules are listed in a new Section 690-52 (Marking, Alternating-Current Photovoltaic Modules). These markings are similar to those required for conventional PV systems required in Section 690-51.

Utility-interactive systems received considerable attention in the 1999 NEC because of the expected proliferation of these systems. Marking the points-of-connection of these systems is required by Section 690-54 (Interactive System Point of Connection). Most of Part G (Connection to Other Sources) was revised to allow easier connection of utility-interactive systems while still maintaining high levels of safety. The changes included a revised requirement for using listed equipment in interactive systems, a new requirement for inverters to de-energize upon loss-of-utility in interactive systems, allowable unbalanced grid connections, and a clarification of the allowable point-of-connection for a PV system.

Section 690-72 (Storage Batteries, Charge Control) was revised to require control of the charging process except the 1999 changes require no battery charge controls on systems where the maximum charging currents are very low (less than 3% of battery capacity expressed in amp-hours).

A new Part I (Systems Over 600 Volts) was added to Article 690 to specifically address PV systems operating over 600 volts. Some of the larger utility-interactive systems may operate above 600 volts. The new section directs that systems greater than 600 volts meet the requirements of the new Article 490 (Equipment, Over 600 Volts, Nominal) that has been added to collect all parts of the code for over 600 volts into one Article. The new Section I defines the maximum battery voltage as the highest voltage experienced under charging conditions. Maximum system voltage is used for the PV source- and output-circuits.

The 1999 NEC Handbook (available from NFPA) includes significantly more detail, substantiation, and explanations of Article 690 and the changes that were made for 1999. It is also an excellent reference for other articles of the NEC.

If you have questions about the implementation of PV systems following the requirements of the NEC, feel free to call, fax, email, or write John Wiles at the location below. Sandia National Laboratories sponsors the activities in this area as a support function to the PV Industry. This work was supported by the United States Department of Energy under Contract DE-AC04-94AL8500. Sandia is a multi-program laboratory operated by Sandia Corporation, a Lockheed Martin Company, for the United States Department of Energy.

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Photovoltaic Power Systems and the NEC

Posted By John Wiles, Friday, January 01, 1999
Updated: Wednesday, January 16, 2013


Photovoltaic (PV) systems that generate electricity from sunlight are being installed in ever increasing numbers throughout the United States and the rest of the world. Over 150 megawatts of PV modules are being produced worldwide annually and these PV modules, when exposed to sunlight, will be generating electricity for the next thirty years and longer. Utility-interactive PV systems (that can feed power to the electrical utility grid) and stand-alone PV systems are being installed in both rural and urban locations on residential dwellings and commercial buildings. They are either utility-interactive or they provide power for lights, water pumps, appliances, and communications equipment in stand-alone applications. A few PV systems are owned and operated by utility companies, but most are not, and they fall under the provisions of the National Electrical Code (NEC) and are inspected by the Authority Having Jurisdiction (AHJ).

Photovoltaic system

Photovoltaic system

This article will briefly describe both stand-alone and utility-interactive PV systems and highlight code issues that electrical inspectors should be aware of when inspecting them.

PV Cells, Modules and Arrays

PV modules use solar cells to convert sunlight directly into direct current (dc) electricity. A number of cells are connected in series or parallel to form a PV module, which is the smallest commercially available, listed product for power applications. PV modules range in power output from about six watts to about 300 watts with nominal output volt- ages from 6 to 90 volts (Figure 1, PV module test bed at New Mexico State University). PV modules are connected in series and parallel to increase voltage and current output; these groups of modules form PV panels or arrays. PV arrays may consist of any number of modules (for instance 30 watts or less at 12 volts) up to tens of thousands of modules with megawatt outputs at over a 1000 volts. One of the largest systems was utility-interactive and was installed, owned, and operated by a non-utility organization and, therefore, fell under the NEC.

Photovoltaic cells are made of a number of materials. The oldest commercially available technology uses a silicon material that is processed to produce a final product. Newer technologies are using various thin films to produce PV modules that are expected to lower the cost of the product. The most common PV module uses cells made of silicon wafers that are laminated between a glass front plate and rear insulator (sometimes glass) with an aluminum frame. PV modules made from thin-film photovoltaic materials may be constructed in a similar manner, but some manufacturers are exploring less expensive manufacturing methods such as laminating the PV material directly to metal roofs or producing roofing tiles that also serve as PV modules. Many of the PV modules on the market (manufactured in the US and elsewhere) have been listed to standards established by Underwriters Laboratories (UL) and many also have fire ratings for use on rooftops.


There are thousands of residential stand-alone PV systems in the US plus thousands of stand-alone communication sites, water pumping systems, emergency call boxes, and lighting systems. In many states, any electrical system that requires field-installed wiring should be installed according to local codes or the NEC and should be inspected.

Figure 2

Figure 2

As the name implies, stand-alone systems are not connected to the utility grid and are self-contained producers of electrical power. They may use batteries for energy storage. These systems may also have engine-driven backup generators. A typical residential stand-alone system might have a PV array rated from 1 to 4 kW, a 4 kW inverter, a 1000 amp-hour battery bank, and a 3 to 6 kW backup generator (see figure 2). An engine fueled by gasoline, propane, natural gas, or sometimes diesel fuel would drive the generator. PV systems that include a generator or second renewable energy source such as a wind turbine are known as hybrid systems (see figure 3, Hybrid PV system).

Figure 3

Figure 3

Commercial stand-alone PV systems used for power at telecommunications sites, National Parks, and in military installations may have PV arrays sized from 10 kW to 200 kW with proportionally sized battery banks and backup generators (Figure 4, Pinnacles National Monument PV System).

Remote (and some urban) lighting and water pumping systems may have only a few PV modules. Water pumping systems usually do not have batteries and operate only during daylight hours.

With the addition of a battery bank, most stand-alone PV systems will also have a charge controller to control the charging and discharging of the batteries (Figure 5, Battery charge controller). The charge controller may contain a low-voltage disconnect to protect the batteries from excessive discharge. The low-voltage disconnect may be a separate device. Many inverters have internal low-voltage disconnect controls.

Figure 4. Pinnacles National Monument PV System

Figure 4. Pinnacles National Monument PV System

There are more than 1000 utility-interactive PV systems in the U.S. but the number is expected to increase due to federal and state subsidies and the Million Solar Roofs Initiative of the federal government. For more information see the US Department of Energy’s web page at

A residential PV system in an urban location will usually be a utility-interactive system (Figure 6, PV modules on roof). The output of the PV array (typically 500-2,000 watts) will be connected to a listed, utility-interactive inverter (dc-to-ac power conversion) (Figure 7, Utility-interactive inverter). The interactive inverter will produce energy only when connected to the electrical power grid that is operating at near 60 Hz and 120 or 240 volts. If the grid is "down” for some reason, the inverter will produce no power and, in fact, will usually stop producing power (de-energize) even in "”brownout”" conditions. This creates a safer environment for the utility lineman by preventing exposure to PV power on lines that have been disconnected from the grid. Because of the NEC requirements to de-energize, utility-interactive PV systems do not pose any of the dangers associated with engine-driven generators that are illegally connected during outages after a storm.

Figure 5

Figure 5

Utility-interactive PV systems must be connected to the utility with a dedicated circuit. There should be no receptacle or other outlets on this circuit between the inverter output and the load center. Section 690-64(b)(2) places restraints on the size of the PV system that can be connected to any particular load center or other circuit. These restraints are particularly important in commercial installations where the load centers and distribution panels are operated at near capacity.

AC PV Module

The ac PV module is a new type of utility-interactive PV system (Figure 8-Two ac PV modules). These listed devices have a small (100-300 watt) inverter attached (factory integrated) directly to the back of the PV module or modules (Figure 9, Rear view of ac PV module showing attached inverter). There is no field-connected or installed dc wiring, and the system operates much like an ac appliance. It is listed as a single unit. The only output is alternating current, and there are no accessible dc voltages. The output terminals of the ac PV module are not energized until they are connected to a 120-volt 60-Hz utility grid. This type of PV system may become increasingly popular since the unit cost of these low-power systems is small compared to larger systems with multiple components. The installation and code requirements of the ac PV modules are considerably simplified.

Figure 6

Figure 6

Code Requirements

Figure 7

Figure 7

Article 690 of the NEC specifically addresses installation requirements for PV electrical systems, but most of the rest of the code is also applicable. Where there are conflicts in the code requirements between Article 690 and other articles of the Code, Article 690 takes precedence due to the unique nature of PV modules as electrical generators.


Aside from the exposed single-conductor module wiring allowed by NEC Section 690-31, the rest of the wiring, in both ac and dc circuits, should comply with the requirements of Chapter 3 (Wiring Methods and Materials) or Chapter 4 (Equipment for General Use) of the NEC. Exposed single-conductor wiring is not normally allowed by the NEC inside buildings and also should not be used in the well-designed and installed PV system. Flexible, portable power cable (NEC Chapter 4) should only be used in PV arrays where the movements of sun-tracking devices require the extra flexibility.

Figure 8

Figure 8

PV modules and arrays do not have the capability of generating high fault currents like a battery or generator. The PV output is proportional to the intensity of the sunlight on the module. The rated current (both short-circuit and operating) of a PV module is measured in a laboratory under standard test conditions. The standard conditions used for rating may be exceeded in actual use, on a daily basis, for three hours or more. Consequently, the instructions provided with PV modules require that all conductors and overcurrent devices be rated to handle 125 percent of the rated short-circuit current. This requirement was contained in the UL Standard 1703 and the 1996 NEC. In the 1999 NEC, the requirement is contained entirely within the NEC.

Temperature Derating of Conductors

Figure 9

Figure 9

Since PV modules operate at elevated temperatures and the wiring to the modules may be in conduits that are exposed to sunlight and the weather, temperature derating of conductors is necessary. PV modules may operate at temperatures of 20-40°C (68-104°F) above the ambient temperatures. In the hot, sunny Southwest, where ambient temperatures reach 45°C (113°F), the PV module junction box on the back surface of the module may reach 75°C (167°F). Conductors with 90°C-rated insulation should be used, and the ampacities of conductors in the junction boxes need to be derated accordingly. Conductors in conduit are considered to be in exposed locations and should have insulation rated for wet use. For exposed conductors, type USE-2 or type TC cable meets the 90°C/wet requirements. In conduit, conductor types RHW-2, THWN-2, THW-2, or XHHW-2 meet both the 90°C and wet requirements.

Overcurrent Protection

Figure 10

Figure 10

As in other electrical systems, each conductor or circuit in a PV system should be protected from overcurrent. Since a PV system may have more than one source of energy, some circuits may have power sources at both ends thereby requiring overcurrent protection at more than one location. Although PV modules are current-limited power production devices, the UL-listing and labeling may require an overcurrent device for each module or series string of modules to protect the modules and wiring from external sources of power. In most systems with batteries or utility-interactive inverters, the module wiring must be protected from high fault currents originating from the batteries or the utility grid back feeding through the system.

DC source-circuit combiner devices and power centers used in PV systems are somewhat like ac load centers used in conventional ac systems. The individual PV source circuits connected to PV power centers resemble ac branch circuits connected to circuit breakers in an ac load center.

Figure 11

Figure 11

Current-limiting fuses such as the Class RK-5 or Class T fuses are used to protect wiring and devices connected to batteries since large fault currents are possible. Where current-limiting fuses are not used, each overcurrent device in the circuit (either a fuse or circuit breaker) must have an interrupt rating capable of withstanding any fault currents that may occur. Typically, overcurrent devices with interrupt ratings of 20,000 amps or higher are used with battery circuits.

In the dc circuits of a PV system, only overcurrent devices listed for dc operation are allowed by the NEC. Underwriters (UL) Standard 1703 and the 1996 NEC require that the voltage rating of the overcurrent devices should be at least 125 percent of the rated, open-circuit voltage of the PV array output since rated open-circuit voltage increases as temperatures go below 25°C (77°F). In the 1999 NEC, a new Table 690-7 includes the UL 1703 requirement and provides correction factors that are less than 125 percent for localities where the modules will experience more moderate temperatures.


The requirement for disconnects for PV systems are covered in Article 690 of the NEC. Generally, a disconnect is needed for each source of power or energy storage device in the system. If these disconnects are inadequate to isolate equipment like inverters and charge controllers for servicing, additional disconnects may be required for these components.

PV modules and arrays are energized when illuminated, but a disconnect at the PV array location is not required by the NEC unless the system is so large (more than 10 kW) that subarray disconnects would facilitate maintenance actions. Usually, only a single disconnect for the PV array is used near the power center or other combiner box (stand-alone systems), or near the inverter (utility-interactive systems). This main PV disconnect disconnects the entire PV array from all equipment, thereby removing the PV source of power from the system. It also isolates the PV array and array wiring from all other sources of power in the system, but it does not make the array safe for maintenance. All switchgear used in dc circuits are required to be appropriately listed and labeled for use in dc circuits.

Ground-fault Protection

Section 690-5 (Ground-fault Protection) of the 1999 NEC requires that any PV array installed on a dwelling be provided with ground-fault protection (changed from the 1996 term "”Ground-fault Detection and Interruption”") to minimize the possibility of fires. This NEC requirement is unique to PV systems and is not related to the common GFCIs used for shock protection or the ground-fault equipment required on high-current circuits used for equipment protection. Utility-interactive inverters may contain ground-fault protection circuits or the ground-fault protection is available as an option. Stand-alone and utility-interactive PV systems that are roof-mounted on dwellings need ground-fault protection. AC PV modules generally are meeting the requirement with equipment-type, ground-fault-protection-circuit breakers installed as part of the dedicated branch circuit for those modules.

Listed Equipment Availability

Listed hardware for PV installations is now commercially available. Listed combiner boxes and power centers that contain the necessary overcurrent devices are sold as components (Figure 10, Listed Power Center). Several inverters with power outputs of less than 5 kW are listed. A number of listed battery charge controllers are now on the market. Components (such as inverters) for larger systems are not listed yet and may have to be examined for safety. Conventional junction boxes, pull boxes, conduit, and other familiar materials are used throughout the systems.

Batteries and Engine-generators

Batteries are covered in Article 690 of the NEC. The installation of batteries, their use in dwellings, allowable operating voltages, current limiting, battery interconnection, and charge control are all spelled out. Batteries and engine-generators generally are not listed. Batteries may either be sealed types (valve regulated lead-acid—VRLA or gelled electrolyte) or the more common flooded lead-acid batteries. All batteries can vent hydrogen gas when over-charged and they contain an electrolyte. Both types of batteries should be installed so that the exposed terminals are not accessible to unqualified persons. The flooded batteries should be installed in an acid resistant, non-conducting container to contain spilled electrolyte in the unlikely event that the battery case is damaged.

While the batteries should be installed in a well-vented area, power venting is not required for small systems. Hydrogen gas is very difficult to contain and normal room ventilation is usually adequate to ensure dispersion of the gasses. Venting manifolds common to each cell should be avoided. Conduit entrances to battery enclosures should be below the tops of the batteries since hydrogen gas rises, and the conduit ends need to be sealed with an appropriate material to prevent hydrogen gas from entering power centers or other switchgear.


Typically, PV power systems are installed by persons trained and experienced in one discipline or trade. The code-familiar person such as an electrical contractor or electrician may be unfamiliar with the unique particulars of PV system installations. Conversely, the PV system designer or vendor is often an expert on PV installation requirements but is not familiar with the intricacies of the NEC. For this reason, the most satisfactory installations are the result of a team effort, from project commencement to completion, that includes a PV designer, an electrical contractor/electrician, and the Authority Having Jurisdiction (AHJ).


Photovoltaic power systems have been installed throughout the US and increasing numbers are being installed each year. Most of these systems fall under the requirements of the National Electrical Code. Equipment, knowledge, and experience is available that allows these systems to be installed in full compliance with the NEC. Best results are obtained when a PV systems designer works with an electrician or electrical contractor and the Authority Having Jurisdiction.

Additional Information

A manual entitled Photovoltaic Power Systems and the National Electrical Code: Suggested Practices authored by John Wiles and published by Sandia National Laboratories is available without charge from the author or on the internet

The author writes a bi-monthly column called Code Corner in Home Power Magazine, which covers the NEC requirements for PV energy installations in some detail. The magazine is available on the Internet at subscriptions are available by calling 800-707-0836.

Presentations by the author on PV systems and the NEC® are available to groups of 30 or more electrical inspectors, electrical contractors, electricians, and other interested IAEI members. The presentations run from 6-8 hours and consist of overhead and 35mm slides and hardcopy handouts.

Read more by John Wiles

Tags:  Featured  January-February 1999  Perspectives on PV 

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