Gray Areas, Yours and Mine

The National Electrical Code, even though it is now almost 900 pages long, cannot specifically define every particular piece of equipment and every installation requirement for that equipment. There are always going to be areas that are left to the interpretation of the local inspector (the AHJ). This article will cover four gray areas that I get calls on and, perhaps, generate some discussion that may lead to clarifications. Send me your comments and your feelings about how the Code is either grayer or less gray and perhaps we will cover them in a future article.

 Photo 1. Couldn’t find the dc PV disconnect. What do you mean, the sun has to set?

Service Disconnect and PV Disconnect

This has long been one of my favorite gray areas in the Code. Section 230.70(A)(1) has the following requirement for the service disconnecting means.

"230.70(A)(1) Readily Accessible Location. The service disconnecting means shall be installed at a readily accessible location either outside of a building or structure or inside nearest the point of entrance of the service conductors.”

690.14(C)(1) has a similar requirement for the dc PV main disconnecting means.

"690.14(C)(1) Location. The photovoltaic disconnecting means shall be installed at a readily accessible location either on the outside of a building or structure or inside nearest the point of entrance of the system conductors.”

Now let’s go to the definitions in Article 100 and look up the definition of readily accessible.

"Accessible, Readily. Capable of being reached quickly for operation, renewal or inspection without requiring those to whom ready access is requisite to climb over or remove obstacles or to resort to portable ladders and so forth.”

AC Service Disconnect. Fire Service personnel responding to fire emergencies have a requirement to access the service disconnect to turn off the ac power to a building or structure to ensure safety where water and axes are being used.

One would assume that a locked door is an obstacle that must be removed to access a service disconnect located inside a building. I question whether or not the installation of the service disconnect inside a locked building meets the definition of readily accessible. With half of the residential service disconnects located inside the home and the other half located outside of the home, we seem to have a gray area.

An all too common situation occurs when a residence is on fire. The ac service disconnect is behind locked doors. The Fire Service maintains that they have master keys to many locks. And when confronted with high security locks, they bring out their universal master key, the fire axe. However, entering a burning building with power still in the building is not conducive to maximum safety.

Normally, the Fire Service will request the local utility to quickly respond and remove power from the building by opening a disconnect somewhere in the distribution system. However, when the power company cannot respond quickly enough in emergency situations, the Fire Service can and will remove the utility meter from the outside of the building thereby disconnecting the AC power to the structure. The Fire Service is usually reluctant to do this because of perceived hazards in this action and the fact that the meter socket and service conductors are still energized on or in the vicinity of the structure.

In many jurisdictions, the local codes and utility requirements dictate that all ac service disconnects on new construction be installed on the outside of the building near the meter location.

While there are ways to disconnect the ac power from a building or structure, it appears that this is a gray area in the Code. What about the dc PV disconnect?

DC PV Disconnect. The dc circuits from a PV array on the roof entering a building or structure do not have a meter that can be removed when the dc disconnect is located inside the structure. This gray area gets a little grayer when other sections in Article 690 are examined. The exception to 690.14(C)(1) of the Code makes things even a little more confusing. Where the dc PV conductors are installed in a metallic raceway, the dc PV disconnect does not have to be located near the point of entry and apparently can be located anywhere inside the building (except in a bathroom), but the disconnect must still be readily accessible. See photo 1.

DC Battery Disconnect. And there is an (increasing) number of battery-backed-up utility-interactive PV systems as well as many off-grid PV systems that have the ac circuits supplied by an inverter that is, in turn, supplied by a battery bank. What is the disconnect requirement for that battery disconnect and where is it to be located?

Help in 2014? For PV circuits, it would appear that the 2014 National Electrical Code might provide some clarification (or at least, other requirements) in this area. It is likely that a Fast Response disconnect will be required for these energized PV circuits on and in a building and the implication is that the Fire Service will have access to some sort of a remote controlled disconnecting means that will de-energize most of the PV circuits on or in a building or structure from an external location. However, for the time being it appears that these areas are still gray and have been for a very long time.

Placards and Directories. Although not directly addressing the accessibility issue, placards and directories help the first responders in locating all of the required disconnects. Sections 690.54, 690.55, 698.56, and 705.10 address these requirements. See photo 2.

Photo 2.   Placard showing external ac PV disconnect and dc battery disconnect in garage.

Grouping

Another gray area is the definition of grouping. In several sections of the Code, disconnecting means are required to be "grouped.” These requirements appear in 690.15; 690.14(C)(4); 230.71; 230.72 and other sections. Grouping is not specifically defined in the Code. Some inspectors maintain that the distance between the grouped disconnects is as far as you can reach with outstretched arms. Others consider grouping to mean within sight and, of course, within sight from is defined in Chapter 1 of the Code. A gray area: Should the dc PV disconnect be grouped with the ac service disconnect for the building? And, if so, how far apart can they be? See photo 3.

Photo 3.  Nicely grouped ac and dc disconnects

The Fence. Here is an example that I hear about several times a year. The inverter does not have an internal ac disconnect or the local jurisdiction or utility requires an external disconnect. NEC Section 690.15 requires a maintenance disconnect grouped with the inverter for obvious reasons. In many cases, where the inverter is located adjacent to the load center for the building, the backfed breaker in the load center can be used as the required disconnect. They are within arms length and it is easy to verify that the breaker is off when the inverter needs maintenance. Unfortunately, for some reason, frequently the inverter is mounted on a wall with a fence separating the inverter location from the wall-mounted ac load center containing the backfed breaker. Usually, the fence has a gate in it and when the gate is open the breaker is visible from the inverter vocation. But, when the gate is closed, the breaker cannot be seen from the inverter.

In some cases the gate is always closed to keep a dog in the backyard. In another example, the gate would normally swing shut by itself. And in some cases, the gate could be latched in the open position. This is a gray area requiring an AHJ decision. See photo 4.

Photo 4. Oops, ac disconnect on other side of the wall

Expected Lowest Temperature

The Problem. PV designers and installers face a dilemma when designing PV systems. PV module voltages and string (the series connection of modules) voltages increase as temperatures go down, and they decrease as temperatures go up. The PV inverter is able to accept only a certain range of voltages. In hot weather the string voltage must be high enough to operate the inverter properly and, of course, associated with the lower module voltage is less module/string/array power. The designer wants to put as many modules in series for each string as possible to maximize power output and to keep the inverter operating properly in hot weather. However, in cold weather voltages increase and if they increase too much they may exceed the upper limit of the inverter and the upper voltage limit of the modules, the wiring, and other equipment.

The Gray Area. NEC Section 690.7, Maximum Voltage, requires that the maximum photovoltaic system voltage be determined and the requirement is to determine that voltage at the lowest expected ambient temperature. The gray area of interest: What is meant by the term lowest expected ambient temperature?

It is possible that the temperature may drop to a point where the voltage of the modules and the string of modules rise above the voltage rating of the modules, the voltage rating of the cables, or the voltage rating of other connected equipment? The open-circuit voltage (Voc) of the string is the voltage of concern. That voltage may be higher than the normal rated maximum power point voltage of the module or the string (Vmp), and may exceed the maximum voltage rating of equipment in the system.

Operating Modes. In a properly functioning PV system, the dc electrical system is rarely subjected to open-circuit voltage (Voc). As the array voltage comes up in the morning when the sun rises, the inverter will sense the increasing voltage and when the voltage is high enough to energize the control circuits, the inverter will start power tracking and will hold the array dc voltage at the peak power point (Vmp), which will be substantially below the open-circuit voltage. In most cases in the morning the current will be very low and no significant amounts of energy will be generated.

The only time that the inverter and the wiring on the dc side will see open-circuit voltage is when the dc disconnect is opened and then closed or the inverter is turned off or the inverter loses ac power.

All listed equipment is tested at twice the rated voltage +1000 V as a high potential test. For a 600 V module and 600 V wiring the test is 2200 V. Modules and wiring will normally not be damaged if operated slightly above the maximum rated voltage, although this would be a code violation [110.3(B)].

However, inverters are not as robust, and I personally have damaged a 600 V rated inverter at 604 V. This is the area of concern: Will cold weather subject the dc input of the inverter to a voltage above its rated value (frequently 600 V)? Be advised, some inverters have a maximum voltage of only 500 V or 550 V. It always pays to read the manual.

Multiple Events. In the real world, the following conditions have to occur simultaneously in order for the inverter to see voltages above maximum rated voltage. The temperature has to be at or below the expected low temperature being used in the calculation of Voc; there has to be sufficient light on the PV array (and that does not require direct illumination by the sun); and the dc disconnect must be opened and closed, or the inverter turned off, or the ac power disconnected or not present.

The lowest temperatures occur in the early morning hours and since the PV array has cold soaked all night long, it will be at that temperature for some period of time after the minimum temperature occurs. Also, on clear nights you have night-sky radiation that will lower the temperature of the PV array a few degrees Celsius (2 or 3 degrees) below the measured low ambient temperature.

In these early morning hours, there will usually be very little if any module heating because the sun is not directly shining on the PV array. Indirect sky illumination and cloud-scattered illumination may be sufficient to bring the module voltage up to full rated Voc for that temperature.

Also, there can be very cold, windy days in bright sunshine where the wind removes all heat from the PV modules and if the circuit is interrupted and then restored, the inverter can be subjected to a high Voc.

So, there is a probability function involved with these occurrences that will be very difficult to estimate. Also the record low may not be ever seen again in the area or, on the other hand, future variations in temperature may exceed that number.

But the Unexpected Happens. In warm, sunny Las Cruces, NM, where I live, most PV systems are designed for an expected low of 14–15°F. However, in February 2011, the temperature went down to -2°F for several days with rolling power blackouts that kept turning the numerous installed PV inverters OFF and ON. Fortunately, the blackouts did not occur until late afternoon and the PV arrays had been heated by the sun to temperatures in the 40–60°F ranges, resulting in open circuit voltages significantly below the rated voltages of the equipment. See photo 5.

Pick a Source. In choosing an expected lowest temperature, several methods are available—none explicitly required by the NEC. Another gray area for the AHJ.

A conservative estimate would be to use the local weather data to get the record low. This information is available from various sources on the web as well as www.weather.com. The ASHRAE Handbook—Fundamentals has data low temperatures that gives the frequency of the temperature variations that occur in a given area (Informational Note: 690.7). Also, the local weather station can provide the last 10 years of weather data and this data can be used to determine the average low and the trend on those low temperatures.

AHJ Decision? Some AHJs and jurisdictions require that the record low be used. Maybe they are not sure that Global Warming exists. Other AHJs allow the systems installer/designer to pick the expected low temperature and justify it.

 Photo 5. Unexpected very cold weather

DC-to-DC Converters

Several dc-to-dc converters are already on the market and more will be coming in future months. Most of these are separate boxes that are attached to the module leads and the output conductors are connected in series to make a string of modules. However, at least one, and possibly more, of these dc-to-dc converters will be installed directly in or replace the module junction box on the back of the PV module. See photo 6.

Photo 6. Smart Module by Tigo Energy.

In most cases, these dc-to-dc converters decouple the output of the module from the circuit going to the inverter. And each of these dc-to-dc converters has different characteristics with respect to the ratings of input and output circuits and the amount of isolation or decoupling from the module output. The NEC, even in 2014, will have few details on how these dc-to-dc converters must be installed.

It will not be possible to use sections 690.7, 690.8 and 690.9 which are based on module output characteristics to determine how these devices are to be treated in a PV system. At this point it appears that the only way the inspector has to deal with them is to use NEC Section 110.3(B). Each of these certified/listed products must be installed in a manner consistent with the instructions provided with the products. And unfortunately, there are going to be gray areas in those instructions and in the lack of specific requirements in the Code—or possibly due to existing requirements in the Code.

As an example: a dc-to-dc converter may have a maximum output of 60 V, and up to 15 of these converters may be connected in series to make a string. However, the interaction between the converter and the required matching inverter in the system restricts the maximum string voltage to 500 V by restricting the output of each converter to 40 volts. But here is the gray area: 15 x 60 = 900 V. Applying normal code procedures and requirements would tend to require that 900 V or 1000 V conductors and equipment would be needed. However, the instruction manual accompanying this listed device says that the "smart” inverter has been evaluated as a system with the dc-to-dc converter to fully maintain the correct voltage on the system in a safe manner and that the system has fail safe features that will ensure that the string voltage is never higher than the equipment limit.

Now and more so in the future, inspectors will have to read and become totally familiar with the installation manuals of current and new equipment. Only in this way, can the inspection community ensure the safety of the public.

For More Information

The author has retired from the Southwest Technology Development Institute at New Mexico State University, but is devoting about 25% of his time to PV activities in order to keep involved in writing these Perspectives on PV articles in IAEI News and to stay active in the NEC and UL Standards development. He can be reached, sometimes, at: e-mail: jwiles@nmsu.edu, Phone: 575-646-6105

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: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html It should be updated to the 2008 and 2011 NEC before the 2014 NEC arrives.

PV Plus Batteries Means Power When the Utility Goes Out

These backup systems allow the owners to operate some or all of the loads in the building using a specially designed and configured PV system with batteries in the absence of the utility service. These systems can be as small as a system that can power a radio or cell phone charger. They can also be as large as necessary to run all appliances and loads in a residence or commercial building. The size and number of electrical loads that can be operated and the period of time they can be operated depend on the size of the photovoltaic power system, the size of the battery bank, and the size of the specialized inverter.

Photo 1. Battery-backed-up, utility-interactive PV system during installation

There are characteristics of these PV systems with batteries that are different from those relating to the standard utility-interactive PV system. Obviously, the batteries pose some unique problems that the inspector must review and the connection of the inverters to not only the electrical system in the house but also to the utility requires looking at some different code sections than are normally used.

The multimode inverter that is used has characteristics of both the utility-interactive inverter and the standalone, off-grid inverter with features that are unique to the multimodal inverter. These inverters will be listed to UL Standard 1741. These inverters will have two sets of ac input/output terminals and a connection for the battery bank. Photo 1 shows the batteries and the multimode inverters in a system being installed.

Figure 1 shows the basic elements of a battery-backed-up, utility-interactive PV system. Green arrows represent dc power/energy flow and red arrows represent ac power/energy flow. Double-headed arrows represent bidirectional power/energy flow.

Figure 1. Components in a battery-backed-up, utility interactive PV system

DC-Coupled Battery Charging

There are two main types of battery-backed-up, utility-interactive PV systems. The first and oldest is what is called a dc-coupled charging system. As shown in figure 2, the PV array has a nominal voltage of 24 volts or 48 volts and normally operates through a charge controller to charge a battery bank. The battery bank is connected to a multimode, utility-interactive inverter and that multimode inverter is connected to the house loads and to the utility using two separate and distinct ac input/output circuits. When the utility is present, the PV system charges the batteries through the charge controller; and power is taken from the batteries (or directly from the PV system when the batteries are fully charged) through the multimode inverter where it is converted to ac power.

Figure 2. DC-coupled system interconnections and power flows

The designated protected (backed up) loads may be supplied by either the utility (when present) or the PV inverter output (supplied from the batteries when the utility is absent). Where the PV system power output exceeds the building loads, the excess energy is fed into the utility and renewable energy credits (REC) or net-metering benefits may be accrued. At night or at other times when the PV production is low, power for the loads is purchased from the utility and fed to the main loads through the main panel or through the multimode inverter to the protected loads. In general, the battery stays fully charged at all times but there are some systems in which the stored energy in the battery can be sent ("sold”) to the utility with proper programming of the equipment.

When the utility is not present, the PV array and battery combination and the multimode inverter continue to operate the loads connected to the protected loads subpanel to the extent that the size of the PV system and the capacity of the battery bank can supply the energy required by those protected loads. The multimode inverter will not send power to the main (unprotected) loads or to the utility connection but continues to monitor that utility connection for voltage and frequency. And, the main panel gets no power from any source. When the utility comes back online with the proper voltage and frequency characteristics, the multimode inverter will reconnect and the system becomes utility interactive once again. Photo 2 shows a dc-coupled battery charging system. The three charge controllers are on the right and the four inverters are in the center between the ac and dc distribution panels.

Photo 2. DC-coupled system

AC-Coupled Battery Charging

Figure 3 shows a more recent type of system, known as ac-coupled charging system, where the PV modules are usually configured in a high voltage string configuration (200–600 volts) and provide dc voltage to a standard utility interactive inverter. The output of the utility-interactive inverter(s) is connected to the protected load subpanel with a backfed breaker [705.12(D)] and that subpanel is connected to the load ac input/output terminals of the multimode inverter. The battery again is connected to the multimode inverter dc input/output. The utility is connected to its unique ac input/output on the multimode inverter and when the utility is present, it feeds through the multimode inverter generally keeping the batteries charged at all times and providing energy to the protected load subpanel. The utility interactive inverter sees the proper voltage and frequency supplied by the utility and continues to convert dc PV energy into ac energy that can be used by the loads (both protected and main) and also be fed to the utility. When the utility goes down or has a brown out (voltage and/or frequency variation), the multimode inverter senses this and stops sending power to the now unenergized utility lines (and the main load panel) but continues to monitor them for proper voltage and frequency, which would indicate that the utility is back online. At this time, on the load ac input/output of the multimode inverter, the battery supplies energy to the inverter and it will become the correct frequency and voltage reference source to supply not only the protected loads, but also to keep the utility interactive inverter connected to the PV system, operating and producing energy (in the daytime).

Figure 3. AC-coupled system interconnections and power flows

Again, the amount of loads that can be connected and operated for any short period or long period of time depends on the size of the PV array and the capacity of the battery bank. Typically the PV array may only supply energy for 4 to 6 hours per day. Loads obviously can operate 24 hours a day, so the total amount of PV array energy that can be stored in the battery and the capacity of the battery and size of the inverter determine how long the loads can be operated and how many loads can be connected at any one time.

Photo 3 shows an ac-coupled, battery-backed-up, utility-interactive system. The gray utility-interactive inverters are above the yellow multimode inverters and the batteries are in the rear of this very compact installation. There is normally a clear insulating service panel in front of the batteries; the panel was removed when the photo was taken.

Photo 3. AC-coupled system

In either case, with dc charging or ac-coupled charging of the batteries, the certified/listed multimode inverter ensures safety for the power line and utility personnel at anytime the utility is shutdown or operates abnormally.

Battery Considerations

Batteries, although not considered a source of energy, can store considerable amounts of energy. They should not be considered current-limited sources like PV modules are, but have the characteristics of a constant voltage output like an ac feeder with large amounts of available short-circuit current. Batteries must have overcurrent protection and disconnects on the output cables. The current between the battery and the multimode inverter is bidirectional. It flows to the batteries when the batteries are being charged by the multimode inverter or the charge controller, and it flows from the batteries when the multimode inverter is in the inverting mode supplying the protected loads with ac power.

In the dc coupled charging system, the cables between the charge controller and the battery are sized based on the rated output of the charge controller irrespective of the size of the PV system feeding it. These conductors should be sized at 125% of the rated output current of the charge controller. There should be an overcurrent device and a disconnect at the battery end of the circuit to protect these cables from high short-circuit currents originating at the battery. Depending on the location of the charge controller with respect to other components, there may be disconnects required on the input and output of the charge controller. A main PV dc disconnect located between the PV array and the charge controller will be required complying with 690.14.

Available short-circuit currents. The battery banks used in these types of systems typically will have an available short-circuit current at the output conductors from the battery bank less than 15,000 A. Cable lengths, connections, and cable resistances limit the available short-circuit current. Any overcurrent devices and/or disconnects must have ratings that can handle currents of this magnitude. Current-limiting fuses and dc rated circuit breakers are generally available with sufficient ratings and should be used.

Conductors. The conductors between the battery bank and the multimode inverter must carry bidirectional currents. The multimode inverter will use utility power or power from the utility interactive inverter in AC coupled systems to keep the battery charged and currents will flow from the inverter to the battery. When the multimode inverter is operating in the inverting mode and supplying protected loads with energy, the currents will flow from the battery to the multimode inverter. In general, the discharging currents flowing from the battery to the inverter will be larger than the charging currents flowing from the inverter to the battery. This is because the typical multimode inverter will be able to draw more current from the battery than it can provide to charge the battery. Therefore, the cables between the batteries and the inverter must be sized based on the maximum rated output of the multimode inverter in the inverting mode of operation. This continuous current should be specified in the inverter specification/installation manual and the cable sized at 125% of this continuous current. Of course, the battery cables should be in a raceway along with an equipment-grounding conductor, which would be used to ground any metallic battery rack and battery disconnect or overcurrent device enclosure. The size of the equipment-grounding conductor would be based on the rating of the overcurrent device protecting the circuit.

Many pre-manufactured battery cables are made with fine-stranded cables consisting of type AWM (appliance wire material) conductors. These cables are not suitable for use in battery PV systems since they are not mentioned directly in the National Electrical Code as one of the Chapter 3 wiring materials suitable for field installed wiring. The use of these manufactured cables is a gray area and could be considered an AHJ decision. And, in many cases automotive battery cables and welding cables have been used but these are typically fine stranded conductors which are very difficult to terminate properly at conventional disconnects and circuit breakers and they are not allowed in this application by the Code. See the find-stranded cable warning in Section 110.14 in the 2011 NEC. Also see the IAEI News article, "Do You Know Where Your Cables Are Tonight?” in the January–February 2005 issue.

Battery Circuit Overcurrent Protection and Disconnects. An overcurrent device should be located at the battery end of the circuit to protect this conductor from high available fault currents from the battery. This overcurrent device will be sized at 125% of the multimode inverter rated dc current in the inverting mode which is the same number used to size the cables. An overcurrent device at the inverter end of the circuit is normally not required because the inverter typically cannot source the same high fault currents that the battery can. A battery disconnect should be installed at the battery end of the circuit. Normally, if the inverter is within 4 to 5 feet of the battery bank, it is not practical or possible to put a disconnect any nearer to the battery than this distance. Therefore, the disconnect for this circuit can be near or at the inverter—usually in a power center. However, if the distance between the battery and the multimode inverter is more than 4 to 5 feet or the inverter is located in a different room than the battery bank, then there must be a disconnect at the battery end of the circuit in addition to the overcurrent protection required at that location. Photo 4 shows a battery disconnect/overcurrent protection enclosure using circuit breakers mounted just above a valve regulated (sealed) battery bank. These batteries release no hydrogen gas or acid fumes during normal operation.

Photo 4. Battery disconnect and overcurrent protection located near the batteries

Grounding. The nominal battery voltage in these systems is 48 V DC. The operating voltage may be as high as 62 to 65 V. Normally the multimode inverters do not ground one of the battery circuit conductors and the NEC requires that one of the battery circuit conductors be connected to earth with a grounding electrode conductor (690.41).

If the system uses DC coupled battery charging, the connection to Earth will be usually done through a distinct and separate ground fault detection/interruption system (GFDI) as required by NEC Section 690.5. In some cases the charge controller may have this GFDI built in.

On an AC coupled system the utility interactive inverters will have their normal GFDI internal circuitry, which will usually ground one of the PV array output conductors. But in the ac coupled systems, the dc battery circuit will still have to be grounded to keep costs down and to be compatible with available equipment that has been designed for use in grounded systems.

AC Circuit Considerations

Multi-wire branch circuits. Many houses today have several multi-wire branch circuits that have two branch circuits with a shared neutral conductor and are wired with a 14–3 AWG/with ground type NM cable. Multimode inverters come with either 120V AC outputs or 120/240V AC outputs. Neither of these multi-mode inverters should be connected to load circuits in the building that are part of a multi-wire branch circuit. See NEC 690.10(C). The inverters in the inverting mode, in some cases, may not be in synchronization with the utility power frequency waveform. This could cause overloading of the shared neutral that is associated with multi-wire branch circuits. If any of the circuits needing battery backup power protection are multi-wire branch circuits they should be segregated in their entirety (both circuits) in the special protected loads load center that is connected to the multimode inverter ac output.

Utility connections. One of the characteristics of most of the multimode inverters is that they can pass power from the utility through to the protected load circuits at a greater power level then they can supply power to the utility in the utility interactive mode. This indicates that the circuit and the overcurrent device, typically a breaker, between the utility connection and the multimode inverter must be rated at the full pass-through current capability of the inverter. A common value of this circuit breaker would be 60 or 70 amps. However, in the utility interactive mode, the inverter may only be able to source 33 amps from the PV system into the utility. In previous editions of the code, the 60 or 70 amp breaker would be used in the 705.12(D) calculations to determine panelboard/load center busbar ratings and conductor sizes. But, the danger to the circuit from overloading is related to the 33-amp output of the inverter when feeding the utility. Now, an exception to NEC Section 705.12(D)(2) allows the calculations for this requirement to be based on 125% of the rated utility interactive inverter output in the utility interactive mode. In this example, 41.25 amps (1.25 x 33) could be used in the calculations. And the circuit breaker connecting the inverter to the load center can still be rated at the higher 60 or 70 amps required to allow the protected loads to be operated in the pass-through mode of operation.

Summary

Aside from the battery circuits and the unique characteristics of the utility interconnection covered above, the multimode inverter in the battery backed up, utility-interactive PV system is connected to the utility in much the same manner as any normal utility interactive system. The dc PV circuits are connected in the same manner as those circuits in a standard utility interactive PV system for the ac coupled system. The dc-coupled systems require additional considerations for the low-voltage battery charging circuits.

For More Information

The author has retired from the Southwest Technology Development Institute at New Mexico State University, but is devoting about 25% of his time to PV activities in order to keep involved in writing these Perspectives on PV articles in the IAEI News and to stay active in the NEC and UL Standards development. He can be reached, sometimes, at: E-mail: jwiles@nmsu.edu Phone: 575-646-6105

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: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html

It should be updated to the 2008 and 2011 NEC before the 2014 NEC arrives.

Read more by John Wiles

Many AHJs are familiar with the 120% allowance on busbar and conductor size allowed by 705.12(D)(2). Less familiar is the 705.12(D)(7) requirement that must be met before the 120% can be applied.

We typically, but not always, apply these requirements to a load center (photo 1). And if the backfed PV connections do not meet NEC requirements in 705.12(D)(7), problems can arise. In this load center rated at 100 amps with a 100-amp busbar, four 15-amp backfed PV breakers have been added at the top of the load center adjacent to the main breaker. If the panel were filled with load breakers and the loads on the panel were increased (during daylight hours) to 160 amps (for example), the load center busbar could see 160 amps, somewhat in excess of its rating. No breakers would trip since the main breaker could supply 100 amps from the utility and the PV breakers could supply an additional 60 amps from the PV system for a total of 160 amps.

Photo 1. Load Center/Panelboard. Rated at 100 amps with 160 amps of supply breakers

Before we look at the overall requirements. Let us focus on a few of the details and those details will need some explanation.

Many PV installers and a few AHJs do not understand the significance of the 705.12(D)(7) requirement. If this backfed PV breaker location requirement is not met, then the 120% allowance in 705.12(D) cannot be used and many PV systems could not be installed. But what is so important about the location of the backfed PV breaker in the panelboard/load center?

Look at the simplified one-line schematic of a 100-amp load center in diagram 1. For simplicity, only one busbar, ½ of a 2-pole main breaker and a set of 15- and 20-amp load breakers on that busbar is shown.

Diagram 1. Simplified load center diagram

The busbar in this 100-amp load center is also rated at 100 amps. It should be noted that the total rating of the load breakers on this busbar will typically exceed the busbar and the main breaker rating in normal dwelling and commercial installations. In the example, the breaker ratings total 225 amps. Although there are both fixed loads and plug loads in a typical structure and the fixed loads are used in the NECChapter 2 load calculations, the plug loads are estimated, but are otherwise not constrained or restricted, at least until they reach the branch circuit breaker rating.

If the total load currents (45+35) on the panel stay below the 100-amp rating of the main breaker and the bus bar, they are "happy” (stay cool with no trips) as shown in diagram 2.

Diagram 2. Happy load center with total loads less than 100 amps

But as consumers, we must have that new 96″ wood lathe, that 130″ two-wall flat screen gaming system, two new color laser printers, the plug-in electric car and a few other toys. The loads on each branch circuit would typically stay below the breaker rating, but if one load does exceed the rating, that breaker will trip. See diagram 3.

Diagram 3. Circuit breakers protect branch circuits

While the individual loads may stay below 15 or 20 amps, the total could go to 120 amps when everything is running. In a short time, the 100-amp main breaker will trip and the busbar may get a little warm at the top, near the main breaker. But, the main breaker will protect the busbar and possibly the service conductors from over loading. See diagram 4.

Diagram 4. Total load currents exceed 100 amps and the main breaker trips, protecting the busbar.

Now in diagram 5, a 20-amp backfed PV breaker has been added to the first breaker position at the top of the load center adjacent to the main breaker. As shown, the loads may total 80 amps and 20 amps are supplied by the PV system and 60 amps from the utility. Nothing is overloaded and the components stay cool.

Diagram 5. No problems with this connection… yet.

Now let’s assume that the total loads are 120 amps during the day when the sun is shining brightly, the PV breaker can supply 20 amps and the main breaker can supply 100 amps. Yes, I know that these breakers should only be handling 80% of rating, but bear with me for this example. None of the load breakers trip, the main breaker is happy, but the busbar is probably getting a little warm since it is carrying 120 amps just below that backfed PV breaker. I am assuming that the 15-amp breaker at the top right is not contributing to the load currents. See diagram 6.

Diagram 6. Loads increased, busbar overloaded

Warm busbars that operate over their intended design temperature (40 degree Celsius(C) plus normal current heating) will not melt, but they may cause overheating and softening of the plastic insulators in the load center and those insulators may allow various current-carrying parts to touch each other or ground. The NEC requirements are intended to address this potential overheating issue.

Diagram 7. PV breaker located per 705.12(D)(7) so no current overloading of the busbar is possible.

In diagram 7, the backfed PV breaker is moved to the lower left position as far as possible from the main breaker. The PV breaker can supply 20 amps, the main breaker can supply 100 amps and the total loads can be as high as 120 amps. As before, no breakers will trip, but in this case, the currents from the PV breaker and the main breaker have nowhere to add together as they jointly supply the load currents. At most, any section of the bus bar will see only 100 amps, no matter where the loads are placed or occur on the busbar. Although not possible, visualize a 120-amp load could be placed in the first breaker position just below the main breaker. The busbar section between the 100-amp main breaker and the 120-amp load breaker circuit would carry 100 amps. The remaining 20 amps would come up the busbar from the 20-amp back fed PV breaker. If the 120-amp load were concentrated just above the PV breaker, the busbar would supply 100 amps from the main breaker and 20 amps from the PV breaker. In both cases, the busbar would see no more than 100 amps.

Diagram 8. Center-fed panel has no place for PV that will prevent busbar overloading.

So this is the reason that 705.12(D)(7) requires that the backfed PV breaker be located as far away from the utility sourced breaker on the busbar or the conductor.

Center-Fed Panels Are a NO GO.

Unfortunately, center-fed load centers are common in many parts of the country.

In diagram 8, one busbar of a center-fed load center is shown. The 100-amp main breaker feeds the center of the 100-amp rated bus bar and the load breakers are arranged above and below (or sometimes horizontally to each side) of the main breaker. With this diagram, it is fairly easy to see that, there is no position on either the upper or lower busbar that will keep the currents from the PV breaker adding to the currents from the utility breaker on the portion of the busbar that is opposite the busbar where the main breaker is added. Of course loads on the half of the bus bar that has the PV breaker would normally absorb the current from the PV input before it could overload the other portion of the busbar. But, there will be times when the electrical loads are not evenly distributed and there is the possibility of busbar overloading when center-fed panels are involved. It is expected that the 2014 NEC will have a warning about the use of center-fed panelboards.

SUMMARY

The NEC language is sometimes difficult to read and understand. However, in many cases, like this one, the Code is based on sound engineering and establishes requirements that help to ensure the safety of the public. These PV connections can and must be done correctly. See Photo 2.

For More Information

If this article has raised questions, do not hesitate to contact the author by phone or e-mail. E-mail: jwiles@nmsu.edu Phone: 575-646-6105

See the web site below for a schedule of presentations on PV and the Code. Call the author if you would like to schedule a presentation.

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: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html

Read more by John Wiles

Here are some examples of such systems.

Electric Gate Openers

PV-powered electric gate openers are becoming more common because they are reliable, easily installed, and do not require trenching a branch circuit from the nearest building to the possibly remote gate location. See photos 1, and 2. These openers have many different designs and may employ a battery to allow operation at night and during cloudy weather. Normally the products are sold as a kit and installed by the building owner, the fencing contractor or others. In some cases, an electrician is involved.

These systems, when powered by a PV module will involve field-installed wiring and connections. The voltages are usually 12 or 24 volts dc and the batteries are typically automotive-sized, deep-cycle batteries. The system components rarely comply with NEC requirements in terms of listed modules, listed charge controllers and code-compliant wiring, disconnect, overcurrent protection and grounding. The contents of the entire kit or the electrical components have not been certified/listed in most cases. The AHJ must make the call on whether time is available to inspect these systems and whether or not they should be permitted. Few, if any, would pass an inspection for compliance with the NEC.

Photo 1. PV-powered electric gate; no trenching required

Photo 2. PV-powered electric gate. Courtesy MightyMule/GTO

Solar Hot Water Systems

Many solar hot water systems have been and are being installed throughout the country using a PV module to power the circulating pump. The combination of a PV-powered pump with a solar collector works well since bright sun results in more hot water and also causes the pump to run faster, transferring that hot water to the storage system. The PV module(s) can have a power of 10–30 watts and higher with voltages from 12 to 24 volts (nominal). See photo 3. Field-installed modules, pumps and controllers are used and, in most cases, the equipment is not listed or installed in compliance with NEC requirements. There are typically no considerations given to module grounding, proper disconnects and ground-fault protection. Conductors from the pump to the roof frequently do not meetNEC requirements for such circuits. Plumbing or combination inspectors should also examine the electrical circuits for compliance with NEC requirements.

Photo 3. Solar water collector and PV modules connected to the circulating pump

Construction Signs and Crossing Lights

Long gone are the small diesel or gasoline engine-powered generators powering the warning signs at highway construction sites. PV modules and batteries have replaced those noisy, polluting power sources and these systems are used throughout the country. But the PV connection is not noticed since the PV modules are usually out-of-sight (photo 4). School crossing and speed signs are also being powered by a PV module or two because such a system is cheaper than running utility power feeders along the highways. And there are the red light cameras and radar speed traps that are PV-powered.

These systems are usually manufactured as a single device that is already assembled and is, in many cases, portable. There are no field connections to make and inspections are usually not justifiable.

PV-Powered Air Conditioning

While there have been a few dc PV-powered air conditioners on the market, Lennox Industries has been marketing their Dave Lennox Signature SunSource heat pump and air-conditioning systems for more than a year. These systems have a set of AC PV modules connected to the outdoor compressor unit and the AC PV modules act as a utility-interactive PV system supplying the outdoor unit and feeding power into the building wiring system. When the local loads are less than the PV ac modules output, the excess is sent to the utility. The systems are available for both residential applications (photos 5 and 6) and commercial applications (photo 7). The outdoor compressor units have a factory-installed PV power combiner panel installed that has the necessary overcurrent devices required byNEC Section 705.12(D) (photos 8 and 9).

Photo 5. Residential Lennox SunSource HVAC system. Courtesy Lennox Industries

Photo 6. Lennox XC-21 SunSource Air Conditioning Outdoor Unit

The size of the AC PV module array will vary with the customer’s budget and desires. Usually, in the residential applications, a single string of modules on a 15- or 20-amp circuit will be connected to a circuit breaker of that rating in the PV panel on the outdoor unit. And within the limited available space, the number of modules can be expanded from 1 to 15–17 depending on rating of the circuit and the rating of the AC PV module (photo 10).

Yes, these systems involve electrical connections above and beyond electrical wiring of the installation for the HVAC unit, and they should be permitted and inspected. The ac wiring is usually routed from the modules though a utility-required, readily accessible lockable disconnect and then to the PV breaker on the HAVC outdoor unit. There is no dc wiring to contend with and the equipment grounding of the module frames and the attached microinverters is made at a single point of one of the modules since they are all electrically and mechanically bonded together.

Photo 8. Lennox XC 21 PV power input panel

Photo 9. Backfed PV breaker in power panel on outdoor unit

Photo 10. Four AC PV modules installed with expansion room for more modules

Large Systems in Remote Areas

Numerous large (megawatt and up) PV systems are being installed in remote areas on otherwise unused land or even on the unused and available flat roofs of very large buildings (photo 11). These systems will use multiple inverters rated from 500 kW to two megawatts each. In the case of ground-mounted systems, a fence will usually surround the entire array and all equipment with locked access. Large arrays on a building will also have limited access.

Photo 11. One megawatt PV array on a single building

At this point, the AHJ should review section 90.2 of the NEC to determine if this system comes under the requirements of the NEC. Large PV systems may be utility-owned, utility-operated and located on utility property and these systems are not required to comply with NEC requirements. A utility is defined and regulated by state law. However, many of these large systems are not owned or are not being operated by a utility on utility property. They are power purchase agreement (PPA) systems that are installed and operated by third parties. They must comply with the requirements of the NEC and any local codes. Although these systems are frequently referred to as being "behind the fence,” this term has no meaning in the NECand all NEC requirements should apply. Inspections of these larger systems may find numerous safety and code violations.

Summary

Time and funds in most jurisdictions are limited. The AHJ must evaluate the workload carefully and apply knowledge and inspection talents wisely to ensure the public safety. Not all PV systems can or should be inspected but those that can pose the most potential hazards should be high on the list.

For More Information

If this article has raised questions, do not hesitate to contact the author by phone or e-mail. E-mail: jwiles@nmsu.edu Phone: 575-646-6105

See the web site below for a schedule of presentations on PV and the Code. Call the author if you would like to schedule a presentation.

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: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html

Read more by John Wiles

The Standards Development Process

For each of the major standards that UL publishes, a Standards Technical Panel (STP) is established and the STP actually controls the content of the standard through a rigorous process known as the Collaborative Standards Development System (CSDS). The STP membership consists of a balanced selection of representatives from all areas of interest that are involved in the product that the standard addresses. The STP for UL 1703 has more than 50 members from PV module and material manufacturers, PV installers and systems designers, electrical inspectors and plan reviewers (including IAEI members), users, NFPA Code-Making Panel members, IBEW, laboratories, government agencies, universities, and a general interest area.

ll parts of the standard are continually reviewed, analyzed with respect to Code changes and new equipment developments and discussed. Anyone may make proposals for changing the standard. The proposals are circulated, revised, re-circulated and voted on by the STP members. Negative votes must be accompanied by suggested changes and all negative votes must be addressed. UL, as a member of the STP, has only one vote just like all other members.

Photo 1. Top of frame module mounting. Listing is valid only if the method is in the instruction manual.

The STP meets about once a year, but may be convened more frequently as the need arises.

Safe Installations

When equipment is manufactured according to the requirements in the standard and is evaluated by one of the National Recognized Testing Laboratories (NRTL), it can be then certified as complying with the standard and the product is put on a list showing that certification. This is the Certification/Listing process. In the NEC, PV modules, charge controllers, inverters, combiners and ac PV modules are required to be listed. Currently, the US Occupational Safety and Health Administration (OSHA) has recognized four of the numerous NRTLs as capable of certifying and listing PV equipment. They are UL, TUV Rheinland NA, Intertek (ETL), and CSA International.

Certified/listed equipment, when installed according to the requirements established by the NEC will generally result in a hazard free electrical installation.

What’s New for Inspectors and Plan Reviewers?

AHJs around the country have been aware for some time that consistency in the PV module instructions manuals has been lacking. These inconsistencies stem from a lack of preciseness in UL 1703 in the areas of module mounting, module grounding, and the way the rated short-circuit current and module open circuit voltage are to be used in the application of NEC requirements to the module installation. Module manufacturers have widely varying instruction manuals in terms of content and detail. They issue tech notes that address mounting and grounding the modules, but it is unclear whether or not these tech notes have been reviewed by the certifying/listing NRTL for compliance with the standard.

Photo 2. Improper module grounding has failed.

Modules are generally tested, labeled, and listed with four mounting holes that are to be used for bolting the modules to the mounting surface. However, many installers use mounting racks that use clips that fasten the modules to the racks by clamping the top of the module to the rack with these clips which generally are not located near the four mounting holes. See photo 1. A few module manufacturers have instruction manuals that specify that top clips may be applied at certain locations on the modules, but most do not have these instructions.

Grounding issues abound for plan reviewers and inspectors and many module grounding systems are failing around the country. See photo 2. Typically a module has four labeled grounding holes that have been tested to meet UL 1703 requirements for safe connection to earth through the equipment-grounding system. Again module instruction manuals and tech notes vary greatly in the level of detail associated with using the labeled grounding holes to ground the PV modules. A few manufacturers supply hardware that has gone through the UL 1703 testing and evaluation process with the modules. Some manufacturers specify locally procured hardware like star washers and nuts and bolts to ground modules. See photo 3. Others provide very sparse instructions on grounding. And the content of tech notes ranges from very good to very poor with respect to grounding.

Photo 3. Correct hardware?

Since the inception of UL 1703, the standard has required that each PV module instruction manual have statements requiring that the short-circuit current (Isc) and the open-circuit voltage (Voc) be multiplied by 125% before any NEC requirements were applied. The 125% on Isc was to address normal and expected high levels of irradiance up to 1250 watts per square meter that can occur in many areas of the country for three hours or more. The 125% factor applied to the rated Voc was to address the fact the module voltage decreases as temperature increases, and this factor accounts for modules exposed to temperatures as low as -40°C (-40°F). In 1996, during deliberations for the 1999 NEC, all parties including the PV Industry, UL, AHJs, and the Code-Making Panels at NFPA agreed that these 125 factors should be removed from UL 1703 and placed in the Code.

They were placed in the 1999 NEC in 690.7 (Voc) and 690.8 (Isc), but until this revision of UL 1703, they have remained in the standard. Of course, looking at NEC 110.3(B) that requires the instructions with the listed product to be followed that duplicated the requirements of NEC Sections 690.7 and 690.8 created a very poor situation for the AHJs and the installers. Do we duplicate those 125% factors, which have been required in both the instructions and in the Code?

Current Revisions to UL 1703 Have Clarified Several Areas

In general, it is evident that previous editions of UL 1703 have not provided sufficiently detailed requirements to the NRTLs to allow them or require them to properly evaluate the instruction manuals for the PV module in terms of NEC-compliance, mounting, grounding, and the specifications related to the electrical parameters.

Photo 4. Module fire rating valid for this mounting?

The May 8, 2012 revision of UL 1703 has addressed several of these longstanding issues.

1. The NRTL must verify the contents of the manual and NEC-compliance.

These revisions now include a requirement that the certifying/listing organization verify that the contents of the instruction manual and any tech notes comply with the standard and do not violate any NEC requirements. Here are a few of the relevant revisions extracted from UL 1703:

48.1 "A module or panel shall be supplied with installation instructions describing the methods of electrical and mechanical installation. The instructions shall include the following in addition to any other information required by this standard:

c) "A list containing the date of the first edition of these instructions and the dates of any and all subsequent revisions, amendments, and tech notes related to these instructions.”

48.1.1 "The electrical installation instructions shall include a detailed description of the wiring method to be used in accordance with the National Electrical Code, ANSI/NFPA 70.”

48.7 "The contents of the instruction manual and subsequent revisions to the instruction manual shall be verified for compliance with this standard by inspection.”

2. The 125% factors have been removed from the module instruction manual.

48.5 "To allow for increased output of a module or panel resulting from certain conditions of use, the installation instructions for a module or panel shall include the following statement or the equivalent: "Under normal conditions, a photovoltaic module is likely to experience conditions that produce more current and/or voltage than reported at standard test conditions. The requirements of the National Electrical Code (NEC) in Article 690 shall be followed to address these increased outputs.”

3. A module not mounted in accordance with the instructions in the manual will no longer retain its UL 1703 listing. This emphasizes the NEC requirement in 110.3(B).

48.1(B) 2) "The module is considered to be in compliance with UL 1703 only when the module is mounted in the manner specified by the mounting instructions below.”

4. A module not mounted per the mounting instructions will invalidate the fire rating on the module. See photo 4.

48.1(B) 1) "The fire rating of this module is valid only when mounted in the manner specified in the mechanical mounting instructions.”

5. A module not grounded according to the grounding instructions in the manual and not in accordance with the labeled grounding points on the module will invalidate the listing on the module. See photos 5 and 6.

48.1(B) 3) "A module with exposed conductive parts is considered to be in compliance with UL 1703 only when it is electrically grounded in accordance with the instructions presented below and the requirements of the National Electrical Code.”

Photo 5. Right grounding point; wrong hardware and method.

Those grounding instructions include the following:

48.1.1 a) "The grounding method to be used, and where a specific grounding device is supplied or suggested, the following statements:

1) "Where common grounding hardware (nuts, bolts, star washers, spilt-ring lock washers, flat washers and the like) is used to attach a listed grounding/bonding device, the attachment must be made in conformance with the grounding device manufacturer’s instructions.

2) "PV module manufacturers recommending such a method must either 1) thoroughly detail the attachment means in the module installation instructions or 2) refer the installer to readily available manufacturer’s instructions for the grounding/bonding device.

3) "Common hardware items such as nuts, bolts, star washers, lock washers and the like have not been evaluated for electrical conductivity or for use as grounding devices and should be used only for maintaining mechanical connections and holding electrical grounding devices in the proper position for electrical conductivity. Such devices, where supplied with the module and evaluated through the requirements in UL 1703, may be used for grounding connections in accordance with the instructions provided with the module.”

6. A PV laminate without a frame is not considered a listed module until it has been mounted with hardware that has been evaluated with the laminate under this standard or has been subject to a field evaluation by an NRTL.

4) "Any module without a frame (laminate) shall not be considered to comply with the requirements of UL 1703 unless the module is mounted with hardware that has been tested and evaluated with the module under this standard or by a field inspection certifying that the installed module complies with the requirements of UL 1703.”

7. The value of module series overcurrent device marked on the back of the module now has to be at least 1.56 times the Isc in order to comply with NEC 690.8.

47.10 "A module or panel shall be marked relative to the maximum electrical rating of an acceptable overcurrent protective device (for protection against backfeed). The statement on the module or panel shall include the following: ‘Maximum series overcurrent protective device, where required.’ ”

47.10.1 "The ampere rating of the maximum series overcurrent device shall be not less than 1.56 times the rated short-circuit current of the module and the rating shall be rounded up to the next higher available overcurrent device rating. The available ratings are 1–10 amps in one-amp increments, 1.5, 2.5, 3.5, 12 amps, 15 amps, and 20 amps. The rounded up rating of the series overcurrent protective device shall be used in the reverse current tests of 28.1.”

Photo 6. Modules being grounded correctly

These revisions to UL 1703 should clarify the intent and requirements for installing PV modules in a PV system that is compliant with the requirements of the National Electrical Code. The revisions are dated 8 May 2012 and it may take a few months for the module manufacturers, the rack manufacturers and the grounding device manufacturers to work together to get the necessary testing done and to revise the instruction manuals.

Noncompliance with the requirements of UL 1703 or the requirements of the NEC will result in a system that cannot be legally installed in jurisdictions where the NEC is legislated into law. This includes the entire United States.

More Changes Coming

By the time you read this article, the UL 1703 STP will have approved more changes in the standard related to module grounding and module grounding devices. These changes and related changes in UL 2703 (PV Racking), UL 487 (Grounding Devices) and other standards will enhance PV module grounding, reduce the labor requirements, and also reduce the costs associated with grounding.

The PV installer and the inspector will be reasonably assured that a listed module can be installed according to the instructions provided with that module using the Code requirements to achieve a safe and durable electrical system.

For More Information

If this article has raised questions, do not hesitate to contact the author by phone or e-mail. E-mail: jwiles@nmsu.edu Phone: 575-646-6105

See the web site below for a schedule of presentations on PV and the Code. Call the author if you would like to schedule a presentation.

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: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.htm

This work was supported by the United States Department of Energy under Contract DE-FC 36-05-G015149

Read more by John Wiles

Harsh Environment—No Maintenance

PV modules may be generating energy for 40–50 years after installation. While power production may not be what it was when the PV system was new, hazardous amounts of voltage and current will be still available from the PV array. The rooftop, outdoor environment is harsh. Unlike HVAC equipment, which requires periodic inspections and maintenance, PV modules and the rooftop wiring and equipment may not be examined for the life of the system.

Inspectors and plan reviewers need to be aware of the requirements for cables used in PV systems. They also need to know that the system longevity may impose stringent workmanship and materials requirements on the conductors in a PV system.

Conductors interconnect the modules to the PV direct current combiners (where used) and then to the disconnects, inverters, and eventually to the utility grid or other load. The outdoor environment the conductors are exposed to is one of the most strenuous for any electrical circuit found in premises wiring. In various parts of the country, module and source circuit conductors, both in and out of conduit are exposed to temperatures from -50°C (-58°F) to +80°C (176°F), continuous submersion in water (in some conduits), ice, wind, hail, snow, sand, and for conductors exposed to the sun, ultraviolet (UV) radiation.

For these conductors to survive in this environment for the module life of 40–50 years, the conductors must be properly selected and installed. Cables come in many types, sizes, and constructions and PV even has some unique cable types that are not available to other industries.

USE-2

For many years, USE-2 has been the conductor of choice (and metNECrequirements) for a durable cable that could be attached to the PV module and also field installed in the outdoor environment. It is suitable only for module and source circuit wiring on grounded PV arrays where one of the dc circuit conductors is connected to earth/ground. This direct burial cable is typically made with cross-linked polyethylene insulation. The cable has undergone a 350 hour accelerated UV test, but is not marked "Sun Light Resistant” even though it is considered suitable for the outdoor environment. USE-2 is rated for wet environments (it is a direct buried cable) and for temperatures up to 90°C. Without any other markings (such as a dual USE-2/RHW-2 marking), USE-2 has no flame or smoke retardants and may not be used indoors in conduit. The author has personally had USE-2 conductors made with cross-linked polyethylene insulation exposed in the harsh outdoor conditions of New Mexico for more 30 years without obvious signs of deterioration.

Photo 1. Lug is not suitable for fine-stranded cable.

PV Cable/PV Wire

PV modules are made for international markets and have attached conductors that can be used in different countries. Most of the rest of the world (ROW) uses transformerless inverters (a.k.a. non-isolated inverters) and ungrounded PV arrays (no dc circuit conductor, either positive or negative connected to earth/ground). TheNational Electrical Code(NEC) allows ungrounded arrays to be installed in the U.S., and a "PV cable” or "PV wire” is required for the permanently attached modules conductor as well as for the field-installed exposed wiring. This specialized conductor is only mentioned in the NEC in Section 690.35 and is not found elsewhere in the Code. It has a nonstandard outer diameter, so the conduit fill tables may not be used. It may be used on modules in ungrounded PV arrays and also on modules intended for grounded PV arrays. PV wire/PV cable is tested, certified and listed to Underwriters Laboratories (UL) Outline of Investigation 4703.

UL 4703 establishes the materials that can be used in the conductor and the tests that the conductor must pass. The conductor insulation may be either thermoset (synthetic rubber-like cross-linked polyethylene) or thermoplastic (PVC).

The thickness is specified and there may be one or two layers of insulation. The insulation must pass an accelerated UV test of 720 hours and will be marked "Sunlight Resistant.” PV cable/PV wire also has smoke and flame-retardants and may be used inside conduit inside buildings. In the U.S., it should not be called a "double-insulated cable” as that is a purely European term.

All Insulations Are Not Equal

Photo 2. Improperly secured conductors can abrade and fault.

Both USE-2 and PV cable/PV wire are available with colored insulations (e.g., white, red, green), but care should be exercised when considering colored insulations. While these colored cables are marked "Sunlight Resistant” and have passed the 720-hour accelerated UV test, they do not have as much carbon black in them as do the black-insulated cables. Carbon black is one of the main insulation components that provides a conductor with UV radiation resistance. Cables with less carbon black may not fare as well over 40–50 years in the extreme PV environment as cables with high levels of carbon black.

And, in a similar manner, PVC insulated cables have passed the 720-hour accelerated UV tests, but PVC insulated electrical components like PVC jacketed UF cables and PVC liquid-tight non-metallic conduit (LFNC) have not survived well in the hot, sunny southwest outdoor environment.

In Conduits

Conductors in conduits are somewhat protected from the mechanical abuse that affects the exposed conductors. However, PV systems are experiencing ground faults in conductors in conduits indicating that more care must be exercised during the installation process. Not using the correct number of pull boxes and installing too many degrees of turn, as well as not installing bushings at the entry and exit points can lead to insulation damage. And, while the problems may not show up at system turn-on, they may show up in later years as the conduits are subject to thermal expansion and high temperatures from solar heating. Inspectors need to keep vigilant for signs of improper cable installation such as missing bushings, tight or stretched cables, and slivers of insulation.

Photo 3. Stainless steel/EDPM Loop Strap (available from McMaster-Carr)

Conductor Stranding

The UL 4703 specification allows both normal class B stranding (typically 7–19 strands) and it also allows finer stranding which can be hundreds of fine strands in a 10 AWG conductor. The European IEC Standard for PV cable (yes, unfortunately, the same name) requires that the European PV cables be fine-stranded. While fine-stranded, flexible cables pose no problems when installed on the modules in the factory, the use of fine-stranded flexible cables is problematic where field-installed cables are involved. This is due to the lack of suitable terminals for fine-stranded cables (see photo 1). See NEC 110.14, 690.31(F), 690.74 and the "Perspectives on PV” article in the January/February 2005 IAEI News.

Excellent Workmanship Required

Photo 4. ACME cable clip by Wiley Electronics

TheNEC, in Section 110.12, requires that electrical equipment be installed in a neat and workmanlike manner. ANSI/NECA 1-2006 Standard Practices For Good Workmanship in Electrical Contracting provides details. However, both theNECand the NECA standard were developed for conventional electrical installations where the conductors are installed in either interior locations (modest temperature, low mechanical stresses) or in exterior conduits. The exposed PV conductors, as noted above, are subject to far less benign conditions, and those conditions will affect the cables for many decades. When it comes to the workmanship associated with these exposed PV source circuit conductors, that workmanship must be excellent, not just good. Winds blowing a slightly loose conductor against a PV racking member can cause the insulation to be abraded in a few short months, leaving a potential shock hazard or ground-fault hazard (see photo 2). Exposed module conductors that hang below the modules and touch the roof are also subject to abrasion on the roof surface. In colder climates, they are also subject to ice dams and frozen snow sliding down the roof separating the cables from the modules—not a desirable situation.

Photo 5. Torque screwdrivers

The use of the common black plastic wire ties that are rated as UV resistant do not survive the PV environment which exposes the plastic to high levels of UV radiation and high temperatures on a day-in, day-out basis for many years. The most common size of these wire ties is ⅛” to 3/16″ wide and these have failed in PV installations after only a few years. It is possible that the more robust units, ⅜”to ½” wide and thicker, would survive more years. My organization (Southwest Technology Development Institute) deals with the smaller size PV systems (3–18 kW) and we usually use EDPM rubber-cushioned stainless-steel loop clamps to secure the module wires (see photo 3). PV equipment suppliers also stock stainless steel ACME cable clips by Wiley and others (photo 4).

Terminations

In addition to securing the exposed conductors properly, these conductors and others in conduit must be terminated properly on the fuse holders, circuit breakers, combiners, disconnects, inverters and at other equipment. In most cases, screw terminals are used and on every piece of certified/listed equipment, there is a torque value that must be used. Section 110.3(B) of the NEC requires that all instructions and labels associated with a listed product be followed. A torque screwdriver or torque wrench must be used to make these connections (see photo 5). If these terminals are not properly tightened, they will fail (see photo 6). IAEI, IBEW, and NECA have demonstrated numerous times that the average electrician cannot accurately make a screwed electrical connection without the use of a calibrated torque device.

Inspectors: Maybe it is time for your chief to get some torque screwdrivers.

Summary

Photo 6. Improper torque results in failed connections

As the large number of PV systems being installed today age in the decades ahead, we will see the affects of "average” workmanship. Plan reviewers and inspectors rarely get to see a PV system that has been installed 5 or 10 years ago. Research and development people who test these aging systems see the signs of deterioration on nearly every system. Systems integrators who sell maintenance contracts with their systems are finding issues with the conductors as the systems age.

It might prove informative and educational for plan reviewers and inspectors to visit a few of these older systems and see how the conductors and other parts of the installation are holding up. Perhaps the workmanship standard needs to be moved from "Good” to "Excellent.”

For More Information

If this article has raised questions, do not hesitate to contact the author by phone or e-mail. E-mail: jwiles@nmsu.edu; Phone: 575-646-6105.

See the web site below for a schedule of presentations on PV and the Code. Call the author if you would like to schedule a presentation.

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 2005National Electrical Code: Suggested Practices, written by the author, may be downloaded from this web site: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html

This work was supported by the United States Department of Energy under Contract DE-FC 36-05-G015149

Read more by John Wiles

Instructions supplied with these listed products should be followed [NEC110.3(B)]. The suggestions below do not substitute for compliance with theNECor local codes.

Grounding

Both the AC PV module and the microinverter will require equipment-grounding connections where there is any exposed metal in these devices. A grounding electrode conductor (GEC) connection will be required when the microinverter operates the module in a grounded manner.

Equipment/Safety Grounding

Photo 1. PV microinverter with exposed dc cables and connectors to PV module

The ac output circuit cable of some microinverters and AC PV modules does not have an ac equipment grounding conductor (EGC). This EGC conductor must be started (originated) in the transition box on the roof where each set of inverters has the final factory ac output cable connected to another wiring system. The ac equipment grounding conductor should also be attached to the microinverter enclosure. This ac EGC must be routed all the way back to the service-entrance bonding point as it is in any other ac circuit. There is no requirement that it be unspliced and the size will typically be 14 AWG per Table 250.122.

System/Functional Grounding

True AC PV modules where there are no readily accessible dc conductors or dc disconnect will normally not require a grounding electrode conductor. Since both the requirements in the 2005NEC690.47(C) and the permitted 690.47(C) in the 2008NECare both based on Article 250, the provisions of either editions of the Code appear to be applicable in jurisdictions using either edition. Section 690.47(C) in the 2011NECcombined and clarified 2005 and 2008 code requirements in this area.

Under UL Standard 1741 the microinverter, if it isolates the dc grounded input conductor (assuming a grounded PV module) from the ac output, must have a dc grounding electrode conductor (GEC) running from the grounding electrode terminal on the microinverter case to a dc grounding electrode. If the microinverter operates the PV module as an ungrounded system (neither positive nor negative connected to ground), then no grounding electrode conductor would be required.

Section 690.47(C) in the 2008 NEC permits the use of a combined ac EGC and dc grounding electrode conductor (GEC) from the inverter. The 2011NEChas this requirement in 690.47(C)(3). UL 1741 requires the dc GEC terminal on the outside of the inverter. If this option is elected, then the 8 AWG minimum (250.166) conductor from each inverter must be bonded to the input and output of each metal conduit and metal box that it travels through until it gets to the main grounding bar in the service entrance equipment. The bonding requirement and 8 AWG size would appear to rule out the use of 10-3 with ground type NM cable for the ac output circuit inside the building. The bonding requirement may also be cumbersome to implement multiple times and the routing of this combined conductor may induce lightning surges to enter the main load center and other branch circuits. The permissive method of grounding described in 690.47(C) in the 2008NECmay also be used under the 2005NEC.

Photo 2. AC PV module. No exposed dc cables or connectors. Courtesy Exeltech.

Alternatively, the permissive grounding method described in the 2005 NEC 690.47 may also be used under the 2008NECas an alternative to the 2008 NEC 690.47. Section 690.47(C) in the 2005NECand 690.47(C) in the 2008 NEC are based on the general requirements of Article 250.

Section 690.47(C) in the 2011 NEC combines and clarifies the grounding methods described in the 2005 and 2008 NEC.

The Exception in 690.47(D) in the 2008 NEC regarding array grounding is not clear. The subject of the section refers to array grounding electrodes. It is not clear if the Exception removes the requirement for an additional array grounding electrode only and leaves the requirement for the array GEC or removes the requirement for both. The intent of the submittal was to use a new array GEC to ground the array to an existing electrode or for a ground-mounted array, to a new grounding electrode at the array location. This would be particularly important in a high lightning area, but that is a performance issue, not a safety issue. This section was not in the 2005 NECand was removed from the 2011 NEC. An auxiliary grounding electrode is always an option under 250.54.

The size of the dc grounding electrode conductor is determined by 250.166, and this section has been clarified in the 2008NEC. In many cases, but not all, a 6 AWG bare copper conductor will meet the requirements. Where a UFER (concrete-encased electrode) is used, a 4 AWG grounding electrode conductor will usually be required. A short 6 AWG conductor may have to be irreversibly spliced to the 4 AWG conductor at each microinverter and connected to the microinverter grounding terminal if the inverter grounding terminal will not accept a 4 AWG conductor directly. An alternative would be to drive a single ground rod six or more feet from the UFER ground, ground the inverters and modules as described below with a 6 AWG bare copper grounding-electrode conductor and then bond the ground rod to the UFER with a 4 AWG bonding jumper (690.47(C)(1) in 2005 and 2011NEC).

The dc grounding electrode conductor may terminate at the service-entrance grounding electrode or at a grounding electrode associated with any subpanel where the inverter dedicated circuits end in backfed breakers under the 2005NEC. Under the 2008NEC, the combined conductor dc GEC/ac EGC can be terminated at the main service grounding bus bar or at any subpanel bus bar that has a grounding electrode attached and where the inverter backfed breaker terminates. The 2011NECallows either location to be used.

Disconnects

The microinverters should be installed in compliance with 690.14(D) of theNEC. As noted in this section, there are requirements for dc and ac disconnects on the roof in this not-readily accessible area, and an additional ac disconnect in a readily accessible location.

The relatively low dc voltage (usually less than 70 volts) and currents (less than 8 amps) may allow the dc connectors on the microinverter inverter to serve as the dc disconnects for servicing the inverter. In a similar manner, the ac connectors on the microinverters and AC PV modules could be used as the maintenance disconnects required by 690.15. Microinverter and AC PV Module manufacturers can have the ac and dc connectors designed and listed with the microinverter or AC PV module as load break rated disconnects and this will allow the use of these connectors to meet Code requirements (690.14, 690.15 and 690.17).

Even with load break rated ac connectors, a transition box is needed to change from the flexible ac output cable to the code-required fixed wiring system that will enter the building. An inexpensive unfused 60-amp 240-volt air conditioning pull out disconnect would serve nicely and is already in a NEMA 3 R enclosure. It will also serve as an ac disconnect that when pulled, will shut down the microinverters or AC PV modules and opening the ac circuit will reduce the dc currents in the microinverter input cables and connectors to very near zero permitting safer opening of the dc disconnects.

Such a disconnect can also be used to meet some AHJ requirements for a non-connector disconnecting means on the roof.

Section 690.14(D)(3) requires an additional disconnect and that disconnect requirement may be met by the backfed breaker in the load center where the load center is positioned to meet the accessibility and location requirements of 690.14(C)(1). Some jurisdictions are requiring that this second ac disconnect be on the outside of the building and any utility-required disconnect on the inverter output circuit would usually meet this requirement.

AC Output Circuits

The output circuit of any utility-interactive inverter up to the first overcurrent protection device (OCPD) is very much like an ac branch circuit. If the utility voltage is removed from this circuit (for any reason), the circuit becomes de-energized (dead) — just like a branch circuit. If there is a line-to-line or line-to-ground fault on this circuit, the OCPD responds in a normal manner to the fault currents generated by the utility. The inverter(s) can generate no more than its rated current per UL Standard 1741 and when the fault occurs, the drop in line voltage will normally cause the inverter to shut down. And when the branch circuit breaker opens in response to the fault, the inverter shuts down.

It would appear that these inverter output circuits could be wired using any Chapter 3 wiring method suitable for the environment (hot, wet and UV outside and hot in attics). Grounding requirements or methods used for microinverters may dictate conductor sizes too large for 10 AWG type NM conductors.

An ac GFCI device should not be used to protect the dedicated circuit to the microinverter or ac PV module even though it is an outside circuit. None of the small GFCI devices (5 ma–30 ma) are designed for back feeding and will be damaged if backfed. In a similar manner, most ac AFCIs have not been evaluated for backfeeding and may be damaged if backfed with the output of a PV inverter.

Combining Multiple Sets of Microinvertersor AC PV Modules

In multiple strings of these inverters, there is no NEC requirement that an ac combining panel (load center) be located on the roof. In fact, most NEMA 3R load centers must be mounted against a surface to keep water from penetrating holes in the back panel and they must be mounted within 30 degrees or vertical. Such a surface may have to be added in order to properly mount a 3R load center on the roof. And then there might be problems meeting 110.26 clearance requirements. A further issue with OCPD on the roof is heating of the device over its rated 40 degrees Celsius operating temperature. Gray load centers in the sun will normally operate 10–20 degrees C hotter than the ambient temperature. This may be difficult to compensate for when considering available equipment, the size of the ac conductors attached to the inverters, and listing restrictions on the inverters. Nevertheless, it is possible to mount an ac load center on the roof with proper solar shielding and use it to combine the outputs of U-I inverters or sets of microinverters.

The rating of any combining panel and the ampacity of conductor from that panel to the backfed breaker in the main load center as well as the rating of the main load center and the backfed breaker must meet 690.64(B)/705.12(D) requirements. This requirement will require a combining panel and conductor with a rating nearly twice sum of all of the 15-amp or 20-amp backfed breakers used for each output. See the 120% allowance in 690.64(B)(2)/705.12(D)(2) and 690.64(B)(7)/705.12(D)(7).

The ac output conductor for a set of inverters must have an ampacity of 125% of the continuous currents for all of the inverters on that circuit. The backfed circuit breaker in the panel must be rated the same and if an odd current rating is determined, the breaker rating should be the next larger size. The breaker must protect the conductor under the conditions of use and the conductor ampacity must be derated for those conditions of use.

The ac output circuit from each set of inverters must have an equipment grounding conductor to facilitate OCPD operation during ac ground faults. Some microinverters have a three-wire output through a four-contact connector. The unused terminal in the connector is reserved for future use. The three active pins in the connector are 240-V L1 and L2, and a neutral. There is no ac equipment grounding conductor. This lack on an equipment grounding conductor in the cable requires that the equipment grounding conductor for the microinverter or ac PV module be an external connection to the inverter case, where the case is metal. This external equipment grounding conductor must be connected to the fixed wiring system (usually, but not always conduit) where that wiring system originates.
Unless the microinverter bracket has been designed and evaluated as a grounding/bonding jumper, grounding the microinverters does not ground the rack or the modules and visa versa.

There is only one ac neutral-to-ground bond in an ac electrical system. That bond is made in the existing service entrance equipment. No additional neutral-to-ground bonds should be made when installing a PV system unless a supply-side service entrance connection is made.

AC PV Module Grounding — A Gray Area

Combinations of PV modules and microinverters combined/assembled in the field or at the dealer or distributor do not meet the intent, definition, or requirements associated with true AC PV Modules as defined in 690.2 and in 690.6. As of early 2012 there is no specific size associated with either microinverters or ac PV modules. The power outputs are increasing with nearly every new product and are now in the 190–220 watt range.

Combinations of a microinverter and a PV module with exposed dc connectors and dc conductors between the PV module and the microinverter are being certified/listed as ac PV modules. Some of these products have instruction manuals that say the microinverter may not be removed from the PV module. Other manuals give specific instructions for removing the microinverter from the PV module for repair. At issue is the definition of an ac PV module as a factory assembled unit and the potential need to meet all dc code requirements for these products with exposed dc connectors and dc conductors. Connectors are subject to loosening or being opened in the field. Connectors and conductors are exposed to environmental degradation, ground faults, and animal damage.

Also at issue in the ac PV module is the microinverter-to-PV module frame bonding when the mechanical/electrical connection is broken in the field. When the microinverter is replaced, how is the bonding connection quality verified and how is the certification/listing maintained without NRTL evaluation?

At some point, these issues will be addressed in UL Standard 1741 and possibly in theNational Electrical Code.

For Additional Information

If this article has raised questions, do not hesitate to contact the author by phone or e-mail. E-mail: jwiles@nmsu.edu Phone: 575-646-6105

See the web site below for a schedule of presentations on PV and the Code.

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 (1.91) 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: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html

Read more by John Wiles

Questions on Grounding

Question: Does the NEC require that a grounding electrode conductor (GEC) and a grounding electrode (ground rod) be connected to the new transformerless inverters? See photo 1. Section 690.47 in the 2011 National Electrical Code (NEC) does not exactly address this issue.

Answer: If the listed transformerless inverter (also called a non-isolated inverter) adheres to the requirements of Underwriters Laboratories Standard 1741 for PV inverters, the inverter will not even have a terminal for a grounding electrode conductor. These inverters are used with an ungrounded PV array. The UL standard requires a grounding electrode conductor terminal and the Code would require a grounding electrode conductor only when there is a bonding jumper in the direct current (dc) side of the inverter. In normal transformer-type of inverters (also called isolated inverters), this bonding jumper is part of the required 690.5 ground fault detection and interruption (GFDI) circuit.

Photo 1. Transformerless inverter. Looks like many other inverters that have transformers, but may not have a GEC terminal or a 690.5 Warning. Photo courtesy SMA Technologies

Transformerless inverters do not connect one of the dc circuit conductors in the PV array to ground (as allowed byNEC690.35) and have no internal bonding jumper. Therefore, there will normally be no terminal to connect the GEC to and theNECdoes not require a dc GEC. Unfortunately, Section 690.47 does not specifically say this, so a proposal has been submitted for the 2014NECthat hopefully clarifies the issue. Here is the wording of that proposal for 690.47(B).

Add a new third paragraph to 690.47(B) as follows:

Ungrounded DC PV arrays connected to utilization equipment with common ac and dc equipment-grounding terminals shall be permitted to have dc equipment-grounding requirements met by the ac equipment-grounding system without the requirement for a dc grounding electrode conductor or grounding system.

We have been asking PV installers to get that dc GEC connected to the inverter for many years. Now, on these new systems, it will no longer be required. But, be advised that not all inverter manufacturers, nor their certification agencies, will read all of the fine print in the standard and some transformerless inverters will have terminals or instructions for a GEC. This terminal will be, as it is in other inverters, connected internally to the dc and ac equipment-grounding conductor terminals. And, if desired, this terminal may be used with a GEC routed to a grounding electrode. This would essentially be a 250.54 optional grounding electrode and that electrode does not have to be bonded to any other grounding electrode. It is connected only to the equipment-grounding system in the inverter.

The 690.47(B) proposal for the 2014NECindicates that since the ac and dc equipment-grounding conductor terminals are common in the inverter, the ac equipment-grounding system (grounded at the service-entrance equipment) can be used to provide the array equipment-grounding function.

However, this may route lightning induced surges on the array equipment-grounding system through the inverter and into the service equipment. Far-thinking PV installers may elect to install optional 250.54 grounding systems at the array and possibly also at the inverter to better protect against these surges.

Question: What is the proper method of grounding the modules and microinverters that are not manufactured or certified/listed as an AC PV module?

Answer: These microinverters are essentially small inverters. It is difficult to precisely define them as a unique device since they are continually getting larger (now 380+ watts) while some normal "string” inverters are down to 700 watts and below. The micro-inverter/ PV module combination has many of the characteristics of any other inverter when it comes to grounding. There are usually exposed metal surfaces on both the inverter and the module that must be grounded (i.e., connected to earth through an equipment-grounding conductor/system). The microinverter may cause the module to operate as an ungrounded module, as a positively grounded module (most common), or as a negatively grounded module. This form of grounding refers to how the dc circuit conductors are referenced to ground and is called system or functional grounding. When the module is operated in a grounded manner, there will be a dc bonding jumper inside the inverter and this fact will require that the inverter have a dc grounding electrode conductor terminal. The dc grounding electrode conductor (GEC) will have to be 6 AWG in exposed locations and at least 8 AWG inside conduit. It will have to be unspliced or irreversibly spliced from the microinverter all the way to the grounding electrode or the grounding bus bar in the equipment that has a connected grounding electrode.

Photo 2. Microinverter with single grounding terminal for both equipment grounding and dc grounding electrode conductor connections. Photo courtesy Enphase.

The inverter should also have an ac equipment-grounding conductor that will be routed with the ac output circuit conductors. With a dc input from the module, there should also be provisions to accept a dc equipment-grounding conductor from the PV module. However, in many cases, a single external terminal on the microinverter can meet both the equipment-grounding terminal requirements (ac and dc) and the grounding electrode conductor terminal requirement. See photo 2

In general, the module will require an equipment-grounding conductor attached to the frame following the instructions provided in the module instruction manual and sized per 690.45. In many cases this can be as small as 14 AWG. Of course, 690.46 may apply or the AHJ may require a larger conductor to provide greater mechanical integrity. In these cases, a 6 AWG conductor is frequently used.

In some cases, an electrical connection (not just a mechanical attachment between inverter and module frame) between the module frame and the microinverter enclosure will enable a single equipment-grounding conductor to be used for both devices.

Creative sizing (6 AWG) and routing of a single unspliced conductor can be used to meet all module and microinverter grounding requirements.

Question: What type of grounding is required on modules with plastic frames (also known as industrial composites) and these new dc-to-dc converters that are attached to the module outputs that have plastic enclosures? See photo 3

Answer: My favorite type a question — an easy one. If there are no exposed metal parts on a module, a microinverter, or a dc-to-dc to dc converter, there will be no requirement for an equipment-grounding conductor and probably no place to attach such a conductor. However, we may get a plastic encased dc-to-dc inverter or a microinverter that has a dc grounding electrode conductor requirement and there will be a terminal for that conductor. The manual for these certified/listed products will have the instructions for this connection.

Questions on Overcurrent Protection

Question: When do multiple strings of modules require a fused combiner box or a set of fuses inside the inverter?

Answer: The number of strings of PV modules that can be connected in parallel without a fused combiner is determined by the short-circuit current (Isc) rating of each module and the maximum series fuse. Each string of modules can, under worst-case conditions of sunlight, generate 1.25 x Isc of current into a fault in a parallel-connected string of modules. If we have "n” strings connected in parallel, then "n-1” strings can send fault current into a faulted string. The total fault current would be (n-1) x 1.25 x Isc. That fault current must be less than the rating of the module protective fuse marked on the back of the module. If the fault current were greater than the value of the module protective fuse, then the module and its cable could be damaged where there was no fuse.

A little PV math shows that:

(n-1) x 1.25 x Isc < F where F is the value of series fuse marked on the back of the module.

If we solve this for n, the total number of strings in parallel, we get:

n< (F+1.25 x Isc)/(1.25 x Isc)

Example 1: Module W has an F of 15 amps (pretty common) and an Isc=8 amps.

n<(15+1.25 x 8)/(1.25 x 8) = 25/10 = 2.5, and the total number of strings (n) for this module can be 2.5; and since n has to be a whole number, two strings of modules can be connected in parallel.

Example 2: Module Y has F = 20 and Isc = 3. n < (20+1.25 x 3)/(1.25 x 3) = 23.75/3.75 = 6.33 and six strings of these modules can be connected in parallel.

For many PV modules in the 180–300 watt range, only two strings can be connected in parallel because of these constraints.

Question: Can two sets of 15 microinverters be connected in parallel without overcurrent devices?

Answer: In short — No. The microinverters are tested and certified/listed to be used as a set with the cable or wiring harness provided with them. The instruction manual will specify how many microinverters can be connected to the factory cable and the rating of the required circuit breaker for that set on a single cable. This is consistent with NEC 705.12(D)(1) that requires a dedicated circuit breaker for utility-interactive inverters.

Question: How does the short-circuit current from a PV module affect the output current of the connected dc-to-dc converter? How is the PV module open circuit voltage used to calculate the voltage rating of any combiner or inverter downstream.

Photo 3. Dc-to-dc converter. Photo courtesy Tigo Energy

Answer: This new technology of dc-to-dc converters and other PV module power processors has evolved in numerous configurations. Some converters are required on the output of every PV module; some are required on only a few modules. Most are connected in series, but some are connected in parallel. Some of the devices are "smart” and must be used with "dumb” inverters. All of these devices must be certified/listed to UL Standard 1741. There are and will be too many variations to address the specific connection requirements of each product in the NEC directly. The outputs of these devices are decoupled from their inputs, so PV module short-circuit currents and voltages cannot directly be used to meet any Code requirements that are associated with the circuits connected to the output of these devices. Essentially the installers and the inspectors will have to rely on 110.3(B) where these certified/listed devices must be installed following all instructions provided with the product and all labels on the product. A proposal for the 2014NECwill reinforce this requirement in Article 690.

Questions on Large Systems

Question: What needs to be addressed concerning the ground-fault protective device connected to the inverter output to meet the exception on 690.64(B)(3)/705.12(D)(3)? The exception requires that loads be protected from all sources of ground-fault currents.

Answer: This particular area is beyond the scope of the NEC. The load circuits must be protected from ground faults originating from the utility service and also from ground-fault currents originating from the load-side connected PV inverter. The fault currents reaching the load circuits will be shared between these two sources. It would take engineering analysis to determine how the two sources will share the fault currents under various situations and how the settings of each ground fault device will be determined.

Question: The service disconnect is at 12 kV (12.47 kV) for a large facility and the PV system will be connected at 480 volts on a feeder. For this load-side connection, how do we apply 705.12(D)(2) to determine conductor and busbar ampacities when transformers are involved?

Answer: The voltage ratio of the transformer is used to adjust the various overcurrent device ratings and ampacities to an equivalent set of numbers at a single voltage, either at the 12 kV or the 480 V level.

For example, a 25-amp fuse on the 12 kV side of the transformer would translate to about a 650-amp (25 x 12470/480) overcurrent device when referenced to the 480 V feeder. Then the requirements of 705.12(D) may be applied. In these large facilities, keep in mind that the PV inverter output connection to the existing system must be made at the end of a feeder or busbar opposite the utility feed end before the 120% allowance can be used. If the sum of the overcurrent devices exceeds 120% of the ampacity of the feeder or the rating of the busbar, or the PV connection cannot be properly located, a 100% factor must be used. Any circuits (conductors and busbars) not protected by a single overcurrent device that may carry current from the PV system may have to be increased in size.

Keep those questions coming. The holes in the 2014 NEC have not yet been addressed and thatCodeis more than two years away.

For Additional Information

See the web site below for a schedule of presentations on PV and theCode.

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 (1.91) 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: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html

And yes, it may be updated to the 2008 and 2011 Codes sometime this year.

Read more by John Wiles

Service Entrance Questions

Question: I am looking at a diagram of a PV system where the main service is a 100-amp main-lug-only (MLO) panel with six breakers. One of the six breakers is rated at 40 amps and is being backfed from a utility-interactive PV inverter. Doesn’t this 40-amp breaker exceed the 120% allowance of 690.64(B)/705.12(D) that would limit the backfed breaker to 20 amps on a 100-amp panel?

Answer: These six breaker MLO service-entrance panels are common in many areas of the country, primarily in older homes. There is no main overcurrent device or disconnect ahead of the MLO panel busbar, so each of these six breakers represents a service disconnect. That backfed 40 amp represents a supply-side connection allowed under 690.64(A)/705.12(A) and the load-side requirements of 690.64(B)/705.12(D) do not apply. The limit of the breaker rating in such a supply-side connection would be the rating of the MLO panel, the rating of the panel busbar (usually the same as the panel rating), or the rating of the service, whichever is less.

Photo 1. Main-lug-only panel — PV breaker rating?

Question: The PV installer has made a supply-side connection between the meter base and the load center by cutting the EMT, installing a pull box and making the PV connection inside the box. He has installed a fused disconnect adjacent to the pull box and has run EMT to the inverter. Workmanship looks good, but what else should I be looking for?

Answer: The NEC treats these supply-side connections as additional services as allowed by 230.2(A)(5). As services, the various requirements of services should be followed including conductor type between the connection point and the disconnecting means, routing and protection of this service-entrance conductor, bonding neutral to ground at the new service disconnect, and running a grounding electrode conductor from the bonding jumper to the existing grounding electrode. Yes, it appears that there may be some parallel paths for the neutral currents, but they do not appear objectionable since similar multiple bonding jumpers in close proximity are shown in Article 250 in the NEC Handbook where multiple services are involved.

Photo 2. Utility-required disconnect — PV AC disconnect too?

Question: We have numerous commercial buildings in our jurisdiction with 480-volt, 4-wire services that are over 1000 amps and have main service-entrance disconnects as main breakers with attached or internal ground-fault protection devices. What are the issues that should be considered when looking at a plan to backfeed a panel on the load side of this main GFP breaker with the output of a photovoltaic inverter?

Answer: Briefly: (1) Has the GFP device been evaluated for backfeeding? Most new ones are, but older units may not have been evaluated. UL does not do this particular evaluation; only the manufacturer can provide the necessary information. The breaker may not be marked "Line” or "Load,” which indicates that it has been evaluated for backfeeding, but this has no bearing on the suitability for the GFP device for back feeding. (2) Does the inverter ac output circuit have a ground-fault protection device connected to protect loads from ground-fault currents originating from the inverter? The internal dc ground-fault protection device does not meet this function. (3) Has a fault analysis been accomplished to determine how ground-fault currents will divide between the main GFP and the inverter GFP and what the proper trip settings for each should be? See a White Paper on this subject on the author’s web site below.

Photo 3. Inverters with internal AC and DC disconnects plus external disconnects

Disconnect Questions

Question: Can an unfused disconnect used to meet a local utility requirement be also used as the 690.15 maintenance disconnect for the inverter? The disconnect is not locked by the utility and is located near the service disconnect and the meter on the outside of the building.

Answer: Usually the utility will have no objections to this dual use of the utility-required disconnect, but it never hurts to verify. In order to meet the intended safety requirements of 690.15, the disconnect should be located near or at least within sight of the inverter. This location requirement would allow the inverter to be maintained in a safe manner by opening this ac disconnect, opening the dc disconnect, verifying that both are open and then working on the inverter as necessary. An inverter that is not mounted within sight of this utility-required disconnect may require that an additional ac disconnect be mounted adjacent to the inverter location.

Question: Can the disconnects, either ac or dc or both, that may be internal to the inverter be used as the 690.14 dc PV disconnect and/or the 690.15 required disconnects?

Answer: If the inverter is mounted in the location required by 690.14 for the dc PV disconnect, an internal dc disconnect might meet that disconnect requirement. However, meeting the 690.15 maintenance disconnects with any internal disconnects may pose certain problems. This is a discussion that the PV installer and the AHJ will have to have. Where the internal disconnects are mounted in a section of the inverter that is separate from the inverter electronics and the inverter electronics section can be removed for service while the disconnect section remains attached to the wall and the dc and ac conduits, then it would appear that the safety intent can be met. However, if the internal disconnects are in one enclosure with the inverter proper, there is the possibility that a less-than-fully-qualified person might run into trouble by unintentionally pulling live dc cables through the conduit knockout when removing the inverter for service. Recent internal disconnect failures, a few disconnect fires, and recalls of some inverters for problems in the disconnect section have caused many AHJs to reevaluate their position on the internal disconnect.

Photo 4. Microinverters — disconnects required?

Question: Microinverters are mounted on roofs in not readily accessible areas. How can the disconnect requirements of 690.14 and 690.15 be met? It would appear that 690.14(D) would apply since the inverters are mounted in these roof top areas, but there are no disconnects being used. Should I require ac and dc disconnects for each microinverter?

Answer: Before requiring large and expensive ac and dc disconnects for each inverter, check with the microinverter manufacturer to determine if the connectors on the microinverter have been evaluated as load-break-rated disconnects. While the typical MC 3 or MC 4 PV disconnect on a PV module is only a recognized component because it cannot pass the listing requirements at 600 volts dc, those connectors can be evaluated as load-break disconnects at the lower operating voltages (typically less than 80 volts) of the microinverters. At least one manufacturer of microinverters has had the ac and dc connectors so evaluated.

Photo 5. FMC from the roof

Where an additional ac disconnect is deemed necessary, the common 60-amp pullout ac HVAC unfused disconnect can meet the requirements and provides a transition point between the microinverter cable and the circuit to the ac panel. It is usually cheaper than many other outdoor-rated pull or junction boxes.

Circuit Questions

Question: The electrician ran flexible metal conduit from the roof penetration through the house to the dc disconnect and the inverter located in the basement. Is this type of installation permitted per the NEC?

Answer: Yes, as of the 2005 NEC, Section 690.31(E) allowed metal raceways to be used for this interior circuit run between the rooftop mounted PV system and the readily accessible dc disconnect/inverter. This would include flexible metal conduit (Type FMC). In the 2011 NEC, a metallic cable assembly, Type MC was added. Type AC metallic cable assemblies, particularly those with aluminum outer jackets, are not approved or listed for use in direct current (dc) circuits.

Question: Is the inside of a house or building with locked doors and windows considered a readily accessible location for meeting the Article 230 service entrance and Article 690 PV disconnecting means location requirements?

Photos 6A and 6B (inset). Steel door and high security lock — readily accessible?

Answer: Excellent question, and one that needs further clarification in the Code. Fire fighters will usually call the utility to have the ac power disconnected from a building before entering an area that might have energized circuits. When the utility is unable to get to the location in a timely manner, the fire fighters are reluctant to remove the utility meter due to the safety hazards and legal issues involved. In life safety issues, they will pull the utility meter thereby de-energizing the ac circuits.

But what about that inside-the-house dc disconnect for the PV system? They know that it is there because of the code-required directories and placards on the outside meters and service equipment. Fire fighters have told me that they have master keys for many locks; and for the high security locks, there is always the fire axe. However, the answer to this question remains unclear in the NEC. Is the inside of a locked building considered a readily accessible area in which an ac service-entrance disconnect or a dc PV disconnect can be located?

Question: Section 690.47(C)(3) in the 2011 NEC allows the function of the PV inverter dc grounding-electrode conductor to be combined with the function of an inverter ac equipment grounding conductor in a single conductor meeting the most stringent requirements of either conductor. In many older electrical systems and in some newer ones, an outbuilding such as a barn or garage is connected to the main service panel with a feeder that uses the neutral as both the grounded circuit conductor and as the equipment grounding conductor as allowed by 250.32(B) Ex. If a utility-interactive PV system is installed on the outbuilding, can that combined neutral/ac equipment grounding conductor be used as the 690.47(C)(3) "grounding” conductor for the inverter?

Answer: Section 690.47(C)(3) addresses only the grounding-electrode and equipment grounding conductors from the inverter. Under normal operation, neither of these conductors carries current, whereas the combined ac neutral/equipment grounding conductor allowed by 250.32(B) Ex would normally be a current-carrying conductor. Although the NEC does not explicitly address this combination, I tend to think that these two functions should not be further combined into a single conductor in that feeder between the main panel and the outbuilding. One reason that comes to mind is that lightning surges induced from the PV array now have a relatively easy path along the neutral into the service equipment. However, the next question may have some bearing on this issue.

Answer: Although 690.47(C) in the 2008 is a bit murky, I believe both editions of the Code allow this combined conductor to be terminated at a grounding bus bar in the nearest ac panel that has an ac grounding electrode conductor connected to a grounding electrode that meets the requirements of the Code. Such a panel would certainly include the main service-entrance panel and also any feeder panel that has the necessary grounding. With respect to the previous question, the remote building that has the 250.32(B) Ex "grounding” system is required to have a grounding electrode at the outbuilding. It would appear that the PV inverter could be mounted in this location with the combined dc grounding electrode conductor/ac equipment grounding conductor terminated at the grounding bus bar in the outbuilding panel. In this case, the combined neutral/equipment grounding conductor between the buildings would not be involved in the inverter grounding requirements.

Ratings and Calculations Questions

Question: I’m a building inspector and I have a few questions regarding STC ratings. I know that the NECrequires all PV modules to be marked with its maximum voltage, open-circuit voltage, short-circuit voltage, etc., and common sense will tell me that the conductors and OCPD must be sized based on that info. The problem is, I can’t find anywhere in the NEC that states exactly that, other than the word "rated” in 690.8 and 690.9. So I guess I’m asking: What forces us to use STC ratings when sizing a PV system? And are STC ratings the only ratings marked on modules? If another testing standard was marked on the modules and the modules were listed, would the Code require the wires and OCPD to be sized based on that info instead of STC?

Answer: The key is NEC Section 110.3(B), which requires that we use the instructions and labels on a listed product. The label on the back of a PV module is required by UL Standard 1703 and the values on that label are based on testing under the Standard Test Condition as required by the standard. As far as I know, UL Standard 1703 is the only standard being used in the U.S. to certify/list PV modules and that standard is being harmonized with the European IEC standards. In both the UL and the IEC standards, Standard Test Conditions are used to rate the module. NEC Informative Annex A lists UL Standard 1703 as the applicable standard for flat plate PV modules. There are no values on the back of the module other than the STC values. So, the rated values required in 690.8 are the values marked on the back of the module and they would be used in the circuit sizing and overcurrent protection. In a similar manner, the motor nameplate ratings in terms of locked-rotor current and full-load current would be used in determining the circuit sizing for that motor. Yes, there are other specifications sometimes listed for modules in the technical specification sheets or in other documents. For example, the temperature coefficients are listed in specification sheets and used to calculate the cold weather, open-circuit voltage as required by 690.7. In some cases, PVUSA Test Conditions (PTC) are given, but these typically are used for performance estimations and are not involved with Code calculations.

Photo 7. Cold weather Voc calculations are important.

Question: I am checking a set of plans for the calculations on the cold-weather open-circuit voltage (Voc) and I find that some of the module specification sheets show a Voc temperature coefficient in degrees K. In the January-February 2009 IAEI News article on "PV Math,” you described the method of using coefficients with degrees Celsius (C). But what do I do with these numbers in degrees K?

Answer: You use the numerical values in coefficients that are based on degrees Kelvin (K), in the same way you use the coefficients based on degrees Celsius (C). A change in temperature of one degree K is the same as a change in temperature of one degree C. The difference is that the Kelvin temperature scale is based on zero being at an absolute zero temperature where all molecular motion stops, but the Celsius temperature scale has a zero based on the freezing point of water. The zero point on the scale does not affect our calculations.

For Additional Information

See the web site below for a schedule of presentations on PV and the Code.

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 (1.91) 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: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html

And, yes, it may be updated to the 2008 and 2011 Codes sometime this year.

Read more by John Wiles

Plan Reviewers and Inspectors. What Do You Need?

Photovoltaic (PV) power systems are becoming more numerous, larger and more complex. Inspectors and plan reviewers have limited time to deal with these new systems and still carry on the routine electrical system inspections that have been done for 100 years or more. I intend for this "Perspectives on PV” articles to provide you with information on the Code requirements for these systems and also give you information on how to make the plan reviews and inspections easier and faster.

Inspecting PV Systems

What do you need to know about concerning PV systems? Give me a call or drop me an e-mail and let me know what you would like to see in these articles. There will be a time delay since I am writing this November-December 2011 IAEI News article in August. In a hurry for an answer? Try the e-mail and I’ll try to get a fast response.

On the Front Lines

Plan reviewers and inspectors bear a heavy responsibility for the safety of the public when it comes to electrical systems, including PV systems. While most residential and small commercial electrical systems have not changed much over the past few decades or so, PV systems now have transformerless inverters for ungrounded PV arrays, microinverters, AC PV modules, dc to dc converters in the PV array and dc PV arc fault circuit protection. Couple those new "toys” with the dc current-limited outputs from the PV modules and we have a very dynamic, constantly evolving situation.

I know that many jurisdictions do not have a plan review section or person and that many inspectors only have 15–30 minutes allocated to perform a residential inspection. We all know that there are both qualified and unqualified people doing electrical installations, including PV systems. And with the significant amounts of money flowing into green electrical systems, there are many people jumping on the bandwagon that should not even be near the parade.

In this Perspectives on PV, I will share with you a PV installer checklist that covers the more import Code requirements for PV systems. The checklist will show 2005, 2008 and 2011 requirements and the differences will be noted.

Photo 2. AC or DC disconnect?

Since jurisdictions vary in the availability of a plan review department and the time available for the inspection differ, I will not attempt to separate the items that would be accomplished at the plan review stage and those that need to be done at the on-site inspection. And, yes, I have tried many times to read a conductor size and type on a hot sweaty day when the conductors are cut to minimum length inside a disconnect—it sometimes is just not possible.

The following checklist is available on the author’s web site (see below) and it is double spaced for better readability.

CHECKLIST FOR PHOTOVOLTAIC POWER SYSTEM INSTALLATIONS

1. PV ARRAYS

• PV modules listed to UL Standard 1703? [110.3] [690.4(D)]

a. Mechanical Attachment

• Modules attached to the mounting structure according to the manufacturer’s instructions? [110.3(B)]
• Roof penetrations secure and weather tight? [110.12]

b. Grounding

• Each module grounded using the supplied hardware, the grounding point identified on the module and the manufacturer’s instructions? Note: Bolting the module to a "grounded” structure usually will not meetNECrequirements [110.3(B)]. Array PV mounting racks are usually not identified as equipment-grounding conductors. [Note 690.43(C) and (D) in 2011 have additional provisions and allowances for grounding with mounting structures.]
• Properly sized equipment-grounding conductors routed with the circuit conductors? [690.45] Note differences between 2005, 2008 and 2011NEC.

c. Conductors

• Conductor type? —If exposed: USE-2, UF (usually inadequate at 60°C), or SE, 90°C, wet-rated and sunlight-resistant. [690.31(B)] (2008 NEC restricts exposed single-conductor wiring to USE-2 and listed PV/Photovoltaic Wire/Cable)—If in conduit: RHW-2, THWN-2, or XHHW-2 90°C, wet-rated conductors are required. [310.15]
• Conductor insulation rated at 90°C [UL-1703] to allow for operation at 70°C+ near modules and in conduit exposed to sunlight (add 17–20°C to ambient temperature-2005NEC)[see Table 310.15(B)(2) in the2008 NEC] [Table 310.15(B)(3)(c)]
• Temperature-corrected ampacity calculations based on 156% of short-circuit current (Isc), and the corrected ampacity greater than 156% Isc rating of overcurrent device? [690.8,9]

Note: Suggest temperature derating factors of 65°C in installations where the backs of the module receive cooling air (4″ or more from surface) and 75°C where no cooling air can get to the backs of the modules. Ambient temperatures in excess of 40°C may require different derating factors.

(2011 690.8 substantially updates ampacity calculations to parallel calculations in other sections of theNEC.)

• Portable power cords allowed only for tracker connections? [690.31(C), 400.3,7,8]
• Strain reliefs/cable clamps or conduit used on all cables and cords? [300.4, 400.10]
• Listed for the application and the environment? Fine stranded, flexible conductor cables properly terminated with terminals listed for such conductors? [690.31(E)(4)]
• Cables and flexible conduits installed and properly marked? [690.31(E)]
• Exposed conductors in readily accessible areas in a raceway if over 30 volts? [690.31(A)] Note: Raceways cannot be installed on modules. Conductors should be installed so that they are not readily accessible.

2. OVERCURRENT PROTECTION

• Overcurrent devices in the dc circuits listed for dc operation? If device is not marked dc, verify dc listing with manufacturer. Auto, marine, and telecom devices are not acceptable.
• Rated at 1.25 x 1.25 = 1.56 times short-circuit current from modules? [UL-1703, 690.8, module instructions] Note: Both 125% factors are now in theNEC, but the duplicate 125% should be removed from the modular instructions in calendar year 2011. Supplementary listed devices are allowed in PV source circuits only, but branch-circuit rated devices are preferred. [690.9(C)].
• Each module or series string of modules have an overcurrent device protecting the module? [UL-1703/NEC110.3(B)] Note: Frequently, installers ignore this requirement marked on the back of modules. Listed combiner PV combiner boxes meeting this requirement are available. One or two strings of modules do not require overcurrent devices, but three strings or more in parallel will usually require an overcurrent device. The module maximum series fuse must be at least 1.56 Isc.
• Located in a position in the circuit to protect the module conductors from backfed currents from parallel module circuits or from the charge controller or battery? [690-9(A) FPN, NEC-2008] Informational Note, 2011.
• Smallest conductor used to wire modules protected? Sources of overcurrent are parallel-connected modules, batteries, and ac backfeed through inverters. [690-9(A)]
• User-accessible fuses in "touch-safe” holders or fuses capable of being changed without touching live contacts? [690.16] Strengthened for 2011 to include distance between overcurrent device and disconnect.

3. ELECTRICAL CONNECTIONS

• Pressure terminals tightened to the recommended torque specification?
• Crimp-on terminals listed and installed with listed crimping tools by the same manufacturer? [110.3(B)]
• Twist-on wire connectors listed for the environment (i.e., dry, damp, wet, or direct burial) and installed per the manufacturer’s instructions?
• Pressure lugs or other terminals listed for the environment? (i.e., inside, outside, wet, direct burial)
• Power distribution blockslistedand not just UL Recognized?
• Terminals containing more than one conductor listed for multiple conductors?
• Connectors or terminals using flexible, fine-stranded conductors listed for use with such conductors? [690.31(F), 690.74]
• Locking (tool-required) on readily accessible PV conductors operating over 30 volts [690.33(C)]

4. CHARGE CONTROLLERS

• Charge controller listed to UL Standard 1741? [110.3] [690.4(D)]
• Exposed energized terminals not readily accessible?
• Does a diversion controller have an independent backup control method? [690.72(B)(1)]

5. DISCONNECTS

• Disconnects listed for dc operation in dc circuits? Automotive, marine, and telecom devices are not acceptable.
• PV disconnect readily accessible and located at first point of penetration of PV conductors?
• PV conductors outside structure until reaching first readily accessible disconnect unless in metallic raceway? [690.14, 690.31(F)]
• Disconnects for all current-carrying conductors of PV source? [690.13]
• Disconnects for equipment? [690.17]
• Grounded conductorsnotfused or switched? Bolted disconnects OK.

Note: Listed PV Centers by Xantrex, Outback, and others for 12, 24, and 48-volt systems contain charge controllers, disconnects, and overcurrent protection for entire dc system with possible exception of source circuit or module protective fuses.

6. INVERTERS (Stand-Alone Systems)

• Inverter listed to UL Standard 1741? [110.3] [690.4(D)] Note: Inverters listed to telecommunications or other standards do not meetNECrequirements.
• DC input currents calculated for cable and fuse requirements? Input current = rated ac output in watts divided by lowest battery voltage divided by inverter efficiency at that power level. [690.8(B)(4)]
• Cables to batteries sized 125% of calculated inverter input currents? [690.8(A)]
• Overcurrent/Disconnects mounted near batteries and external to PV load centers if cables are longer than 4–5 feet to batteries or inverter?
• High interrupt, listed, dc-rated fuses or circuit breakers used in battery circuits? AIR/AIC at least 20,000 amps? [690.71(C), 110.9]
• No multi-wire branch circuits where single 120-volt inverters connected to 120/240-volt load centers? [100—Branch Circuit, Multi-wire], [690.10(C)]

7. BATTERIES

• None are listed.
• Building-wire type cables used? [Chapter 3] Note: Welding cables, marine, locomotive (DLO), and auto battery cables don’t meetNEC. Flexible, listed RHW, or THW cables are available. Article 400 flexible cables larger than 2/0 AWG are OK for battery cell connections, but not in conduit or through walls. [690.74, 400.8] Flexible, fine stranded cables require very limited, specially listed terminals. See stand-alone inverters for ampacity calculations.
• Access limited? [690.71(B)]
• Installed in well-vented areas (garages, basements, outbuildings, and not living areas)? Note: Manifolds, power venting, and single exterior vents to the outside are not required and should be avoided.
• Cables to inverters, dc load centers, and/or charge controllers in conduit?
• Conduit enters the battery enclosure below the tops of the batteries? [300.4]
  

  Photo 4. Undetected Ground Fault

  Note: There are no listed battery boxes. Lockable heavy-duty plastic polyethylene toolboxes are usually acceptable

8. INVERTERS (Utility-Interactive Systems)

• Inverter listed to UL Standard 1741 and identified for use in interactive photovoltaic power systems? [690.4(D), 690.60] Note: Inverters listed to telecommunications and other standards do not meetNECrequirements.
• Backup charge controller to regulate the batteries when the grid fails? [690.72(B)(1)]
• Connected to dedicated branch circuit with back-fed overcurrent protection? [690.64]
• Listed dc and ac disconnects and overcurrent protection? [690.15,17]
• Total rating of overcurrent devicessupplyingpower to ac load center (main breaker plus backfed PV breaker) must be less than load-center rating (120% of rating in residences) [690.64(B)(2)]. The2008 NECallows the 120% breaker total on commercial installations and residential system ONLY if the PV breaker is at the opposite end of the busbar from the main utility breaker. No change for 2011.

9. GROUNDING

• Only one bonding conductor (grounded conductor to ground) for dc circuits and one bonding conductor for ac circuits (neutral to ground) for system grounding? [250] Note: The main dc bonding jumper will generally be located inside inverters as part of the ground-fault protection devices. On stand-alone systems, the dc bonding jumper may be in a separate ground-fault detection and interruption device or may be built in to the charge controller.
• AC and dc grounding electrode conductors connected properly? They may be connected to the same grounding electrode system (ground rod). Separate electrodes, if used, must be bonded together. [690.41,47] The 2008NECin 690.47 allows a combined dc grounding electrode conductor and an ac equipment-grounding electrode, but the conditions and requirements are numerous. [690.47]. (2011NECclarifies and combines 2005 and 2008 690.47(C) requirements.)
• The 2008NEC690.47(D) array grounding requirement was removed in 2011NEC.
• Equipment grounding conductors properly sized (even on ungrounded, low-voltage systems)? [690.43, 45, 46]
• Disconnects and overcurrent in both of the ungrounded conductors in each circuit on 12-volt, ungrounded systems or on ungrounded systems at any voltage? [240.20(A)], [690.41]
• Bonding/grounding fittings used with metal conduits when dc system voltage is more than 250-V dc? [250.97]

10. CONDUCTORS (General)

• Standard building-wire cables and wiring methods used? [300.1(A)]
• Wet-rated conductors used in conduits in exposed locations? [100 Definition of Location, Wet]
• Insulations other than black in color will not be as durable as black in the outdoor UV-rich environment.
• DC color codes correct? They are the same as ac color codes—grounded conductors are white and equipment-grounding conductors are green, green/yellow, or bare. [200.6(A)] Ungrounded PV array conductors on ungrounded PV arrays willnotbe white in color.

For Additional Information

The US Department of Energy funding for providing inspectors and the PV Industry with telephone and e-mail support from the author was terminated on March 1, 2011. Answers to your questions may be delayed or not answered at all depending on future funding. Consultation services are available on a contracted basis. E-mail: jwiles@nmsu.edu Phone: 575-646-6105

See the web site below for a schedule of presentations on PV and theCode.

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 (1.91) 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: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html

Read more by John Wiles

Photo 1. 400-amp load center, 300-amp main. Internal supply side and load side PV connections are possible.

The Basic Requirement

This section of Code was written to address a general condition where any panelboard busbar or conductor might be fed by multiple sources of power that are connected to the busbar or conductor through overcurrent devices. Although the 2008 NEC 690.64(B) appears to restrict the connection point, in fact nearly any point on a load-side circuit (inside a panelboard or on the conductors of a feeder or branch circuit) may, and has, served as a connection point for either a PV inverter or for an additional load circuit. Of course, there are numerous restrictions and requirements on making such connections, but in general, all of the load-side wiring is up for grabs and the connections and circuits must be protected.

There are no restrictions in this code requirement as to the particulars of any specific installation. There are no restrictions on where the multiple power sources might be connected on the busbar or conductor nor are there any limits on the number of overcurrent devices. There are no restrictions on the loads connected to the busbar or conductor either in terms of their connection point or the rating of the overcurrent device and, in fact, loads are not specifically addressed in the section. When applying this requirement, no assumptions should be made as to the configuration of the circuit with respect the location of connections (taps) and the number, magnitude and locations of any sources or loads. Some people even feel that the code requirement was written to "Protect people from doing harm—in the future.”

Photo 2. Load side connection. Conductor size to the PV inverter too small to meet 690.64(B) requirements.

This is the manner in which many code requirements are formulated. The requirement is written in general terms and then the general requirement is modified by exceptions (restrictions or allowances) or additions to the requirement.

From an engineering point, the basic requirement is sound. A conductor or busbar will be prevented from being overloaded if the rating of that busbar or the ampacity of that conductor is greater than or equal to the sum of the ratings of all overcurrent devices supplying it [see 690.64(B)(2) in2005 NEC]. Note that the requirement refers only to theratingof thesupplyovercurrent devices, not to any calculated currents and it does not refer to any load overcurrent devices.

Because dwelling unit load centers are usually not fully loaded and the Chapter 2 load calculations usually result in light panel loadings, the 690.64(B) requirement up to the2008 NECallowed a dwelling exception to the extent that the sum of the ratings of the supply overcurrent devices could exceed the rating of the busbar or conductor up to 120%. This allowance for dwelling units would allow up to 20 amps of backfed PV breaker to be installed on a 100-amp rated panel that had a 100-amp main breaker. By calculation:

The 2011 National Electrical Code (NEC) has been published by the National Fire Protection Association (NFPA) and is now available from numerous sources. It was adopted by some jurisdictions automatically on 1 January 2011, and will be adopted throughout the country over the next three years or even longer in some areas that are slow to change.

Anyone working with PV systems and equipment in either manufacturing, design, installation, or inspection arenas should get a copy of the 2011 NEC and the 2011NEC Handbook. TheNECindicates the code changes (which will not be repeated verbatim here) by highlighting and the Handbook provides additional explanations.

I hope that the following information is reviewed with the 2011NECin hand or at least it whets the appetite for getting the Code ASAP. Inspectors will usually start reading the new Code as soon as it becomes available for clarifications of the existing code, even though their jurisdiction may not adopt the newest Code for several years. In many cases where safety enhancements are involved, AHJs will permit or even enforce the requirements of the new Code before it is officially adopted by the jurisdiction.

Overview

Code-making panel (CMP) 4 processed Articles 690, Solar Photovoltaic (PV) Systems, and 705, Interconnected Electrical Power Production Sources, for the 2011 NEC. Those articles had previously been handled in CMP-13 for many years. CMP-4 did not have the long-term exposure to PV systems and the unique PV characteristics of current-limited dc generators and utility-interactive ac sources. Many of the carefully thought out and substantiated proposals were rejected for obscure reasons.

In general, we have many areas of Article 690 that were clarified, some that were not, and some added requirements, plus a move of several sections from Article 690 to Article 705. Minor clarifications and grammatical corrections will not be addressed in the following.

690.2 Definitions. Definitions ofsubarrayandmonopole subarraywere added so that they can be used in requirements dealing with the return of bipolar arrays. They have not been in evidence since the mid-1990s and at that time the safety issues resulted inCodechanges.

690.4(A) Installation. Clarification

690.4(B) Installation.Extensive marking requirements were added for all circuits in a PV system. Safe maintenance was the justification. When you open a junction box or combiner, circuit identification should be easy.

690.4(E) Installation. Qualified persons shall install all PV equipment and systems. See the definition ofqualified personin Article 100. Specific skills and training including safety training are mentioned in the definition.

690.4(F) Installation. Circuit routing requirements were added to reduce the likelihood that fire fighters will come into contact with energized circuits. PV circuits inside and outside the building are affected.

690.4(G) Installation. More stringent requirements for bipolar arrays were added to avoid exceeding the voltage rating on equipment. Inspectors will have to look closely at these new systems since the UL Standard 1741 does not specifically address these types of inverters.

690.4(H) Installation. Directory requirements were established for multiple inverters on a single building.

690.7(A) Maximum Photovoltaic System Voltage. An Informational Note (previously a Fine Print Note) gives a source of temperature data that could be used to calculate cold weather open-circuit voltage.

690.7(E) Bipolar Source and Output Circuits. A clarification of ground-fault actions on a bipolar array was added.

690.8(B) Ampacity and Overcurrent Device Ratings. An extensive revision was made to clarify and align PV overcurrent device rating and conductor size calculations with basic requirements found elsewhere in the Code. See January-February 2011 IAEI News, "Perspectives on PV” for details. DC PV conductor ampacity calculations do not always involve 1.56 Isc.

690.9(A) Circuits and Equipment. Exception: Clarification.

690.9(B) Power Transformers. Clarification

690.9(E) Series Overcurrent Protection. Clarification

690.10(E) Backfed Circuit Breakers. Clamping requirements for backfed circuit breakers in stand-alone system were modified to include requirements for multi-mode inverters in battery backed up utility-interactive PV systems.

690.11 Arc-Fault Circuit Protection (Direct Current). A new requirement was added for a dc PV arc-fault circuit interrupter. It must detect series arcs in the dc PV circuits, interrupt them, disable equipment, and annunciate. Equipment is in the market addressing this equipment, at least for off grid systems, and other equipment is coming.

690.13 All Conductors. Clarifications.

690.13 Exception No. 2. A disconnecting means will be permitted in the grounded conductor for maintenance actions and then when accessible only by qualified people.

690.14 PV Disconnecting Means. Unfortunately, no changes were approved.

690.16(A) Disconnecting Means. Clarification

690.16(B) Fuse Servicing. Disconnecting means from all sources of energy shall be located at the fuse location or a directory shall be provided to show disconnect location(s). This requirement is aimed at large inverters which have dc fuses bolted to an input bus bar with no way to de-energize those fuses without opening every single one of the possibly hundreds of fuse holders in the distant combiner boxes.

690.31(B) Informational Note. PV wire has a nonstandard outer diameter and conduit fill tables cannot be used.

690.31(E) Direct-Current Photovoltaic Source and Output Circuits. Corrects longstanding typo and indicates that only dc circuits must be in a metal raceway, not ac inverter output circuits. Allows type MC metal-clad cable to be used for DC circuits inside the structure. Four new paragraphs of requirements have been added on routing, protection, and marking of PV circuits inside the building. Addresses conductor protection, maintenance and fire fighter concerns.

Conductors under the roof shall be 10” below the roof decking. Small metallic raceways and cable assemblies shall be protected from physical abuse in accessible areas. All access points and exposed conduits will be marked as containing PV power sources.

690.43 Equipment Grounding. Clarifications in (A) through (F).

690.43(C) Mounting structures for PV modules shall be identified as equipment grounding conductors or shall have all parts bonded together and to the equipment-grounding system.

690.43(D) Mounting devices used for grounding modules shall also be identified as grounding devices.

690.47 Grounding Electrode System. Substantially revised and clarified. The requirements 690.47(C) in the 2005NECwere merged with the requirements of 690.47(C) in the 2008NEC. See September-October 2009IAEINews"Perspectives on PV” for details.

690.47(D) was deleted.

690.62 Ampacity of Neutral Conductor. Deleted and moved with califications to 705.95.

690.63 Unbalanced Interconnections. Referred to 705.100 without changes.

690.64 Point of Connection. Referred to 705.12 with only two changes; 690.64(A) becomes 705.12(A), and 690.64(B) becomes 705.12(D).

Both sections have needed substantial revisions since 1984.

690.72(C) Buck/Boost Direct-Current Converters. A new section has been added to establish how ampacity and voltage requirements are to be calculated for these devices. Although in Part VIII, Storage Batteries, these requirements may also be used for module circuit dc-to-dc converters.

705.6 System Installation. Qualified persons must do installations of parallel power sources.Qualified personsis defined in Article 100.

705.12(A) Supply Side. The sum of the ratings of power production sources shall not exceed the rating of the service.

705.12(D)(2)Exception. Describes a method of sizing ac output circuits for battery-sourced, multi-mode inverters operating in utility-interactive systems. The 120% equation, where allowed, may use 125% of the rated inverter utility-interactive current instead of the rating of the backfed circuit breaker.

705.60, 65, 70, 80, 82, 95, and 100 contain requirements that duplicate information in various sections of 690.

The Future

We are already working on proposals for the 2014NEC, which are due to NFPA by November 4, 2011. Sections that are being examined for revisions include 250.32, Figure 690.1(A), 690.2, 690.4(D), 690.6, 690.x (microinverters), 690.y (dc-to-dc converters), 690.7(E), 690.14, 705.12 and others. If you see a section of the Code in 690 that is not abundantly clear, send me e-mail with your proposed changes and substantiations.

Please visit the Solar America Board of Codes and Standards web site www.SOLARABCs.org for updates on proposals being developed by the PV Industry Forum.

For Additional Information

If this article has raised questions, do not hesitate to contact the author by phone or e-mail. E-mail: jwiles@nmsu.edu Phone: 575-646-6105

See the web site below for a schedule of presentations on PV and the Code.

A color copy of the latest version (1.91) 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: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html

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. Copies of "Code Corner” written by the author and published in Home Power Magazine over the last 15 years are also available on this web site: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html

This work was supported by the United States Department of Energy under Contract DE-FC 36-05-G015149

 Read more by John Wiles

Photo 1

With these conditions and equipment characteristics in mind, the typical electrician doing indoor wiring has generally used the 75°C insulated conductor ampacity tables in Table 310.16 and not bothered too much with temperature corrections (310.15) and terminal temperature limits [110.14(C)] since they were not necessary or were included in the tables being used.

However, direct current (dc) PV conductors normally operate in an environment that is too hot for conductors with 75°C insulation. Conductors with 90°C insulation must be used and appropriate temperature and conduit fill corrections must be applied along with verifying that connected equipment terminal temperatures (60° or 75°C) are not exceeded. To do otherwise and use the short-cuts of the old days will result in conductors that may be not suited for the application and that may be larger than code requirements resulting in unnecessary costs.

Photo 2. Fused PV combiner with large and small cables

Throughout the Code, circuits are sized based on 125% of the continuous load plus the noncontinuous load. See 210.19(A)(1) and 215.2(A)(1). This requirement establishes a situation where conductors and overcurrent devices are not subjected to continuous loads (currents) more than 80% of rating. (Note: 1/1.25 = 0.80 and we can either divide or multiply depending on how the calculations are being accomplished).

Electricians and PV installers typically use the 125% factor and then apply the conditions of use factors (temperature and conduit fill)sequentially. The NEC,in a careful reading of the two referencedsections, does not require that both factors be applied at the same time. See the 125% requirement below.

In the Code, we have at least two or three requirements that must be met in sizing conductors.

First is the definition ofampacityfound in Article 100. Ampacity is "The current in amperes that a conductor can carry continuously under the conditions of use without exceeding its temperature ratings.”

Next is the 125% requirement in 210.19(A)(1) and 215.2(A)(1): "The minimum feeder circuit conductor size,before the application of any adjustment or correction factor,shall have an allowable ampacity not less than the noncontinuous loads plus 125 percent of the continuous loads” (emphasis added). This requirement ensures that conductors and overcurrent devices are not operated continuously at over 80% of rating.

Photo 3. Fuse AC and DC ratings will be different.

Then, Section 110.14(C) requires that the temperature of the conductor in actual operation not exceed the temperature rating of terminals on the connected equipment.

An added requirement for any listed equipment such as overcurrent devices is that they not be used in a manner that deviates from the listing or labeling on the product [110.3(B)]. Most PV source-circuit combiners operating outdoors in the sunlight will have internal temperatures that exceed the 40°C rated operating temperatures of commonly used fuses and circuit breakers.

The following method of determining ampacity meets the three code requirements above and finds the smallest conductor that can be used to meet these requirements. It also determines the rating of the overcurrent device where required.

Step 1. Determine the continuous current in the circuit.

PV dc circuits and PV ac circuits are not "load” circuits so we will use the termcurrentinstead ofload. For code calculations, all dc and ac PV currents are considered continuous and are based on worst-case outputs or are based on safety factors applied to rated outputs.

A. PV DC Circuits.In the dc PV source and dc PV output circuits, the continuous currents are defined as 1.25 times the rated short-circuit current I_sc(marked on the back of the module). If a module had an I_scof 7.5 amps, the continuous current would be 1.25 x 7.5 = 9.4 amps [690.8(A)(1)].

If three strings of modules (module I_sc= 8.1 amps) were connected in parallel through a fused source circuit combiner, the PV output circuit of the combiner would have an I_scof 3 x 8.1 = 24.3 amps. The continuous current is this circuit would be 1.25 x 24.3 = 30.4 amps [690.8(A)(2)].

B. AC Inverter Output Circuits.In the ac output circuits of a utility-interactive inverter or the ac output circuit of a stand-alone inverter,

Photo 4. Copper busbars are used instead of cables.

the continuous current is taken at the full power rated output of the inverter. Itis notmeasured at the actual operating current (which may be a small fraction of the rated current due to a small PV array connected to a large inverter) of the inverter. Usually the rated current is at the nominal output voltage (120, 208, 240, 277, or 480 volts). The rated output current is usually specified in the manual, but may be calculated by dividing the rated power by the nominal voltage. For stand-alone inverters, which can provide some degree of surge current, it is the rated power that can be delivered continuously for three hours or more [690.8(A)(3)].

In some cases, the inverter specifications will give a rated current that is higher than the rated power divided by the nominal voltage. In that situation, the higher current should be used.

For a utility-interactive inverter operating at a nominal voltage of 240 volts and a rated power of 2500 watts, the continuous current would be:

2500 W/240 V=10.4 A.

A stand-alone inverter with a model number of 3500XPLUS operates at 120 volts and can surge to 3500 watts for 60 minutes. However, it can only deliver 3000 watts continuously for three hours or more. The rated ac output current would be:

3000 W/120 V = 25 A.

C. Battery Currents.The currents between a battery and an inverter in either a stand-alone system or a battery-backed up utility-interactive

Photo 5. Improperly specified and sized cable

system must be based on the rated output power of the inverter (continuous for three hours or more) at the lowest input battery voltage that can provide that output power [690.8(A)(4)]. Normally the output current from the battery in the inverting mode is greater than the current to the battery in the charging mode. This current is usually marked on the inverter or found in the specifications.

The battery discharge current can be calculated by taking the rated output power, dividing it by the lowest battery voltage that can sustain that power, and also by dividing by the inverter dc-to-ac conversion efficiency at that battery voltage and power level. For example:

A 4000-watt inverter can operate at that power with a 44-volt battery input voltage and has a dc-to-ac conversion efficiency (inverting mode) of 85 percent. The dc continuous current will be:

4000 W/44 V/0.85 = 107 A.

On single-phase inverters, the dc input current is rarely smooth and may have 120 Hz ripple current that is larger in root mean square (RMS) value than the calculated continuous current. The inverter technical specifications should list the greatest continuous current.

Step 2. Calculate the rating of the overcurrent device, where required.

Since PV modules are current limited, overcurrent devices are frequently not needed for one or two strings of PV modules connected in parallel. In systems with three or more strings of modules connected in parallel, overcurrent devices are usually required in each string to protect not only the conductors, but also the module internal connections.

A. Rating Determined from Continuous Currents.The overcurrent device rating is determined by taking the continuous current for any of the circuits listed in Step 1 and increasing the continuous current by 125% (or by multiplying by 1.25). Non-standard overcurrent device values should be rounded up to the next standard rating in most cases.

In a very few rare cases, an overcurrent deviceinstalled in an enclosureor an assembly may be tested, certified and listedas an assemblyfor operation at 100% of rating. In these cases, the overcurrent device rating is the same as the continuous current and no 125% factor is used. The author knows of no overcurrent devices installed in an enclosure for PV systems that have such a rating.

B. Operating Temperature Affects Rating.Overcurrent devices are listed for a maximum operating temperature of 40°C (104°F). PV combiner boxes operating in outdoor environments may experience ambient temperatures as high as 50°C. Exposed to sunlight, the internal temperatures may reach or exceed 55–60°C. Any time, the operating temperature of the overcurrent device exceeds 40°C, it may be subject to nuisance trips at current values lower than its rating. In this situation, the manufacturer must be consulted to determine an appropriate derating. At high operating temperatures an overcurrent device with a higher rating will activate at the desired current. In PV source circuits, the new rating of the revised overcurrent device (under cold weather conditions) must not exceed the ampacity of the conductors or the maximum series fuse value marked on the back of the module.

Step 3. Select a conductor size.

The conductor selected for any circuit must meet both the ampacity requirement and the 125% requirement. The correctly sized cable is the larger of A or B below.

A. Ampacity Requirement.The conductor, after corrections for conditions of use must have an ampacity equal to or greater than the continuous current found in Step 1. See Article 100, Definition of ampacity.

B. 125% Requirement.The cable must have an ampacity of 125% of the continuous current established in Step 1. See 215.2(A)(1).

Example 1.Three (3) conductors are in a conduit in a boiler room where the temperature is 40°C. The continuous current in all four conductors is 50 amps. A copper, 90°Cinsulated cable is specified.

Photo 6. PV containers may operate above 40°C.

Temperature correction factor = 0.91, Conduit fill correction factor = 1.0

Step A, Ampacity Rule: Required ampacity at 30°C is 50/0.91/1.0 = 54.9 amps and this would require an 8 AWG cable.

Step B, 125% Rule: 1.25 x 50 = 62.5 amps and this would indicate a 6 AWG cable.

The 6 AWG cable is the larger of the two and is required.

Example 2.Now there are six (6) conductors in the conduit and the temperature has increased to 50°C. The continuous current is still 50 amps.

Temperature correction factor = 0.82, Conduit fill factor = 0.8

Step A, Ampacity Rule: 50/0.8/0.82 = 76.2 amps and a 4 AWG cable is needed

Step B, 125% Rule: 1.25 x 50 = 62.5 amps calling for a 6 AWG cable.

The 4 AWG cable is the larger of the two and must be used.

Step 4. Terminal temperature limits

A. The terminal temperature limits marked on the equipment must be used. If no temperatures are marked, then a 60°C limit is used for circuits rated at 100 amps or less or cables 14–1 AWG. For circuits rated greater than 100 amps and for conductors greater than 1 AWG, a 75°C terminal temperature limit will be used. See 110.14(C).

The following method is a terminaltemperature estimationmethod and is not an ampacity calculation method. It is used after the conductor size has been selected based on the ampacity calculation.

Take the conductor size in Step 3 above. Find the lowest terminal temperature limit for this conductor at any termination. Use that terminal temperature limit (either 60°C or 75°C) to enter the ampacity Table 310.16. For the conductor size selected, read out the current in the correct column, either the 60°C column or the 75°C column. There are no temperature adjustments or conduit fill adjustments to this current.

The current from the table must be equal to or greater than 125% of the continuous current. And, if the conductor meets this requirement, then the terminal temperatures are going to be less than the 60°C or 75°C limit for that conductor and that continuous current. The 125% factor is a fudge that accounts for many items not calculated in this simplified temperatureestimationprocess.

Example 3.Take the 8 AWG conductor and 50 amps of continuous current used in Example 1 above. This conductor is connected to a terminal with a 60°C marking.

From Table 310.16, an 8 AWG conductor in the 60°C column can carry a current of 40 amps.

We take 125% of the continuous currents of 50 amps.

1.25 x 50 = 62.5 amps.

This is larger than the 40 amps from the table, and this terminal will be heated above 60°C.
If we increase the conductor size to 6 AWG, the table gives us 55 amps, still less than 62.5 and too hot.

Increasing the conductor size to 4 AWG will give 70 amps from the table; and since this is greater than the 62.5 amps, we will be assured that the terminal will stay below its 60°Ctemperature limit.

Example 4.Use the 4 AWG conductor selected in Example 2 connected to a terminal with a 75°Ctemperature limit. The continuous current is 50 amps. Taking 125% of that continuous current yields:

1.25 x 50 = 62.5 A.

A 4 AWG conductor in the 75°C column of Table 310.16 shows a current of 85 amps. Since this is greater than the 62.5 amps, the conductor will operate cooler than the 75°C terminal temperature limit. No increase in conductor size is necessary.

Step 5. Verify that the overcurrent device protects the conductor selected under the conditions of use.

Where an overcurrent device is required, it must protect the conductor under operating conditions (conditions of use). Conductors may be protected using the round up allowance found in 240.2(B).

Example 5.A circuit has a continuous current of 70 amps. After conditions of use (4 conductors in the conduit, 48°C) are applied, a 3 AWG, 90°C conductor is selected to meet all ampacity and 75°C terminal temperature requirements.

The ampacity after conditions of use have been applied is:

110 x 0.8 x 0.82 =72.2 A.

The required minimum overcurrent device for this level of continuous current is

70 x 1.25 = 87.5 A.

A 90-amp overcurrent device would typically be used. A few people have suggested using an 80-amp overcurrent device, but that would result in running it at more than 80% of rating and in dc PV circuits could result in nuisance trips during short periods of cloud enhanced irradiance.

However, the largest overcurrent device that could be used to protect the 3 AWG conductor with an ampacity of 72.2 amps is an 80-amp overcurrent device and a 90-amp overcurrent device is the smallest allowed in this circuit.

The conductor size would have to be increased to 2 AWG for full compliance with NEC requirements.
The ampacity of a 2 AWG, 90°C conductor under the conditions of use is:

130 x 0.8 x 0.82 = 107 A.

The required 90-amp overcurrent device can protect the 2 AWG conductor.

Summary

PV installers, plan reviewers, and inspectors need to know how to do conductor sizing and overcurrent device ratings properly to get safe, reliable, and cost effective PV systems. This procedure for sizing conductors and overcurrent devices meets NEC requirements. In general, it can be used for any type of electrical circuit except possibly HVAC and other motor protection circuits. A part of this procedure is in Section 690.8(B) of the 2011NEC.

For Additional Information

If this article has raised questions, do not hesitate to contact the author by phone or e-mail. E-mail: jwiles@nmsu.edu Phone: 575-646-6105

See the web site below for a schedule of presentations on PV and the Code.

A color copy of the latest version (1.91) 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: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html

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. Copies of "Code Corner” written by the author and published in Home Power Magazine over the last 15 years are also available on this web site: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html

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Inspectors and installers continue to puzzle over the requirements in Section 690.64 of the National Electrical Code (NEC) that apply to the connection of utility-interactive inverters to the premises wiring and finally to the utility. This article, using the simplified block diagram (figure 1), will attempt to clarify some of those requirements. Please refer to previous Perspectives on PV articles over the last two years for more detailed information.

One Diagram Is Worth a Thousand Words

Many people do better with diagrams than they do with words, so the diagram shown should be just up their alley. This diagram works with many types of utility interactive PV systems. These systems all start with a meter connected to the utility as shown on the left. After that, we may be dealing with an existing service disconnect and the connected existing load center or with a PV supply side connection, which is just a second service entrance on the existing premises wiring system. In either case, the NEC requirements of Article 230 apply as noted at the bottom. In most jurisdictions, the local utility will require a PV disconnect on the ac output of the PV system and many areas will use a Renewable Energy Credit (REC) meter to measure the PV system output. As shown, one or more single inverters may be connected or even one or more "strings” of microinverters or AC PV modules may be connected to the added combining panel (blue blocks). Or, a single inverter could be connected to an existing load center (red blocks). In some cases multiple inverters might be connected through an ac combining panel and then backfeed an existing load center. Let’s start our examination of the requirements at the inverter end of the circuit.

Inverter Output Circuit

All utility-interactive inverters have a rated output current that cannot be exceeded. There are no surge currents in these output circuits andNEC690.8 requires that the circuit and the overcurrent protective device (OCPD) be rated at 125% of that rated output current. When the calculated OCPD value is a nonstandard value, the next standard higher value should be used, but not to exceed the maximum overcurrent value given in the technical specifications for the inverter. Conductor size should be selected so that it is protected by the OCPD rating.

Figure 1. Utility interconnections and NEC requirements

The asterisk (*) by the 690.8 in the diagram indicates thatifthere is an overcurrent device mounted at the inverter, then the requirements of 690.64(B),and not 690.8, will apply. Some installers and manufacturers use a circuit breaker or fused disconnect at the inverter to meet the requirements of 690.15 to have a maintenance disconnect at the inverter. The inclusion of an overcurrent device at this location generally forces the output conductors from the inverter to be larger [as required by 690.64(B)] than would otherwise be required by 690.8.

After the First Inverter Overcurrent Device

Anyconductor or busbarthat can have power flowing from more than one source of supply (under normal or fault conditions) such as the utility and a PV inverter, and where the conductor is protected by an overcurrent device on each supply source must meet 690.64(B) requirements. This is the long-standing 120% allowance [when 690.64(B)(7) conditions can be met]. Section 690.64(B) is going to apply to allconductors and busbarsfrom the first overcurrent device connected to the inverter output all the way to the service disconnect.

These busbars and conductors would include the busbars of any backfed main panelboards connected to one or two inverters or sets of microinverters, and any busbars in PV ac inverter combiner panels. The conductors or feeders between the panelboards or load centers and the main service disconnects are also subjected to the requirements of 690.64(B)(2) as noted on the diagram.

In general the ratings of all of the breakerssupplyinga busbar or conductor areaddedtogether and the sum is divided by 1.2 (for the 120% allowance). If the location requirements of 690.64(B)(7) cannot be met (PV breaker located at the opposite end of busbar or conductor from the

Photo 2. PV on south-facing roof at a good slope

utility breaker), then the sum may be divided by only 1, and the busbar rating or cable ampacity goes even higher. For example:

Two inverters each require a 50-amp backfed breaker in a main lug PV ac inverter combining load center to meet 690.8 requirements. A supply-side connection is going to be made with a 100-amp fused disconnect. The rating of the combining load center and the ampacity of the conductor to the 100-amp fused disconnect must follow the 690.64(B)(2) requirements.

(50 + 50 +100)/1.2 = 200/1.2 = 166.7 amps

The numbers indicate that a 200-amp PV ac inverter load center/panelboard would be needed and a 2/0 AWG conductor should be used between that panel and the 100-amp fused disconnect.

Now suppose that the two inverters are being backfed into an existing panelboard (switchgear) and it is not possible to position the two backfed PV breakers at the opposite end of the switchgear busbar from the main breaker. The requirements of 690.64(B)(7) are not met and the 120% allowance cannot be used. The equation becomes:

(50 + 50 + main breaker) must be less than or equal to the busbar rating.

If the main breaker were rated at 200 amps, then the busbar would have to be rated at 300 amps.

As the diagram shows, 690.64(B) applies to any panel or load center that has connections to the utility and to the PV inverter. It can be an existing load center or an added PV ac inverter combining panel.

The Main Disconnect and on to the Meter

Any circuit between the meter and the service disconnect would be considered a service-entrance circuit and be governed by the requirements of Article 230. This would be true if the circuit was an existing service- entrance conductor or a new 690.64(A) supply-side connection. The conductor size, type, and routing as well as the size and location of the service disconnect would have to meet 230 requirements. However, after passing through the overcurrent device on either an existing service disconnect or through the overcurrent device on an added PV supply-side connection, the requirements of 690.64(B) apply all the way to the first overcurrent device connected to the inverter output.

Summary

A diagram can simplify understanding of the requirements ofNEC690.64. While the PV industry had hopes of getting additional clarity into this section of the Code, those hopes were not realized for the 2011NEC, and we must continue to work with the existingCodelanguage.

For Additional Information

If this article has raised questions, do not hesitate to contact the author by phone or e-mail. E-mail: jwiles@nmsu.edu Phone: 575-646-6105

See the web site below for a schedule of presentations on PV and the Code.

A color copy of the latest version (1.91) 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: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html

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. Copies of "Code Corner ” written by the author and published inHome Power Magazineover the last 10 years are also available on this web site: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html

Read more by John Wiles

A Little History

Actually the United States is catching up to the rest of the world, which has, for the most part, been using ungrounded electrical systems for aslong as the U. S. has been using grounded electricalsystems. More than 100 years ago, the debate on grounded vs. ungrounded electrical systems began and the U. S. went grounded while many other countries went ungrounded. When we discuss grounded vs. ungrounded electrical systems, we are addressing whether one of the circuit conductors, like our ac neutral conductor, is grounded or not. Except for ungrounded three-phase delta-connected transmission and distribution systems, most of our electrical systems in the U. S. have a grounded circuit conductor. In Europe and elsewhere, ungrounded electrical systems are common and, in fact, in Germany, ungrounded three-phase ac power at 230 volts comes directly into the dwellings.

No grounding

To some extent, most electrical systems in the developed counties use a system of equipment-grounding conductors, called protective earth (PE) in Europe, to provide an outer layer of defense against electrical shocks from exposed conductive surfaces that could become energized. Of course, as in the U. S., double-insulated appliances and tools can be found that do not require an equipment-grounding system.

No transformers

There will be no attempt in this article to further the ages-old debate of the safety of ungrounded vs. grounded electrical systems. Given the history, equipment, training, and experiences on both sides of the issue, it appears that either system can provide equal levels of safety. As the world grows smaller, IEC standards in Europe are being harmonized with the standards developed by Underwriters Laboratories (UL) here in the U. S. and the codes are slowly adopting similar requirements and allowances.

Impact on PV System Design

Since the U. S. uses grounded electrical systems, PV systems installed in the U. S. have been required to have a grounded circuit conductor since 1984 when PV requirements first appeared in theNational Electrical Code (NEC).From the beginning, PV systems with a maximum systems voltage of 50 volts or below have not required a grounded circuit conductor and inNEC-2005, Section 690.35 was added to theCodeto permit the use of ungrounded PV arrays with few voltage restrictions.

Photo 1. A 9 kW transformerless inverter by SMA Solar Technologies AG

In utility-interactive PV systems, the inverter can be greatly simplified to a conceptual switching device and a filter with other added control components. Of course, how the utility-interactive inverter actually works is far more complex. The switch reverses the polarity of the dc output from the PV array 120 times per second to generate a 60 Hz waveform that is shaped into a sine wave by the filter. In Europe, they use 100 switches per second to get 50 Hz. Because the European PV arrays and the electrical system are ungrounded, the PV utility-interactive inverter can be relatively simple compared to what is required in the United States. In the U. S., with a grounded circuit conductor from the PV array and a grounded circuit conductor in the ac inverter output circuit, it is not possible to use a direct switching device because the switch would be shorted as it tried to reverse the polarity of the dc circuit into an ac signal. A transformer is required in inverters used in the U. S. to isolate the grounded dc circuits from the grounded ac circuits. The transformer is usually a heavy, costly, and bulky device that decreases efficiency, increases the size, and increases the shipping costs of the inverter.

U. S. inverter manufacturers and inverter manufacturers in the rest of the world can now sell transformerless inverters in the U. S. Those inverters must be used with an ungrounded PV array, and theNECallows such ungrounded PV arrays (see 690.35). Several inverters are on the market now (see photos 1, 2, and 3). What are these systems going to look like to the PV installer and the inspector?

The Ungrounded PV System

Photo 2. A 5 kW transformerless inverter by Power One

These ungrounded systems are not going to be significantly different from the PV systems that we have been installing and inspecting for many years. They will continue to have a system of equipment-grounding conductors that will connect the module frames, racks, enclosures of combiners, disconnects and inverters together and to ground (earth in Euro-speak).

According to NEC 690.35(B), dc overcurrent protection (when required for three strings of modules or more) will be required in both of the now-ungrounded circuit conductors. PV source circuit combiners for multiple strings of modules will have overcurrent protection in both the positive and negative dc inputs from each string of modules.

The PV dc disconnecting means will be required in both of the ungrounded conductors [690.35(A)]. With disconnects required in each ungrounded circuit conductor, external and internal disconnects will have a switch pole in each of the conductors coming from the PV array.

Ampacity calculations will be the same for grounded and ungrounded systems, and the calculations for maximum system voltage will be the same.

The color code of white for a grounded conductorwill no longer be used; and it is logical that the color code of red for a positive conductor and black for a negative conductor be used, but there is noCoderequirement that these colors be used. As before, the module interconnecting cable and other short-runs of exposed single conductor cables will usually have black insulation (for superior UV resistance) with colored markings used for identification. As an exercise, look at photo 4 and determine what sort of system is shown.

Photo 3. A 3.6 kW transformerless inverter by Power One

All exposed single-conductor cables including those attached directly to the module must be the new PV Wire or PV Cable made and listed to UL Standard 4703 [690.35(D)(3)]. Installers and inspectors should be aware that some of the European PV Cables, PV Wires or other cables with similar names made for the European market (and even made to UL Standard 4703) may use fine-stranded, flexible conductors and it will be difficult to obtain lugs and terminals suitable for use with these cables where they transition to a conduit wiring method. (See NEC 690. 31(F) and "Perspectives on PV” in the January/February 2005, IAEI News).

The inverter must be listed and clearly marked for use with ungrounded PV arrays, and it must have an appropriate internal ground-fault detection and indication system [690.35(C)]. That circuit will not be required to interrupt the ground-fault current (as is required on grounded PV arrays) because on the first ground fault on an ungrounded system, there will be no ground-fault currents. The inverter or charge controller will be required to shut down and indicate that a ground fault has occurred.

Summary

Ungrounded PV arrays, permitted by theNEC, will allow the use of the new transformerless inverters. Color codes will no longer require the white conductor. Disconnects will have poles in both the negative and positive conductors; and overcurrent devices, where required, will be in both conductors too.

Photo 4. Is it an ungrounded PV source circuit or an improperly color-coded grounded source circuit?

For Additional Information

If this article has raised questions, do not hesitate to contact the author by phone or e-mail. E-mail: jwiles@nmsu.edu Phone: 575-646-6105

See the web site below for a schedule of presentations on PV and theCode.

A color copy of the latest version (1.91) 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:http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html

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. Copies of "Code Corner” written by the author and published inHome Power Magazineover the last 10 years are also available on this web site:http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html

The author makes 6–8 hour presentations on "PV Systems and theNEC” to groups of 60 or more inspectors, electricians, electrical contractors, and PV professionals for a very nominal cost on an as-requested basis. A schedule of future presentations can be found on the IEE/SWTDI web site.

An Update on Microinverters and AC PV Modules

As the microinverters, combinations of microinverters attached to PV modules, and the AC PV modules come to market, there will be and already has been some confusion about the code requirements for various products.

Both microinverters and microinverters attached to PV modules in the field or in the factory that have any exposed dc single conductor cables are required to meet all of the dc wiring requirements in theNEC. These may include 690.5 ground-fault detector requirements, dc and ac disconnect requirements (potentially handled by connectors listed as disconnects), and inverter dc grounding electrode requirements. Confusion arises when these are calledAC modules. They are not AC PV modules.

TrueAC PV modules, as defined inNEC690.2 and 690.6, have a module and inverter assembled as one environmentally protected unit in the factory, and there is no accessible dc wiring. None of the dc wiring requirements in theCodeapplies, because there is no dc wiring outside the listed unit. A single equipment-grounding connection will usually be the only requirement to properly ground the combined module/inverter assembly.

Read more by John Wiles

In the course of daily business, I get some questions repeated many times. I try to address these areas of common and frequent interest in this series of articles, but there are always a few that need clarification or repeating.

Inverter DC Grounding Electrode Conductor

In the "Perspectives on PV” in the September-October 2009 IAEI News, we covered 690.47(C) in both the 2005 and the 2008 NEC and discussed that since this section is permissive in bothCodes, that either the 2008 or 2005 requirements may be applied in jurisdictions using either edition of theNEC. It should be clarified that the combined conductor permitted by 690.47(C) inNEC-2008 originates at the inverter and runs to the first grounding bar in a panel where a grounding electrode conductor (connected to a grounding electrode) is attached. It should be noted that this combined dc inverter grounding electrode conductor/ac inverter equipment-grounding conductor does not originate at the PV array. The PV array is normally grounded with an equipment grounding conductor routed with the dc circuit conductors per 690.45. Additional grounding of the PV array may be required by 690.47(D) when the array is ground mounted or mounted on a separate structure from the PV inverter.

Main AC Service Disconnect Ground-Fault Protection

NEC 230.95 requires that solidly grounded wye services with a line-to-ground voltage of 150 to 600 volts be provided with ground-fault protection. This protection is generally provided by a main disconnect consisting of a circuit breaker with an attached or included ground-fault protection device (GFPD). How should the PV designer, installer or inspector proceed where a utility-interactive PV system connection could backfeed this GFPD breaker? The answer: With a great deal of caution.

First, we need to know about one of those hidden-meanings, UL Standards that says if a circuit breaker is not marked "line” and "load,” it has been evaluated for current/power flow in both directions and is suitable for backfeeding. Most of the newer, smaller molded-case circuit breakers that we deal with are not marked "line” and "load” and are suitable for backfeeding. However, in retro-fit situations we may be dealing with main disconnect circuit breakers that are 40 or 50 years old or more and may have "line” and "load” markings. With those markings, the breaker should not be backfed.

Photo 1. GFP Breaker. To feed back or not.

Let’s assume that we have a main disconnect breaker that is suitable for backfeeding and it is also equipped with a GFPD as required by NEC-2008 and earlier Codes. Discussions with engineers at UL and with the circuit breaker manufacturers reveal that the GFPD may not have been tested for backfeeding in a method that duplicates the utility-interactive PV situation. When a ground fault trips a GFPD breaker that is being backfed by a PV inverter, both the line and load terminals may be energized at the same time for up to 2 seconds as the inverter shuts down. Many older GFPD devices could be damaged when this happens. Some of the newer GFPD breakers are not susceptible to this kind of damage, but no one seems to have a good universal answer to all GFPD breakers in all installations. So, the first hurdle is to get the design engineer at the breaker/GFPD manufacturers to provide written statements that the GFPD device will not be damaged when tripped while being backfed by a utility-interactive inverter.

The second hurdle is posed by meeting the Exception to 690.64(B)(3). How are the load circuits protected from ground-fault currents from the inverter? An analysis of the various impedances involved (inverter output source circuits vs. utility source circuits) to determine how currents would be shared between the inverter and the utility would not be simple. It may be possible that the inverter can source sufficient fault currents so that the GFPD does not trip. Then there is the fact that the GFPD has adjustable trip points, and the NEC provides no guidance on how they should be set in a non-PV installation, let alone in a PV installation. When the adjustment ranges over several hundred amps on a 1000-amp GFPD amp breaker, it is not clear how this adjustment should be made. Then if we try to put a GFPD on the output of the inverter, there is a question of how it should be connected and would it provide the desired protection?

At this point, I feel that when the existing installation has a main breaker or any breaker (or any fused disconnect) with a GFPD function, then that device should not have a utility-interactive inverter attached to any circuits that feed the load terminals of the GFPD. Supply side connections [690.64(A)] are the way to make these PV installations and avoid the issues until they are resolved.

690.64(B) All the Way

The "Perspectives on PV” in the November-December 2009 issue of the IAEI News dealt with supply side connections and the article assumed hope for the future code in this area. Unfortunately, NEC 690.64(B) and 705.12(D) will be with us for a long time since it appears that proposed changes for NEC-2011 were rejected. This code requirement applies to any bus bar or conductor that has multiple sources of supply (utility and PV inverter outputs) with each supply protected by an overcurrent device (fuse or circuit breaker). Load breakers are not counted in this requirement. In a typical utility interactive PV system, the requirement would apply to all busbars and conductors from the service disconnect (breaker or fused disconnect) to the first dedicated overcurrent device/disconnect on the inverter output circuit. Although the number of subpanels and conductors between the service disconnect and the PV inverter output may be numerous, and the load on the building large compared with the rating of the PV system, there is always the possibility that any conductor in this path may be subjected to backfeed currents from the PV system. Each of those panel busbars and conductors between them must be sized to meet the requirements of 690.64(B) / 705.12(D).

If the PV inverter output connection cannot be made at the very last breaker position in the most distant panel from the service disconnect as required by 690.64(B)(7), then the calculations for ampacity and busbars become more complex. Without this opposite breaker configuration, it may be possible to overload portions of the busbar or some conductors with current from both the utility and the PV system. The 120% allowance in 690.64(B)(2) cannot be applied, nor can just that first dedicated breaker connected to the PV inverter output be used in the calculations for each conductor and busbar. The designer/installer/inspector must look at each panel busbar and each conductor segment and determine which breakers are limiting current to that specific bus bar or conductor. These areusually the main breaker on the panel and the single backfed breaker in that particular panel that is handling backfed current from the possibly distant PV inverter. It is not the dedicated breaker connected directly to the inverter. Unfortunately, we have lost the 120% allowance and frequently a main breaker and the panel rating are the same. Therefore it is not possible to have breaker carrying backfed PV currents connected to this panel or conductor.

In some cases the main breaker for a panel may be reduced below the rating of the bus bar, and this can allow a backfed breaker to be connected anywhere on that panel. Load calculations determine if the breaker can be reduced. If so, then the sum of the rating of the main breaker (supplying utility power) and the rating of the backfed breaker in that panel may not exceed 100% of the bus bar rating for that panel. And, upstream panels and circuits toward the service entrance must still be analyzed to see if the 100% rule can be met. In many cases, a supply side connection is then the only option available.

Summary

Details are the meat and potatoes of the Code. By looking into theCoderequirements in detail, we see how those requirements are to be implemented. Sometimes the results of these inspections are not what we expect, but the end result is safer electrical systems.

For Additional Information

If this article has raised questions, do not hesitate to contact the author by phone or e-mail. E-mail: jwiles@nmsu.edu. Phone: 575-646-6105

A color copy of the latest version (1.9) 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: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html

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. Copies of "Code Corner” written by the author and published in Home Power Magazine over the last 10 years are also available on this web site: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html

The author makes 6–8 hour presentations on "PV Systems and the NEC” to groups of 60 or more inspectors, electricians, electrical contractors, and PV professionals for a very nominal cost on an as-requested basis. A schedule of future presentations can be found on the IEE/SWTDI web site.

This work was supported by the United States Department of Energy under Contract DE-FC 36-05-G015149

Read more by John Wiles

When buying real estate, conventional wisdom dictates the three most important elements are—Location, Location, and Location.

Based on my twenty-six years of working with PV systems, including the school of hard knocks, I strongly feel that the three most important elements to long- and short-term PV safety are—Grounding, Grounding, and Grounding.

Utility-interactive residential (dwelling unit), commercial, and megawatt PV systems operate with dc voltages from 50 volts to 600 volts and higher. AC voltages start at 120 and go to 23 kV on some of the larger systems. Underwriters Laboratories (UL) has determined that there is a shock hazard in exposed circuits operating at over 30 volts (ac or dc) in wet locations. SeeNEC690.31(A) and 690.33(C).

Operating currents range from less than 10 amps dc and ac to about 2200 amps dc on some of the larger inverters. An arc at currents around 1 amp can start a fire in the right material. Module power can be as low as 20 watts, but ranges upward to 320 watts. Consider the small 7-watt night-light or Christmas tree bulb (before LEDs). Seven watts can start a fire.

Photo 1. Improper module grounding: Plated steel thread cutting screw is not corrosion resistant; THHN conductors and nylon lug are not UV-rated.

PV modules and wiring as well as outdoor-mounted inverters are subjected to severe environmental conditions. Rain, sleet, snow, hail, sand, wind, and sunlight coupled with low and high temperatures would wear down the most stalwart postal worker over a 40–50 year span—the life expectancy of a PV module for producing dangerous amounts of voltage and current. USE-2 cables and the new PV cables are some of the toughest generally available cables, and we have seen USE-2 holding up well after 25 years when properly installed; but what about a less-than-outstanding installation after 30 or 40 years?

The environmental conditions, the use of copper conductors to ground aluminum module frames, and the daily thermal cycling that terminals, combiners, and modules are subjected to will eventually cause a break down in the insulations involved or in the electrical connections.

Proper grounding is a must, even when the NEC and the UL Standards do not fully addressthe issue.

Grounding Problems Are Being Observed and Reported

Unfortunately, getting the PV modules and racks grounded in a manner that will yield a low-resistance connection to the grounding system that will last for 50 or more years appears to be difficult. Inspectors are seeing improper grounding techniques being used (see photos 1, 2 and 3.) Improper grounding instructions are even appearing in the instruction manuals for listed PV modules (see photo 4). Inspections and tests of installed PV systems have found that in some cases, module-grounding connections have deteriorated in as little as three years and sooner in some areas (see photos 5 and 6).

There is significant confusion among module manufacturers, PV installers, and inspectors concerning how to properly ground a PV module; that confusion is becoming more and more apparent as numerous PV systems are being installed. A little history may highlight the cause of this confusion.

A Look at UL Standard 1703

Bonding the frame pieces together in the factory using very specific materials and methods results in a durable electrical connection between the frame pieces so that any failure in the module insulation or external conductor insulation will result in all pieces of the frame receiving equal voltage. The factory bonding also insures that when the module frame is properly field-grounded at one of the marked and tested points, the entire module frame is maintained at the ground potential under fault conditions.

During the bonding process, all screw fasteners are precisely torqued to the specified value by automated equipment or by trained technicians using torque screwdrivers. The factory bonding materials and methods are evaluated for low resistance and durability during the listing process. Subsequent to the listing, if the manufacturer changes any of the bonding materials or methods, the changes must be reevaluated by the listing agency. The materials (including any screws or washers) are not specified generically; they are specified to the original equipment manufacturers (OEM) and must always be obtained and used from those sources unless any change is reevaluated by the listing agency.

Photo 4. Installed per instruction manual—but copper touching aluminum?

Contrast this precisely controlled and evaluated factory bonding system with the field-installed grounding techniques used to connect a copper equipment-grounding conductor to the aluminum module frame. Grounding PV modules is haphazard at best for a number of reasons. The first is that the module manufacturers do not realize the importance of this connection to the overall safety of the system. Second and possibly the most critical is that the Bonding/Grounding section in UL 1703 does not clearly distinguish the differences between bonding and grounding. The manufacturers have the impression that the bonding techniques and materials used in the factory may be applied to the grounding connections made by the installer in the field. Instruction manuals and hardware (sometimes supplied) show techniques which are not consistent with good electrical connections (see photo 4). Field-made connections using a threaded fastener are rarely torqued to the specified value, even when that value is given in the module instruction manual, because few PV installers have or carry torque screwdrivers. The field grounding connection may or may not be inspected by the AHJ, and they are never tested for overall continuity. Also, since the PV system can operate without trouble for many years, there is little motivation to inspect these connections after the original installation.

In late 2007, UL issued an "Interpretation” of UL 1703 which focused on module field grounding. This interpretation was to be used by module manufacturers and the module testing/certification/listing laboratories (UL, CAS, TUV and ETL) to evaluate and possibly revise the grounding methods, hardware (if any) and instructions supplied with the modules. Unfortunately, it is not possible for the laboratories to review all existing modules and supposedly modules are reevaluated every five years when the listing must be renewed. A few module manufacturers have revised their grounding instructions, but it would appear that these revised instructions in some cases may have not been carefully evaluated or even reviewed by the certification/listing laboratories.

Grounding Instructions Not Consistent

The UL Interpretation of UL 1703 has very specific information about not putting dissimilar metals into contact and gives a chart that shows the compatibility of various metals. Copper and aluminum may not come in contact and if they do, the aluminum at the contact point will be removed by galvanic corrosion destroying the connection. Inadvertent contact between the bare copper equipment-grounding conductor and an aluminum module frame or rack does not pose problems because the small amount of aluminum that may disappear is not involved in a specific electrical contact.

Photo 6. Tinned copper braid offers no protection for aluminum module frame.

In some cases, the instructions specify the use of a stainless-steel washer to isolate the copper conductor from the aluminum frame, but no surface preparation of the oxidized, anodized, and/or clear-coated aluminum module frame is specified. If this method were to be done properly with surface preparation, then the presumption is that the mechanical fastener (screw and nut) and the stainless steel washer would carry the fault currents. But these devices are generic in nature and have not been evaluated for carrying current.

A casual examination of any common electrical device such as a circuit breaker, a receptacle outlet, or a wall switch will show that the mechanical fastener provides only pressure to push the two electrical conductors together. Those mechanical fasteners (screws) are not normally designed or specified to carry currents, unless they have been specifically tested and evaluated to do so during the listing of the device. An example of a device where the provided screw has been evaluated to carry current is the neutral-to-ground bonding screw used in many service-entrance panels.

To further confuse the situation, it appears that the high currents, steel plates, and test methods used in UL Standard 467 for evaluating and listing grounding devices may not be applicable to evaluating grounding devices used to ground PV modules and racks where the currents are low and the aluminum surfaces are oxidized, anodized or clear coated.

Help Is Coming

AHJ comments on poor grounding and confusing grounding instructions to the UL AHJ reporting web site may speed the process, as UL is made more aware of the pressing problem.

http://www.ul.com/global/eng/pages/offerings/perspectives/regulator/electrical/productreport/

Although not presently on the market, some modules have been built with plastic frames—maybe they will return.

When the grounding instructions furnished by the module manufacturer are inadequate or contradict NEC or UL requirements, the PV installer and the inspector must come to some agreement on what is an acceptable module grounding method and hardware.

One method used by utility companies for many years to connect copper conductors to aluminum busbars in an outdoor environment uses surface preparation and a tin-plated copper lay-in lug listed for direct burial. A description of this method was presented in The "Perspectives on PV” column in the IAEI News for September-October 2008. It may also be found in the Burndy instructions for installing lay-in lugs and in Appendix G of the NEC/PV Suggested Practices manual. Both may be found on my web site—below. (See photo 7).

Summary

Grounding is critical to the short- and long-term public safety of PV systems. These systems may be producing power 50 years from the installation date with possibly deteriorating electrical connections and insulations. Grounding all exposed metal surfaces for the life of the systems is mandatory, and the techniques used may have to exceed existing Code and UL requirements.

For Additional Information

If this article has raised questions, do not hesitate to contact the author by phone or e-mail. E-mail: jwiles@nmsu.edu Phone: 575-646-6105

A color copy of the latest version (1.9) 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: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html

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. Copies of "Code Corner” written by the author and published inHome Power Magazineover the last 10 years are also available on this web site: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html

For an intensive 7–8 hour training session on PV and the NEC, see the web site above for a schedule of presentations made to inspectors, electricians, electrical contractors, and PV professionals. The hosting organization usually charges a very nominal fee and controls registration and attendance

Read more by John Wiles

No discussion of PV systems would be complete without a look at the newest inverter technologies that the installer and inspector will face. These new technologies include the microinverter and the AC PV module.

Microinverters

The inverters that have been covered in the past several issues are known as string inverters because they operate with a string of series connected PV modules. These inverters range in power from one megawatt down to about 700 watts. DC maximum system voltages can get as low as about 125 volts.

Photo 1. Enphase microinverter

The new Enphase microinverter (photos 1 and 2) is a small inverter (hence the name) that is designed to work with a single PV module and operate at a maximum of about 70 volts dc. The inverter is connected directly to the PV module using the existing conductors and connectors (now locking in most cases) attached to both the module and the inverter. Available units are rated in the 170–210 watt range, but as with other PV products, ratings and specifications change continually.

Photo 2. Pair of Enphase microinverters showing ac and dc cables

The microinverter is a utility-interactive inverter with dc ground-fault protection (690.5) in the current offering. The Enphase microinverter has been on the market since early 2009 and it internally grounds the positive dc module conductor. That internal grounding bond (via the dc ground-fault protection circuits,NEC690.5) requires that the inverter have a dc grounding electrode terminal and that terminal is on the outside of the Enphase microinverter case. Other types and brands of microinverters may accomplish grounding differently or go to an ungrounded configuration using modules with the new "PV cable” required byNEC690.35 for such systems.

Photo 3. Microinverter AC output connector

The microinverter has ac input and output cables and connectors and has been listed in a manner that will allow multiple inverters to be connected with up to about 15 units on a single output cable. See photo 3. With a power output in the 170–210 watt range (depending on model), the rated ac output current at 240 volts will range from 0.71 amps to 0.79 amps. On the 14 AWG cable with a 15-amp overcurrent device, the rated current for that circuit is limited to a maximum of 12 amps. This rating will allow 1–15 inverters to be installed on the same ac output cable.

AC PV Modules

DC Connections

In the standard PV module/microinverter combination, the microinverter dc connection to the PV module may have to be disconnected to replace the microinverter should it or the module fail (say once in every 20–30 years). While the voltage will be a maximum of about 70 volts with current inverter designs, the current may be in 3–7 amp range and the connectors could possibly be damaged at this voltage and current, posing a possible safety hazard. While a very few inspectors may request a costly and impractical load-break rated disconnect, the code-compliant solution is really quite simple. The back of the PV module must be accessed to reach these dc connections and this generally requires that the module be unfastened from the mounting system. Since the module is accessible and is being accessed, just putting a blanket or other opaque material over it per 690.18 will reduce the dc output voltage and current (and the ac current) to near zero, allowing the module/inverter dc connectors to be safely opened. Opening this connection with the module blacked out will, in all likelihood, be safer than opening the same connectors on a module in a high-voltage string of modules. Of course, the AC PV module has no accessible dc connections.

AC Connections

Each microinverter or AC PV module will have an ac input/output cable to allow the multiple inverter parallel connections. This cable may carry currents in bright sunlight of 0.7 amps at 240 volts from the first module/inverter in the set to as much as 12 amps at 240 volts through the last connector of the set that has multiple devices. Servicing the single AC PV module or utility-interactive microinverter could be accomplished by covering the module to reduce the dc and hence the ac current to zero. However, not covering all modules in the set would allow current from other, non-covered, modules/inverter to flow through the cable and, at 240 volts, could damage the connector and possibly pose a shock hazard when opening these ac connections under load. To some extent, the hazard is minimized because the inverter anti-islanding circuits shut down very rapidly, reducing any arcing when the ac connector is opened.

Photo 5. Numerous parts are required for a string inverter PV system

Opening the ac circuit at the PV backfed breaker in the building service entrance panel would be safe solution if that breaker could be locked open, but breaker locks are few and far between and lock-out/tag-out procedures are not generally used in residential and commercial electrical systems.

NEC690.14(D) addresses the situation and it would appear that the installation of a separate ac disconnect on the roof near the AC PV modules or microinverters will meetCoderequirements and enhance safety. A common 60-amp unfused, pull-out air conditioning disconnect costs less than $10 at the building supply centers. It provides the disconnect, a place to terminate the ac output cable from a set of microinverters or AC PV modules, a place to originate the field-installed wiring system to the ac load center in the house, and is usually cheaper than a separate junction box and cover.

Advantages

The use of microinverters and AC PV modules will proliferate due to several advantages they offer over the conventional string inverters.

The first is a simplified set of installation requirements and a reduced number of separate parts. See photos 5 and 6 for some quantitative differences in the amount and types of equipment involved in installing an AC PV Module system vs. a conventional string inverter system.

Photo 6. Far fewer parts are needed to install the Andalay PV/ microinverter system

In a dc series-connected string of PV modules, module mismatch is sometimes an issue that affects the string performance. Modules come out of the factory with slight (up to 10%) variations in specifications. The string of modules in a dc system cannot deliver current above the current delivered by the weakest module in the string. The mismatch between module currents results in some lost power compared to a dc string of modules that are equal in every specification. The PV modules near the top of an array on a sloped roof may operate hotter (and at reduced power) than modules lower down on the roof due to hot air rising behind the modules. Depending on how each string of modules is connected, some loss of power may occur if hot modules are connected in series with cooler modules.

Shading is also a problem in a conventional string-inverter configuration. The shading of a single module will result in a power loss from that module, but may also reduce power from the other, non-shaded modules in the string.

The microinverter and the AC PV module work at the individual module level. Each inverter extracts the maximum power from that module no matter what the other modules in the PV array are doing. The output of each is independent of the other modules/inverters in the set. The outputs of the microinverters or AC PV modules are connected in parallel, rather than in series, and this isolates one from another.

The outputs are at 240 volts ac and these ac output circuits act much like ac branch circuits. They go dead when the ac utility power is removed at any disconnect in the circuit so they do not pose the safety hazards associated with the daytime "always-energized” dc circuits operating at hundreds of volts between the modules and the inverter. If a short circuit or a ground fault were to occur in these ac output circuits, the dedicated branch-circuit breaker would open and the circuit would go dead. Opening the main service disconnect or the backfed PV breaker will de-energize those PV ac output circuits—a boon to fire fighters.

Disadvantages

There may be some cost impact of using AC PV modules or microinverters on each module when compared to the use of the single string inverter. However, two factors must be considered. The cost of the dc switchgear and the required conduit (or other appropriate wiring method) for the dc conductors inside the building plus the cost of the single inverter must be compared to the added cost of multiple small inverters or AC PV modules with an inverter on each module.

Then there are the life cycle costs. Modules are guaranteed for power production for 25 years, but can be expected to produce power for as long as 50 years. Large inverter manufacturers do not seem to be interested in or able to extend the average longevity past about 15 years at reasonable costs. The microinverter manufacturers, using different construction methods and topologies, are predicting significantly longer lives for their products. Time will reveal all.

A Word of Warning

The microinverter or AC PV module output must be connected on a dedicated circuit per 690.64. See the "Perspectives on PV” in recent editions of theIAEI Newsfor details on how to connect multiple sets of these devices. They should never be connected to a circuit protected by a GFCI or AFCI, because neither of these devices has been tested or listed for backfeeding.

Summary

2010 will see numerous microinverters and AC PV modules being installed. They are being sold in the home improvement centers and building supply houses as well as in local electrical supply houses, and the general public will be buying them. Inspectors must become familiar with these devices and the Code requirements that apply to them. See the author’s web site below for a white paper on connecting and grounding the Enphase microinverter.

For Additional Information

If this article has raised questions, do not hesitate to contact the author by phone or e-mail. E-mail: jwiles@nmsu.edu Phone: 575-646-6105

A color copy of the latest version (1.9) 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: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html

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. Copies of "Code Corner” written by the author and published in Home Power Magazine over the last 10 years are also available on this web site: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html

The author makes 6–8 hour presentations on "PV Systems and the NEC” to groups of 60 or more inspectors, electricians, electrical contractors, and PV professionals for a very nominal cost on an as-requested basis. A schedule of future presentations can be found on the IEE/SWTDI web site.

Read more by John Wiles

Many larger PV systems cannot meet the requirements for a load-side (of the service disconnect) connection to the premises wiring system and a supply-side connection must be considered.

Code Considerations

The supply-side connection (also known as a service-entrance tap) is allowed by theNational Electrical Code(NEC) and is addressed in a number of sections in theCode.

Section 690.64(A) {moving to 705.12(A) in the 2008-2011NEC} allows a supply (utility) side connection as permitted in 230.82(6). Section 230.82(6) indicates that solar photovoltaic equipment is permitted to be connected to the supply side of the service disconnect.

Photo 1. A breaker as a supply-side tap. But is it Code legal?

It is evident that the connection of a utility-interactive PV inverter to the supply-side of a service disconnect is essentially connecting a second service-entrance disconnect to the existing service and many, if not all, of the rules for service-entrance equipment must be followed. Many years ago, the National Fire Protection Association (NFPA) made an informal interpretation that these supply-side taps were essentially a second service entrance on the building or structure and should be treated as such.

Section 240.21(D) allows the service conductors to be tapped and refers to 230.91. In general, the other "Tap Rules” of Section 240 do not apply because they were not developed to address two sources of power in a tap circuit, nor were they developed to assure safe operation when one source is an unprotected utility power source.

Photo 2. Utility-required ac disconnects. Could have been combined into one.

Section 230.91 requires that the service overcurrent device be co-located with the service disconnect. A circuit breaker or a fused disconnect would meet these requirements. See photo 1. A utility-accessible, visible break, lockable (open) fused disconnect (aka safety switch) used as the new PV service disconnect may also meet utility requirements for an external PV ac disconnect in areas where utilities require such an additional disconnect. See photo 2.

Section 230.71 specifies that the service disconnecting means for each set of service-entrance conductors shall be a combination of no more than six switches and sets of circuit breakers mounted in a single enclosure or in a group of enclosures. The PV system may be counted as a separate service (230.2) and could have up to six disconnects of its own.

Photo 3. Directory for PV system

Location and Directory

Section 230.70(A) establishes the location requirements for the service disconnect. Section 705.10 requires that a directory be placed at each service equipment location, showing the location of all power sources for a building. See photo 3. Locating the PV ac disconnect adjacent to or near the existing service disconnect may facilitate the installation, inspection, and operation of the system. See photo 4.

Size Matters

Obviously the size of the new PV service disconnect is important. It will normally be sized at 125% of the rated output current from the PV inverter(s). But in small systems, a question arises; how small can it be? Section 230.79 addresses the rating issue. Some inspectors have looked at 230.79(A) and say that it can be as low as 15 amps if that value is at or above the rating of the inverter output circuit. The connection of other allowed loads at this level is common.

I would suggest caution here, since the tap is to service-entrance conductors rated at 100 amps and above. The typical 15-amp circuit breaker with 10,000 amps of interrupt capability, in this application, may not be able to withstand the available fault current, since it is not protected and coordinated with any main breaker typically rated at 22,000 amps. Of course, Section 110.9 should be followed and fault current calculated. Also a service entrance rated 30-amp fused disconnect with 15-amp fuses could be used.

Photo 4. PV ac disconnect above closed service disconnect

Another consideration is the size of the service-entrance conductors, the new tap conductors, and the size of the terminals on available switchgear rated at 30 or 60 amps. The added conductors between the existing service-entrance conductors and the new service disconnect will be subjected to available fault currents and will have no protection except that provided by the fuse on the primary of the utility transformer. Making them as large as possible, with an upper limit of the size of the existing service-entrance conductors would seem prudent, but small disconnects will not accept very large conductors.

For these reasons, I suggest that Section 230.79(D) be used as the requirement for the smallest service disconnect for PV inverter supply-side taps. Section 230.79(D) requires that the disconnect have a minimum rating of 60 amps. This would apply to a service-entrance rated circuit breaker or fused disconnect.

Section 230.42 generally requires that the service-entrance conductors be sized at 125% of the continuous loads (all currents in a PV system are worst-case continuous). The actual rating should be based on 125% of the rated output current for the utility-interactive PV inverter as required by 690.8. The service tap conductors must have a 60-amp minimum rating from 230.79(D). Temperature and conduit fill factors must be applied.

For a small PV system, say a 2500-watt, 240-volt inverter requiring a 15-amp circuit and overcurrent protection, these requirements would appear to require a minimum 60-amp rated disconnect, with 15-amp fuses; fuse adapters would be required. Fifteen-amp conductors could be used between the inverter and the 15-amp fuses in the disconnect.

Photo 5. Meter-main combo—do not tap.

Section 230.42(B) requires that the conductors between the service tap and the disconnect be rated not less than the rating of the disconnect; in this case, 60 amps.

How we would deal with the 60-amp disconnect, 15-amp over-current requirements using circuit breakers is not as straightforward. A circuit breaker rated at 60-amps would serve as a disconnect, and it could be connected in series with a 15-amp circuit breaker to meet the inverter overcurrent device requirements. In this case, the requirements of 690.64(B)(2) should be applied for the series connection. See "Perspectives on PV” in the November-December issue of the IAEI News for details.

Section 110.9 of the NEC requires that the interrupt capability of the equipment be equal to the available fault current. The interrupt rating of the new disconnect/overcurrent device should at least equal the interrupt rating of the existing service equipment. The utility service should be investigated to ensure that the available fault currents have not been increased above the rating of the existing equipment. Fused disconnects with RK-5 fuses are available with interrupt ratings up to 200,000 amps.

Section 230.43 allows a number of different service-entrance wiring systems. However, considering that the tap conductors are unprotected from faults, it is suggested that the conductors be as short as possible with the new PV service/disconnect mounted adjacent to the tap point. Making these tap conductors as large as the service-entrance conductors, while not a Code requirement, would also add a degree of safety. Of course, the added disconnect must be able to accept the larger conductors. Conductors installed in rigid metal conduit would provide the highest level of fault protection.

All equipment must be properly grounded per Article 250 requirements. See 250.24(B) for bonding requirements. As a service disconnect, neutral-to-ground bonding would generally be required at the new disconnect, and a grounding electrode conductor should also be added.

The actual location of the tap will depend on the configuration and location of the existing service-entrance equipment. The following connection locations have been used on various systems throughout the country.

On the smaller residential and commercial systems, there is sometimes room in the main load center to tap the service conductors just before they are connected to the existing service disconnect. In other installations, the meter socket has lugs that are listed for two conductors per lug. Of course, adding a new pull box between the meter socket and the service disconnect is always an option. Combined meter/service disconnects/load centers frequently have significant amounts of interior space where the tap appears to be possible between the meter socket and the service disconnect. However, tapping this internal conductor or bus bar in a listed device such as a meter-main combination would violate the listing and should not be done. See photo 5.

Where the service-entrance conductors are accessible, a new meter base (socket) could be added ahead of the combination device. A tap box would then be added between the new socket and the combination device. The meter would then be moved from the combo device to the new socket, jumper bars added to the old socket and the old socket covered.

In the larger commercial installations, the main service-entrance equipment will frequently have bus bars that have provisions for tap conductors. The tap can only be made by the organization supplying the service equipment and that is usually a UL 508 panel shop. They can tap the equipment and maintain the listing on the equipment.

In all cases, safe working practices dictate that the utility service be de-energized before any tap connections are made. Additional service-entrance disconnect requirements in Article 230 and other articles of the NEC will apply to this connection.

Summary

Supply-side service entrance taps are useful for larger PV systems where the conditions of the load-side tap cannot be met. These supply-side taps normally require that the power be removed from the service to ensure a safe installation.

The next "Perspectives on PV” will address the new micro inverters and ac PV modules.

Sharp-eyed inspectors will note in the last issue that the 45 -amp breaker used for the PV system will be too large for the 200- amp panel. The panel must be 225 amps or the main breaker reduced to at least 195 amps if loads allow.

For Additional Information

If this article has raised questions, do not hesitate to contact the author by phone or e-mail. E-mail: jwiles@nmsu.edu Phone: 575-646-6105

A color copy of the latest version (1.9) 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: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html

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. Copies of "Code Corner” written by the author and published in Home Power Magazine over the last 10 years are also available on this web site: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html

The author makes 6–8 hour presentations on "PV Systems and the NEC” to groups of 60 or more inspectors, electricians, electrical contractors, and PV professionals for a very nominal cost on an as-requested basis. A schedule of future presentations can be found on the IEE/SWTDI web site.

Read more by John Wiles

Connecting the utility-interactive inverter to the utility grid properly is critical to the safe, long-term, and reliable operation of the entire system. The ac output circuit requirements and the circuits that carry the inverter current in the premises wiring are somewhat complex. However, meetingCoderequirements can and should be accomplished to ensure a safe and durable system.

The circuit sizing and overcurrent device on the ac output of the utility-interactive inverter was covered in the September-October issue ofIAEI News. Even though power and current flow from the inverter to the utility, it should be noted that the utility-end of this circuit is where the currents originate that can harm the conductors when faults occur. Any overcurrent protection should be located at the utility end of the inverter ac output circuit and not at the inverter end of this circuit.

Photo 1

Although the inverter may require an external disconnect, if that disconnect function is achieved, as it commonly is, by a circuit breaker, then the conductor ampacity calculations may be more complicated as noted below. It is good practice to install the inverter near the backfed load center so that the backfed breaker commonly used to interconnect the inverter with the utility can also be used as the ac inverter disconnect required by 690.15. This places the overcurrent device at the utility-supply end of the circuit and groups the ac disconnect for the inverter with the dc disconnect.

Load-side connection

There are two types of connections allowed by the Code for interfacing the output of the utility-interactive inverter to the utility power. They are made on either the supply side or the load side of the main service disconnect of a building or structure (690.64). The load side of the main service disconnect is the most common connection used for the residential system and smaller commercial system under about 10 kW. NEC 690.64(B) [moving to 705.12(D) in 2008 and 2011] covers the requirements and it is heavy reading at best.

There were changes in 690.64 between the 2005 NEC and the 2008 NEC and the IAEI News issue for July-August 2008 discussed them.

Inspectors need to know this material and how to apply it because many PV installers are not familiar with the details of the requirements.

Photo 2. Multiple inverters require special connections

Code-making panels since 1984 have maintained that 690.64(B)(2) will be rigorously applied to any circuits supplied from multiple sources where protected by overcurrent protective devices (OCPD) from each source. Such sources would include the output of PV inverter(s) and the utility supply.

This Code section requires that the ratings of all OCPD supplying power to a conductor or busbar be added together. The sum of the ratings of those breakers must be less than or equal (in other words: may not exceed) 120% of the rating of the busbar or the ampacity of the conductor. In equation form:

PV OCPD + Main OCPD <= 120% R, where R is the ampacity of conductor or rating of busbar.

120% factor depends on breaker location

The 120% factor came about in previous code cycles because it was determined that the demand factors on residential and small commercial systems would be such that it was unlikely that the conductor or panel would ever be loaded to 100% of rating. Even if the sources could supply 120% of the rating of the busbar or conductor, loads connected to that same busbar or conductor not exceeding the busbar rating would not pose an overload problem. In order to use this 120% factor, any backfed breaker carrying PV currents must be located at the opposite end of the busbar from the main breaker or main lugs supplying current from the utility (photo 1). The same location requirement would apply to any location of the supply overcurrent devices on any conductor. If the PV inverter OCPD cannot be located as required, then the 120% in the above requirement drops back to 100% and the installation under the load side connection becomes more difficult.

Photo 3. Two inverters with PV ac combining panel

The Article 240 tap rules do not apply to these inverter connections since the tap rules were developed only for circuits with one source. The OCPD for the inverter output circuit should be located, as mentioned above, at the point nearest where the utility currents could feed the circuit in the event of a fault.

Examples

1. A dwelling has a 125-amp rated service panel (bus bar rating) with a 100-amp main breaker at the top. How large can the backfed PV breaker be that must be located at the bottom of the panel?

PV OCPD + Main OCPD <= 120% of Panel rating

120% of panel rating = 1.2 x 125 = 150 amps

PV + 100 <= 150, therefore the PV OCPD can be up to 50 amps

2. Suppose it was 100-amp panel with a 100-amp main breaker. What PV breaker could be added?

PV + 100 <= 1.2 x 100 = 120

The maximum PV backfed circuit breaker would be rated at 20 amps.

3. A 200-amp main panel with a 200-amp main breaker would allow up to 40 amps of PV breaker, which could be any combination of breakers that added up to 40 amps on either line 1 or line 2 of the 120/240V panel.
PV + 200 <= 1.2 x 200 = 240

PV <= 240-200= 40 amps

4. Working the problem from the inverter end, we start with the continuous rated inverter output current. This is usually the rated power divided by the nominal line voltage, unless the inverter specifications list a higher continuous output current (sometimes given at a low, line voltage).

A 3500-watt, 240-volt inverter has a rated ac output current of 3500/240 = 14.58 amps.

Photo 4. Utility-required disconnect, fused

The output circuit must be sized as 125% of 14.58 = 18.2 amps (690.8). The next larger overcurrent device would be a 20-amp OCPD and this would be consistent with the use of 12 AWG conductors if there were not any very large deratings applied for conditions of use. This system could be connected to a 200-amp panel or a 100-amp panel providing that the backfed 20-amp breaker could be located at the bottom of the panel.

There is sometimes a tendency to use that 30-amp breaker and those 10 AWG conductors that happen to be on the truck. While this would pose no problems for conductor ampacity or protection, the inverter specifications may limit the maximum size of the output OCPD and larger values may not be used [110.3(B)].

No bottom breaker position?

From the above equations, it can be seen that if the backfed PV OCPD cannot be located at the bottom of the panel or at the end of the circuit, it is not possible to install the backfed breaker without changing something. That 120% allowance drops to only 100%.

Any panel that has a main breaker rated the same as the panel rating in the above equations would not allow any OCPD to be added. The 100%-of-the-panel-rating factor (instead of 120%) would equal the rating of the main breaker and the equation would force the PV breaker rating to be zero.

In a few cases, an NEC Chapter 2 load analysis might reveal that the service for the dwelling needed to be only 150 amps, but a 200-amp panel was installed with a 200-amp main breaker just to provide extra circuit positions. In this case, it might be possible to substitute a 150-amp main breaker for the 200-amp breaker, and even without the bottom position being open, 50 amps of PV breaker could be installed.

Systems with multiple inverters

Many residential and small commercial systems use more than one inverter (photo 2). If the local utility requires an accessible, visible-blade, lockable disconnect on the output of the PV inverters, then more than one inverter could not be connected directly to the main panel (photo 3). The two or more inverters would have to have their outputs combined in a PV ac inverter combining subpanel (PV ac subpanel) before being routed through the utility disconnect and then to the main panel (photo 4). The disconnect is not normally fused, but some are, depending on the system configuration. The PV ac subpanel rating, the rating of the disconnect, and the ampacity of the conductor to the main panel are also controlled by 690.64(B) requirements.

Here is another example

The dwelling has a 200-amp main service panel with a 200-amp main breaker and there is an empty breaker position (2-poles) at the bottom of the panel. The utility requires an external disconnect switch and it is desired to install a PV system that has a 3500-watt and a 4500-watt inverter. A PV ac panel will be used to combine the outputs of the two inverters and the output of that PV ac panel will be routed through the utility disconnect and then to a single backfed breaker in the main service panel.

The ratings of the output circuits of each inverter are:
3500/240 = 14.58 amps, 1.25 x 14.58 = 18.2 amps; use a 20-amp breaker and 12 AWG conductors.

4500/240 = 18.75 amps, 1.25 x 18.75 = 23.43 amps; use a 25-amp breaker and 10 AWG conductors.

The 20 and 25-amp breakers are mounted in the bottom of a PV ac panel, and a main-lug only panel will be installed. Normally, no loads will be connected to this subpanel. It will be dedicated to the PV system.

The next step is to calculate the backfed breaker that must be placed in the main service panel to handle the combined output of both inverters from the PV ac subpanel and to protect the conductor carrying those combined outputs under fault conditions from high utility currents.

The combined currents from both inverters are:

14.58 + 18.75 x 1.25= 41.6
and the overcurrent device should be 45 amps.

The ratings of OCPD supplying the conductor from the PV ac subpanel to the 45-amp breaker, the utility disconnect switch, and supplying that PV ac panel are now defined as 45, 20, and 25 amps.

The panel rating and the ampacity of the conductor are controlled by 690.64(B)(2) and it would be incorrect to guess that the answer might be 45 amps as it would be in a normal load subpanel.

45 + 20 + 25 <= 120% R,
where R is the panel rating or the ampacity of the conductors.

90 <= 1.2 R, R >= 90/1.2 = 75 amps.

With this number, we would round up to a 100-amp panel, and a 100-amp disconnect would be used. The conductor size for this ampacity would be 4 AWG since the breakers would typically have 75°C terminal temperature limits.

If the reader really wants to see why we must use 75 amps and not 45 amps for sizing the panel and the conductors, send the author e-mail for a white paper on the subject.

Summary

The load-side connection for the utility-interactive PV inverter is not the easiest subject to understand, but the correct application of these requirements will yield a safer, more durable system. When the requirements of load-side connections become complex and expensive, a supply-side connection is used, and we will examine those requirements in the next Perspectives on PV.

For Additional Information

If this article has raised questions, do not hesitate to contact the author by phone or e-mail. E-mail: jwiles@nmsu.edu Phone: 575-646-6105

A color copy of the latest version (1.9) 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: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html

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. Copies of "Code Corner” written by the author and published in Home Power Magazine over the last 10 years are also available on this web site: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html

The author makes 6–8 hour presentations on "PV Systems and the NEC” to groups of 60 or more inspectors, electricians, electrical contractors, and PV professionals for a very nominal cost on an as-requested basis. A schedule of future presentations can be found on the IEE/SWTDI web site.

This work was supported by the United States Department of Energy under Contract DE-FC 36-05-G015149

Read more by John Wiles

Connecting the utility-interactive inverter properly is critical to the safe, long-term and reliable operation of the entire system. Proper grounding of the inverter will minimize the possibility of electrical shocks and damage from surge currents. Understanding and applying the requirements of NEC 690.47 to the inverter grounding connections is somewhat complex but ensures that the user will be safe and that the inverter and other equipment will suffer minimum damage under surge conditions.

Equipment Grounding Conductors

18.1.8 Equipment grounding leads or equipment grounding terminals shall be provided for each input and each output circuit.

Grounding Electrode Terminal

18.2.1 Equipment intended to be installed as service entrance equipment or equipment containing the main dc or ac bonding connection shall be provided with a grounding electrode terminal.

Photo 3. Three grounding terminals

These grounding connection requirements will require that each inverter have a minimum of three terminals available for making the proper connections. All three terminals may be on a common bus bar or mounted separately in the inverter. They will normally all be connected (bonded) together electrically in the inverter and they will be connected to the inverter chassis. See photos 1, 2 and 3.

To ensure proper grounding of the entire PV system, it is necessary to connect all three of these terminals properly. Unfortunately, some manufacturers and their certification/listing agencies are letting inverters get on the market that do not have all three of these terminals. Because other countries do not ground PV systems like our Code requires, some inverters get certified/listed without a dc grounding electrode terminal. The Europeans use the term protective earth (PE) terminal instead of equipment grounding terminal. Others have only one equipment grounding terminal, not the required two and do not even have a grounding electrode conductor terminal. See photo 4.

Photo 4. Only one equipment grounding terminal (PE) and no grounding electrode conductor terminal

Some inverters have an external grounding electrode terminal and the equipment grounding conductors are permanent leads coming out of the inverter. See photos 5 and 6.

When the installer or inspector finds one of these inverters with missing grounding terminals, the manufacturer and the listing agency should be contacted. It is possible, in some cases, to splice the ac and dc equipment grounding conductors together and connect them to a single equipment grounding terminal. However, the grounding electrode conductor must be connected directly to the proper terminal and should not be spliced.

Connecting the Inverter to Ground (Earth)

The Code had significant changes between the 2005 and 2008 editions in Section 690.47(C) that addresses the dc grounding electrode connection. As far as the author can determine, either the requirements of this section in NEC-2005 or the permissive requirements in NEC-2008 may be applied to connect the grounding electrode conductor when installing a system in jurisdictions using either Code. A proposal has been submitted for NEC-2011 that includes all three methods and will have improved clarity. That proposal is repeated and may help in understanding what the requirements are for 690.47(C) in NEC-2008. Note that paragraphs (1) and (2) align with 690.47(C)(1) and 690.47(C)(2) inNEC-2005 and paragraph (3) aligns with 690.47(C) inNEC-2008. Reviewing this proposal may assist the reader in understanding the existing 690.47(C) in the 2005 and 2008 Codes.

690.47(C) Systems with Alternating- and Direct-Current Grounding Requirements. PV systems having direct current (dc) circuits and alternating current (ac) circuits with no direct connection between the dc grounded conductor and ac grounded conductor shall have a dc grounding system. The dc grounding system shall be bonded to the ac grounding system by one of the methods listed in (1), (2), or (3).

This section shall not apply to ac PV modules.

When using the methods of (2) or (3), a visual inspection shall be made to ensure that the existing ac grounding electrode system meets the applicable requirements of Article 250, Part III.

FPN No. 1: ANSI/Underwriters Laboratory Standard 1741 for PV inverters and charge controllers requires that any inverter or charge controller that has a bonding jumper between the grounded dc conductor and the grounding system connection point have that point marked as a grounding electrode conductor (GEC) connection point. In PV inverters, the terminals for the dc equipment grounding conductors and the terminals for ac equipment grounding conductors are generally connected to or electrically in common with a grounding busbar that has a marked dc GEC terminal.

FPN No.2: For utility-interactive systems, the existing premises grounding system serves as the ac grounding system.

(1) Separate DC Grounding Electrode System Bonded to the AC Grounding Electrode System. A separate dc grounding electrode or system shall be installed, and it shall be bonded directly to the ac grounding electrode system. The size of any bonding jumper(s) between ac and dc systems shall be based on the larger size of the existing ac grounding electrode conductor or the size of the dc grounding electrode conductor specified by 250.166. The dc grounding electrode system conductor(s) or the bonding jumpers to the ac grounding electrode system shall not be used as a substitute for any required ac equipment grounding conductors.

Exception: Where the existing ac grounding electrode is not readily accessible, the bonding conductor shall be permitted to be connected to the ac grounding electrode conductor as close as possible to the ac grounding electrode with an irreversible splice.

(2) Common DC and AC Grounding Electrode. A dc grounding electrode conductor of the size specified by 250.166 shall be run from the marked direct-current grounding electrode connection point to the ac grounding electrode. This dc grounding electrode conductor shall not be used as a substitute for any required ac equipment grounding conductors.

Exception: Where the existing ac grounding electrode is not readily accessible, the dc grounding electrode conductor shall be permitted to be connected to the ac grounding electrode conductor as close as possible to the ac grounding electrode with an irreversible splice.

(3) Combined DC Grounding Electrode Conductor and AC Equipment Grounding Conductor. An unspliced, or irreversibly spliced, combined grounding conductor shall be run from the marked dc grounding electrode conductor connection point along with the ac circuit conductors to the grounding bus bar in the associated ac equipment. This combined grounding conductor shall be the larger of the size specified by 250.122 or 250.166 and shall be installed in accordance with 250.64(E).

Photo 5. External grounding electrode terminal

While any of the three methods of making connections to the inverter grounding electrode terminal may be used, there are advantages and disadvantages to each.

Method 1, in the above proposal, (similar to 690.47(C)(1) in NEC-2005) has the advantage of routing surges picked up by the array more directly to earth than methods 2 and 3. However, since the bonding conductor between the new dc grounding electrode must be bonded to the existing premises ac grounding electrode, there is the size, routing and cost of that conductor to consider.

Method 2 (similar to 690.47(C)(2) in NEC-2005) uses fewer components than the other two methods and also routes surges to earth without getting near the ac service equipment.

Photo 6. Equipment grounding conductors as leads attached to the inverter in conduit

Method 3 (similar 690.47(C) in NEC-2008) combines the inverter ac equipment grounding conductor with the dc grounding electrode terminal and thereby uses less copper. However, the requirement to bond the conductor at the entrance and exit of each metallic conduit and enclosure may become difficult with conductor sizes greater than about 6 AWG, especially since the conductor must remain unspliced or irreversibly spliced. Also, any surges picked up by the array will be routed directly to the service equipment and may be more likely to enter the premises wiring system than when grounding electrode conductors are routed more directly to ground.

Summary

Proper grounding connections at the inverter are critical to a safe and properly operating PV system. These connections may be the only connections that the entire system has to earth. All connections must be made and that may prove difficult if manufacturers have not included the proper number of terminals.

In the next Perspectives on PV, we will cover the ac output circuits of the utility-interactive inverter.

For Additional Information

If this article has raised questions, do not hesitate to contact the author by phone or e-mail. E-mail: mailto: jwiles@nmsu.edu Phone: 575-646-6105

A color copy of the latest version (1.9) of the 150-page, PhotovoltaicPower Systems and the 2005 National Electrical Code: Suggested Practices, written by the author, may be downloaded from this web site: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html

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. Copies of "Code Corner” written by the author and published in Home Power Magazine over the last 10 years are also available on this web site: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html

The author makes 6–8 hour presentations on "PV Systems and the NEC” to groups of 60 or more inspectors, electricians, electrical contractors, and PV professionals for a very nominal cost on an as-requested basis. A schedule of future presentations can be found on the IEE/SWTDI web site.

Read more by John Wiles

Photo 1. Inverters

Peak Power Tracking

A PV array is a current source of energy and the output power depends on the load that the inverter places on the array. No loading (zero current) would operate the array at the open-circuit voltage point (V_oc) and the heaviest loading (a short-circuit, not achievable) would operate the array at the short-circuit current (I_sc) point. Neither of these operating points would produce any power output from the array. However, for every condition of sunlight intensity (irradiance) and array temperature, there is a load that will extract the maximum power from the array that the array can produce under those conditions. The utility-interactive inverter will find that maximum or peak power point and track that point as the sunlight and temperature vary throughout the day.

Automatic Operation

Today’s utility-interactive (U-I) inverter is designed, manufactured, tested and certified/listed to operate automatically in the PV system. It seamlessly converts dc power from the PV array into ac power that is fed into the utility supplied premises wiring system. The output of the inverter is functionally connected in parallel with the premises wiring and the utility service.

One of the most important aspects of the inverter is the anti-islanding circuit. The anti-islanding circuit is designed to keep the utility electrical system (both premises wiring and utility feeder) safe in the event that the utility is being serviced or is disconnected at some point in the transmission system, distribution system or premises wiring system.

Unlike the engine-driven generator, which can feed power into a blacked out/disconnected local utility feeder system, the anti-islanding system prevents the inverter from energizing the "dead”power system.

This circuit prevents the inverter from delivering ac power if the utility voltage and frequency are not present, or if they are not within narrowly defined limits. This circuit monitors the voltage and frequency at the output terminals of the inverter. If the voltage varies more than plus ten percent or minus twelve percent from the nominal output voltage the inverter is designed for (120, 240, 208, 277, or 480 volts), the inverter cannot send power to the output terminals. Nor, is there any voltage on these terminals when the inverter shuts down. In a similar manner, if the frequency varies from 60 Hz more than 60.5 Hz or less than 59.3 Hz, the inverter also cannot send power to the ac output. If the utility power is suddenly not present at the output terminals for any reason (inverter ac output disconnect opened, service disconnect opened, meter removed from the socket, utility maintenance, or utility blackout), the inverter senses this and immediately ceases to send power to the output terminals.

The anti-islanding circuit in the inverter continues to monitor the ac output terminals and when the voltage and frequency from the utility return to specifications for a period of five minutes, the inverter is again able to send PV power to the ac output. When the inverter is not processing dc PV power into ac output power, it essentially disconnects from the PV array by moving the load on the PV system to a point where there is no power. Usually this is the V_ocpoint for the PV array.

Circuit Sizing

DC: The dc input circuit to the inverter is sized based on the dc short-circuit current in those conductors. Normally the PV array is rated in watts at standard test conditions (STC) of 1000 watts per square meter (W/m²) of irradiance and a cell temperature of 25 degrees Celsius (°C). In most cases, the array will operate, on average, at a lower power output due to the normal and expected power lost due to module heating. For this reason, inverter manufacturers typically suggest sizing the PV array (STC dc watts) at ten to twenty percent greater than the inverter ac power output rating. It does no short-term harm to connect an even larger PV array to the inverter since the inverter must limit its output to the rated value no matter how much array power is applied. If this over-sized array is used, the inverter will spend more operating time each day at rated power output than it would with a normally sized array. The penalty for designing a system in this manner will be increased module cost for the larger array, some lost power on sunny, cool days, and possibly some slight reduction in the inverter life due to longer high temperature operating temperatures.

Photo 2. Cold weather increases Voc

AC: The ac output circuit of an inverter must be sized at 125 percent of the rated output current of the inverter (690.8). Some inverter manufacturers specify the rated current or a range of values (due to varying line voltages from nominal). If this specification is not given, then the rated power may be divided by the nominal line voltage to determine a rated current. For example, a 2500-watt inverter operating at a nominal voltage of 240 volts would have a rated current of

2500 watts/240 volts = 10.4 amps

These inverters are not capable of providing any sustained (more than a second) surge currents, so the rated output current is all that can be delivered. When faced with a short-circuit, the rated output current is all that can be delivered, but more than likely, the reduced line voltage due to the fault will cause the inverter to shut down.

Dedicated Circuit

NEC 690.64(B)(1) requires that the inverter output be connected to the utility power source at a dedicated disconnect and overcurrect protective device (OCPD). In most systems this is a backfed breaker in a load center/panelboard [690.64(B)]. Inverters may not have their outputs connected directly to another inverter or directly to an ac utility-supplied circuit without first being connected to the dedicated disconnect/OCPD. The utility-interactive micro inverters and the ac PV module are an exception to this rule since they are tested and listed to have multiple inverters connected in parallel on a single circuit with only one OCPD/disconnect device for the entire set of inverters.

The OCPD must be sized at a minimum of 125% of the rated inverter output current (or total of the output rated output current from multiple micro inverters or ac PV modules) and it must protect the circuit conductor from overcurrents from the utility side of the connection. It is usuallynota good idea to install a larger OCPD than the minimum required value (allowing a round up to the next standard value is OK and needed) because the inverter may (as part of the listing/instructions) be using the OCPD to protect internal circuits.

Is It a Branch Circuit?Out #@$%^ Typo!Consider the typical residential branch circuit.

1. It is protected by an OCPD at the source of power (the utility) that can damage it (emphasis added).

2. If the breaker protecting the branch circuit is opened, it becomes completely "dead” (deenergized).

3. If the branch circuit has a solid ground fault or a line-to-line fault, the OCPD will open and protect the conductor.

4. The branch circuit may be wired with Type NM cable in residential applications.

Now consider the circuit between the utility-interactive inverter and the dedicated disconnect/OCPD (usually a breaker).

1. This circuit is protected by an OCPD at the source of power (the utility) that can damage it. Since the circuit is sized at 125 percent of the rated output current of the inverter and the inverter current is limited to the rating, the inverter is not a source of power that can damage the conductor.

2. If the breaker protecting this circuit is opened, it becomes completely "dead” (deenergized).

3. If this circuit has a solid ground fault or a line-to-line fault, the OCPD will open and protect the conductors. And the inverter will shut down.

4. It would appear in every practical sense that this utility-interactive inverter ac output circuit is just like a branch circuit and it, too, may be wired with Type NM cable in residential applications.

So, these ac output circuits from the utility-interactive inverters can be wired like any other branch circuit in a residence. Of course, the inverters are surface-mounted devices and there may be the possibility of exposed Type NM cables being subject to physical damage. If they are, then conduit or other wiring method would be required.

There are no flush mounted inverters on the market yet, but I expect they will appear with internal fans and vents to get rid of the heat they generate.

The typo

Inspectors. There is a typo in 690.31(E) of the2005 NECand2008 NEC. I am the guilty party that let it slip through—on two code cycles. The first sentence starts out:

Photo 3. Cold weather increases module voltages and sunlight helps too.

"Where direct-current source or output circuitsofa utility interactive inverter from a building-integrated or other photovoltaic system ….”

The word "of” should be "to” and will be corrected in the2011 NEC.The requirement for metallic raceways applies only to the sunlight-energized dc PV source or PV output conductor.

GFCIs and AFCIs

The ac output of a utility-interactive inverter should not be connected to a GFCI or AFCI breaker as these devices are not designed to be backfed and will be damaged if backfed. These devices have terminals marked line and load and have not been identified/tested/listed for back feeding.

Summary

A detailed understanding of PV equipment and how power flows in a PV system should enable better, more thorough inspections of these systems. Better inspections will result in better, safer PV installations. We will continue with more information on the utility-interactive inverter ac output in the next "Perspectives on PV” in our top-to-bottom tour of the PV system.

For Additional Information

If this article has raised questions, do not hesitate to contact the author by phone or e-mail. E-mail: jwiles@nmsu.edu Phone: 575-646-6105

A color copy of the latest version (1.9) 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: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html

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. Copies of "Code Corner” written by the author and published inHome Power Magazineover the last 10 years are also available on this web site: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html

The author makes 6–8 hour presentations on "PV Systems and theNEC” to groups of 60 or more inspectors, electricians, electrical contractors, and PV professionals for a very nominal cost on an as-requested basis. A schedule of future presentations can be found on the IEE/SWTDI web site.

This work was supported by the United States Department of Energy under Contract DE-FC 36-05-G015149

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About John Wiles: John Wiles works at the Southwest Technology Development Institute (SWTDI) at New Mexico State University. SWTDI has a contract with the US Department of Energy to provide engineering support to the PV industry and to provide that industry, electrical contractors, electricians, and electrical inspectors with a focal point for code issues related to PV systems. He serves as the secretary of the PV Industry Forum that will be submitting 30+ proposals for Article 690 in the 2008 NEC. He provides draft comments to NFPA for Article 690 in the NEC Handbook. As an old solar pioneer, he lives in a stand-alone PV-power home in suburbia with his wife, two dogs, and a cat - permitted and inspected, of course.

/01/In our top-to-bottom perspective of a photovoltaic (PV) system, we are still on the dc circuits from the PV array and are approaching the inverter. There are always a few details that get overlooked in designing, installing and inspecting these systems.

Photo 1. Enphase 175 Watt Micro inverter

The Conductors

We have noted previously that single-conductor, exposed cables (type USE-2 or the new PV cable/PV wire) will be used for the module interconnecting cables. Both of these cable types will generally be available only in basic black. And as 200.6(A)(2) notes, this black cable, even when smaller than 4 AWG, may be marked white as a grounded conductor at the time of installation.

Normally the exposed single-conductor cables are transitioned to a conduit wiring method when the circuits leave the PV array. Conductors in conduit, while they could be USE-2/RHW-2 (for flame and smoke retardant) or PV wire, are typically THHN/THWN-2 because they are less costly and the -2 rating is needed for the outdoor, wet environment and the high temperatures of conduit in sunlight [310.15(B)(2)]. Unfortunately, 14–10 AWG conductors with THHN/THWN-2 insulation are not widely available due to low demand. (I’ll get e-mails telling me differently if I am misinformed). Of course THHN/THWN is available, but it doesn’t have a wet, 90°C rating. I expect that demand will increase for the small-conductor THHN/THWN-2 cables as inspectors start applying 310.15(B)(2) to roof top HVAC installations. Due to the limited availability of 14–10 AWG THHN/THWN-2, I tend to support the use of USE-2/RHW-2 in the conduits with a white marking although theCodedoes not clearly state that it can be used with markings in that location. XHHW-2 would also be a suitable alternative.

Photo 2. Xantrex 100kW Inverter

Although most PV arrays installed in the recent past have had the dc negative conductor grounded (and colored white), new arrays may have the dc positive conductor grounded and colored white. Of course, there are no designated color codes for the ungrounded conductor, but common sense would indicate that on a negatively grounded array with the negative conductor colored white, the positive, ungrounded conductor would be most clearly marked and understandable if it were colored red. However, many installations use a black positive conductor and that is still acceptable under theCode. In the positively grounded systems where the positive grounded conductor is colored white, the ungrounded negative conductor would be most clearly understood if it were black.

Now, and in increasing numbers in the next few years, the use of transformerless inverters will dictate the use of ungrounded PV arrays (690.35) and then we can go to a "red is positive” and "black is negative” color coding since there will be no grounded conductor.

Oh yes. We should not ignore the newest bipolar PV arrays and bipolar inverters. In these systems, we will have red, positive conductors, black, negative conductors, and white, grounded conductors.

Photo 3. SATCON 1 MegWatt Inverter

As before, the grounded conductor in a PV dc disconnect should never be switched, although bolted, isolated, terminal-block connections are acceptable.

Wiring Methods, Continued

All circuits in a PV system, as in other electrical systems, must be wired using a Chapter 3 or 690.31 method that is suitable for the application and the environment. However, there are frequently questions about the circuits between the dc PV disconnect and the inverter. As far as theNECis concerned, if these circuits are in protected environments, they could be wired with type NM cable. Of course, local codes may dictate other requirements such as the need for using raceways inside commercial structures for all electrical wiring.

The Inverter

Utility-interactive inverters range in size from 175 watts (photo 1) to 1 megawatt and come in all shapes, sizes and colors (photos 2 and 3). New models are being introduced monthly. These inverters will be listed by UL, CSA, ETL, and TUV Rheinland, all of whom are designated as nationally recognized testing laboratories (NRTL) by OSHA for testing and listing PV modules, inverters, combiners, and charge controllers using standards published by UL.

Photo 4. Solectria 13kW Inverter with external disconnects

Some inverters have only a single set of dc input terminals. With these designs, an external dc PV disconnect must be installed. Even if the inverter has more than one set of input terminals for parallel separate strings (source circuits) of modules, external dc PV disconnects must be used on each input. (See photo 4).

Photo 5. Inverter with internal disconnects as part of the inverter

Other inverters have internal dc disconnects or disconnect housings that attach to the main inverter section containing the electronics package. The method used to mount the internal disconnects, the ease and accessibility of the disconnects, and the manner in which they are separated from the inverter proper vary from brand to brand and from product to product. The installer and the AHJ must reach a mutual conclusion on the suitability of these disconnects for meeting the various disconnect requirements in theCode.

Since the inverters are listed with the disconnects, it can be presumed that the disconnects are properly rated for the dc load break operation. If the inverter is installed in a location that meets the 690.14 requirements for the main PV dc disconnect, then it would appear that the internal disconnect would meet this requirement.

Photo 6. Inverter with internal disconnects that can be separated from inverter

Meeting the requirement for maintenance disconnects (690.15) will require additional considerations. If the inverter were to require factory service, can the energized PV source or output circuits be disconnected from the inverter safely when there is no external disconnect? If a disconnect housing is attached to the inverter and that housing does not have to be removed to service the inverter, then some degree of safety is assured. However, if the energized conductors must be disconnected from internal switches and pulled through small conduit knockouts, the situation must be examined carefully. Will qualified people who know how to disable the array be doing the removal? Or will the unqualified person try to pull energized conductors through the knockouts? (See photos 5 and 6).

DC Input Fusing

Some models of both small (<10kW) and large (>100 kW) inverters have dc input fuses mounted inside the inverter or inside a combiner/disconnect device attached to the inverter. The smaller fuses (30 amps or less) are usually mounted in "finger-safe” fuse holders that allow the fuse to be safely replaced in an un-energized state.

Photo 7. PV combiner with disconnect at output

However, when the fuse rating goes over 30 amps with values as high as 400 amps or more, these fuses are mounted in exposed fuse holders or bolted directly to a dc busbar. One side of each fuse is tied together with the dc input of the inverter. The other side of each fuse is hardwired to the output of a PV dc combiner and these combiners will be scattered throughout the PV array—sometimes over acres of real estate. Although the inverter can be turned off and the dc input capacitors allowed to discharge (up to five minutes), each fuse is still energized from its own input and the combined inputs of all of the other fuses through the common bus bar. The only way to safely service these fuses is to go through the entire PV array, find all of the combiners, and open or pull each and every source circuit fuse (those less-than-30 amp "finger safe” fuse holders). An optional disconnect at the output of every combiner speeds this process and makes servicing the combiner fuses safer, but all disconnects must be located and opened. (See photo 7).

Photo 8. Disconnects for each input installed near the inverter

When these fuses are present in the input of the larger inverters, the safest way to provide for service is to install a dc disconnect near the inverter on each dc input to a fuse. (See photo 8). These collocated disconnects can be easily opened, and with the inverter turned off, the fuses can be safely removed in a de-energized state.Removedis a term used to describe prying out 400-amp fuses with a screwdriver because you have broken two plastic fuse pullers trying to remove them from those very tight fuse holders.

Summary

A detailed understanding of PV equipment and how power flows in a PV system should enable better, more thorough inspections of these systems. Better inspections will result in better, safer PV installations. We will continue with more information on the utility-interactive inverter in the next "Perspectives on PV” in our top-to-bottom tour of the PV system.

For Additional Information

If this article has raised questions, do not hesitate to contact the author by phone or e-mail. E-mail: jwiles@nmsu.edu Phone: 575-646-6105

A color copy of the latest version (1.9) 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: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html

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. Copies of "Code Corner” written by the author and published inHome Power Magazineover the last 10 years are also available on this web site: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html

The author makes 6–8 hour presentations on "PV Systems and theNEC” to groups of 60 or more inspectors, electricians, electrical contractors, and PV professionals for a very nominal cost on an as-requested basis. A schedule of future presentations can be found on the IEE/SWTDI web site.

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Read more by John Wiles

In our top-to-bottom perspective of a PV system, we need to look at one more component usually located on the roof. This is the PV source-circuit combiner and it will be followed in the dc circuit by the PV dc disconnecting means.

The PV Combiner

The PV source-circuit combiner is found on larger residential systems and on most large commercial systems. PV systems that have a dc rating above about 6 kW may have sufficiently large numbers of modules that more than two strings of modules are required to get the desired array power. Since module voltages range widely and module power ratings can vary from 40 watts to 300 watts, there are no hard and fast rules relating the need for a dc combiner to a specific number of modules in an array.

Photo 1. PV source-circuit combiner with fuses

Multiple Strings May Need Combiner

The rated output voltage of the PV modules and the inverter dc input characteristics determine how many modules may be connected in a series string. See "PV Math” in the January-February 2009IAEI News.The power rating of each module and the number of modules in a string determine the power rating of a string. The desired array power rating and the power rating of the inverter determine how many strings can be connected in parallel. Normally two strings can be connected in parallel without requiring a combiner containing overcurrent devices [See 690.9(A) Ex]. If more than two strings are needed, then overcurrent protection on each string may be required and these overcurrent devices are placed in a PV source-circuit combiner. See "Questions from the AHJ—To Fuse or Not to Fuse” in the May-June 2008 IAEI News for the details.

Photo 2. PV source-circuit combiner with circuit breakers' poor workmanship

A combiner may use either fuses (typically on high-voltage, utility-interactive systems) or circuit breakers (used on systems operating at a nominal 48 volts or below). [See photos 1, 2, and 3].

It should be noted that the combiners shown in photos 1 and 3 have exposed circuit terminals and busbars near the overcurrent devices. They are not dead front when opened, and voltages on the exposed terminals and busbars may approach 600 volts on many systems in cold weather. Although not dead front, these combiners meet the "intent” of the NEC where a tool is required to get access to energized surfaces (terminals and busbars). In these cases, the combiners have screw-on covers and the tool required to open the combiner is a screwdriver. NEC-2008 requires that combiners be listed and UL has determined that the listing must be to UL Standard 1741 (the PV inverter standard) [690.4(D)]. Although listing is required, UL 1741 has not yet been modified to specifically require that combiners be dead front. Some of the newer units are dead front, and eventually that requirement will be in the standard. See photo 4 of a dead front unit that has terminal covers made of clear plastic.

Photo 3. PV source-circuit combiner on large system

Wiring from the PV Array to the PV Disconnect

Although the conductors between the modules and the return circuit from one end of a string to the other are permitted to be single conductor cables in free air, as soon as these circuits leave the array location they must transition to a standard chapter 3 wiring method. That wiring method must be suitable for the hot, wet environment found on roofs, and sunlight resistance is also a must. Electrical metallic tubing (EMT) is frequently used. The ampacity of the conductors is based on the short-circuit current being carried in that circuit and must be corrected for the conditions of use. In many cases, terminal temperature limitations on combiners or fused disconnects may dictate further ampacity corrections. See the "The Nature of the PV Module: Limited Currents Have Benefits and Drawbacks,” September-October 2007 IAEI News for more details.

An equipment grounding conductor should be run with the circuit conductors in the conduit. Where the PV source circuits are unfused, the size under the 2005 NEC was based on 125 percent of the rated short-circuit current (Isc) for the circuit. In the 2008 NEC, Isc is used directly in Table 250.122 to select an equipment-grounding conductor. The reduction in size of the dc equipment-grounding conductor is due to the 2008 NEC requirement that nearly all PV systems have ground-fault detectors that will limit ground-fault currents in the equipment grounding conductors. On systems with PV source or output circuit fuses, the normal procedure of using the fuse value in Table 250.122 is used (690.45).

Photo 4. Dead front PV source-circuit combiner (photo credit AMTec Solar)

In many systems, the equipment grounding conductors may be as small as 14 AWG between the PV modules. However, in areas where winds, snow, ice and other environmental factors are significant, a larger equipment grounding conductor should be considered to provide additional mechanical protection (690.46).

The dc PV Disconnect

The dc PV disconnecting means (PV disconnect) should be installed in a readily accessible location, either inside or outside the building at the point of first penetration of the conductors (690.14) (photo 5). Since Section 690.31(E) allows the PV source or output conductors to penetrate the building surface on the roof (if they are routed in a metal raceway inside the building), it appears that the PV disconnect can be mounted inside the building in any readily accessible location. However, this NEC allowance may not be the safest option or even very clearly defined in the national Code.

Photo 5. PV dc disconnecting means

This parallel wording of 690.14(C)(1) to the requirements for the ac service disconnecting means 230.70(A)(1) may need further examination since in the world of ac utility-power, removal of the ac revenue meter can effectively disable the ac power in a structure where the ac service disconnect is inside a locked structure. With a dc PV disconnect inside a locked structure, the readily accessible definition may not be appropriate. Many jurisdictions require that the PV disconnect be located within sight of the ac service disconnect or meter on residences. This is usually on the outside of the building. On commercial buildings, the PV system may be some distance from the ac service disconnect, and a directory may be used to show the location of all disconnects, both ac and dc (705.10).

The disconnect should break all ungrounded conductors, but should not open a grounded conductor. Grounded conductors in PV systems may be either the negative or positive source-circuit conductors and should have white insulation, or where larger than 6 AWG, be marked with a white marking. The type of module used determines which circuit conductor should be grounded and the inverter must be compatible with that polarity of grounded conductor. The dc bonding jumper in a utility-interactive PV system is commonly inside the inverter and is a part of the ground-fault detection/interruption systems required by 690.5.

If the grounded source-circuit conductor is opened by the switch in the disconnect, the marked grounded conductor becomes ungrounded and may be energized with respect to ground up to the open-circuit voltage of the system. This represents an unsafe condition for people servicing the PV array and for that reason the Code prohibits the use of disconnects, breakers or fuses in grounded PV dc conductors unless they are part of an automatic ground-fault detection/interruption system (690.13).

Photo 6. Disconnect Labels

Photo 6 shows the front of a PV dc disconnect with the labels required by 690.17 and 690. 53. The 690.17 warning is required because the load terminals of this disconnect are connected to the inverter dc input which may be energized for up to five minutes after the disconnect has been opened. The filter and energy storage capacitors in the inverter will be discharged after this time. The 690.53 label with the dc voltage and current ratings will allow the AHJ to determine if the correct cables have been installed.

Power flow in a PV system is from the PV array through the dc PV disconnect, the inverter, the ac disconnect and finally to the grid. This power flow sometimes confuses installers on how to properly connect the dc and ac disconnects. Note the upper line-side terminals on the disconnect shown in photo 7 are covered by an insulated cover. Also note the switchblades, the fuse holder terminals (if any), and the load-side lower terminals are exposed and easily touched. A general safety rule is that the most dangerous circuits should be connected to the protected line-side terminals. If this is done, it is less likely that energized terminal connections will be accidentally touched when the door of the disconnect is open. In the PV dc disconnect, the PV source or output circuits should always be connected to the line-side terminals. The dc input to the inverter is connected to the load-side terminals and the 690.17 warning label is required as shown in photo 6.

Photo 7. Line and load connections are important

For the ac PV disconnect the circuit connected to the utility source should be the line side of the disconnect with the inverter ac output connected to the load side. No warning label is required because, when the disconnect is opened, the inverter ceases to produce power within a fraction of a second and the exposed load side terminals pose no shock hazard.

Summary

Attention to theCoderequirements in 690 and other articles plus an understanding of PV equipment and how power flows in a PV system should enable these systems to be installed and operated in a safe manner. The utility-interactive inverter is next on our top-to-bottom tour of the PV system.

For Additional Information

If this article has raised questions, do not hesitate to contact the author by phone or e-mail. E-mail: jwiles@nmsu.eduPhone: 575-646-6105

A color copy of the latest version (1.9) 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: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html

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. Copies of "Code Corner” written by the author and published inHome Power Magazineover the last 10 years are also available on this web site: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html

The author makes 6–8 hour presentations on "PV Systems and the NEC” to groups of 60 or more inspectors, electricians, electrical contractors, and PV professionals for a very nominal cost on an as-requested basis. A schedule of future presentations can be found on the IEE/SWTDI web site.

This work was supported by the United States Department of Energy under Contract DE-FC 36-05-G015149

Read more by John Wiles

As we look at the PV array in a PV system, we find that many installers and inspectors are confused by the new system voltage calculations that may be required by the Code specific to PV systems. Code fine print notes (FPN) also address voltage drop that may be applied to the dc wiring from the array to the inverter. This article will cover both of those subjects.

Photo 1. Cold weather increases module open-circuit voltage

PV Math—Module Open-Circuit Voltage

A PV module or a string of series-connected modules has a rated open-circuit voltage (Voc) that is measured (and labeled) at 25 degrees Celsius (C) [77 degrees Fahrenheit (F)]. This voltage increases from the rated voltage as the temperature drops below 25°C. It is necessary to calculate this voltage at the expected lowest temperature at the installation location to ensure that it is less than the maximum input voltage of the inverter and less than the voltage rating of any connected cables, switchgear, and overcurrent devices (usually 600 volts). Since parallel connections of strings do not affect the open-circuit voltage, the number of strings connected in parallel is not involved with this calculation.

Section 690.7 in the 2008 NEC requires that the open-circuit voltage (Voc) of a PV array be determined at the lowest expected temperature at the installation location where module temperature coefficients are available. In previous editions of the NEC, Table 690.7 could be used to determine a multiplier that was applied to either the module or string (series connection of PV modules) rated Voc. The table can also be used under the 2008 NEC where module temperature coefficient data are not available.

The rated Voc is measured at 25°C (77°F) and is printed on the back of the module and in the technical literature of the module. To use the table, all one has to do is to determine the lowest expected temperature, look up the factor from the table for that temperature (which ranges between 1.02 at 24°C to 1.25 at -40°C), and multiply the factor by the rated Voc.

For example, a module has a Voc of 35 volts and is going to be installed where the temperature dips to -17°C. The factor from Table 690.7 in the 2008 NEC is 1.16 and the cold temperature Voc for this module is 35 x 1.16 = 40.6 volts.

If 12 modules were going to be connected in series, the string Voc in cold weather would be 12 x 40.6 = 487.2 volts.

We could also calculate the string voltage at rated conditions first and then apply the temperature factor. In this case, the 12 modules in series would have a string open-circuit voltage of 12 x 35 = 420 volts at 25 degrees C. Then we apply the 1.16 factor and get 1.16 x 420 = 487.2 volts; the same answer as before.

While the table is still valid and has been refined with 5°C increments, new modules may have different technologies than the silicon module technology used to develop the table.

NEC-2008 Requirements Differ

Table 690.7 is based on an average type of crystalline PV module that has been the most widely used over the last thirty years. However, we now have modules with different internal types of PV cells, and the table may not apply very well to these newer modules. Section 690.7 in the 2008NECrequires that where the module manufacturer’s temperature coefficients data are available they will be used. These temperature coefficients are found in the technical literature of nearly all modules and can also be obtained directly from the manufacturer. Unfortunately, different manufacturers present the temperature coefficients in two different forms.

Percentage Coefficients

One way of presenting these data is to specify them as a percentage change, and they are expressed as a percentage change in Voc for a change in temperature measured in degrees C. Note that the temperature used is a change in temperature from the rated 25°C.

For example: The Voc temperature coefficient is given as

-0.36% per degree C or -0.36% / °C.

The module has a Voc of 45 volts at 25°C (77°F) and is going to be installed where the expected lowest temperature is -10°C (14°F). Because the temperature coefficient is given in degrees C, we must work in degrees C. The change in temperature is from 25°C to -10°C. This represents a change in temperature of 35 degrees. The minus sign in the coefficient can be ignored as long as we remember that the voltage increases as the temperature goes down and visa versa.

If we apply the coefficient, we can see that the percentage change in Voc resulting from this temperature change is

0.36% / °C x 35°C = 12.6%.

This percentage change can now be applied to the rated Voc of 45 volts. And, at -10°C, the Voc will be 1.126 x 45 = 50.67 V.

Eleven of these modules could be connected in series and the cold-weather voltage would be 11 x 50.67 = 557.37 V, and that voltage is less than the 600-volt equipment limitation.

Millivolt Coefficients

Other PV module manufacturers express the Voc temperature coefficient as a millivolt coefficient. A millivolt is one, one-thousandth of a volt or 0.001V.

A typical module with an open-circuit voltage (at 25°C) of 65 volts might have a temperature coefficient expressed as

-240 mV per degree C or -240 mV / °C.

If we install it where the expected low temperature is -30°C (-22°F), then we have a 55°C degree change in the temperature from 25°C to -30°C. Again, we must work in degrees Celsius since that is the way the coefficient is presented.

Millivolts are converted to volts by dividing the millivolt number by 1000.

240 mV / 1000 mV/V = 0.24 volts

The module Voc will increase 0.24 V/°C x 55 °C = 13.2 volts as the temperature changes from 25°C to -30°C.

The module Voc will increase from 65 volts at 25°C to 65 + 13.2 = 78.2 volts at the -30°C temperature.

Let us suppose that the inverter maximum input voltage was listed as 550 volts. How many modules could be connected in series and not exceed this voltage? We take that maximum inverter voltage of 550 volts and divide it by the cold-weather open-circuit voltage for the module of 78.2 volts.

550 / 78.2 = 7.03 modules and the correct answer would be seven (7) modules.

7 x 78.2V = 547.4V

Eight modules could not be used because the open-circuit, cold-weather voltage would exceed 550 volts.

8 x 78.2V = 625.6V

Expected Lowest Temperature?

Where do we get the expected lowest temperature? Normally, this temperature occurs in the very early morning hours just before sunrise on cold winter mornings. The PV modules are, in many cases, a few degrees colder than the air temperature due to night-sky radiation effects. The illumination at dawn and dusk are sufficient to produce high Voc, even when the sun is not shining directly on the PV array and has not produced any solar heating of the modules. A conservative approach would get weather data that show the record low temperatures and use this as the expected low temperature. Other data show more moderate low temperatures associated with the data used to size heating systems. However, these data are not widely available. The National Renewable Energy Laboratory (NREL) maintains data on a web site that shows the record lows for many locations in the US.

http://rredc.nrel.gov/solar/old_data/nsrdb/1961-1990/redbook/sum2/state.html

Local airports and weather stations may have historical data on low temperatures

Also, weather.com has some of these data on file accessed by zip codes

http://www.weather.com/weather/climatology/monthly/zip code

PV Math—Module Short-Circuit Current

In most silicon PV modules, the module short-circuit current does increase very slightly as temperature increases, but the increase is so small as to be negligible at normal module operating temperatures. It is normally ignored.

Fine Print Notes—Voltage Drop

Fine print notes are not part of the Code—at least until the AHJ reads them, and then they become part of his or her personal code.

In the common, utility-interactive PV system, the PV array may operate at a nominal 48 volts to voltages near 600 volts. With nominal, peak-power, and open-circuit voltages to deal with, the installer and inspector are sometimes in a quandary as to how to calculate the voltage drop from the PV array to the inverter.

The utility-interactive inverter will normally operate in a manner that keeps the array voltage near the peak-power voltage (also called the maximum power point). While this voltage can vary with temperature, and temperatures vary considerably, using the rated maximum power point voltage and current of the modules results the easiest method of calculating voltage drop.

A typical PV array may have a single string of ten modules in series connected through 200 feet of 10 AWG USE-2/RHW-2 conductors to the inverter. The maximum power point numbers for the module are:

Vmp = 55V Imp = 5.5 amps, where the subscript mp means at maximum power.

For a single string of 10 modules, the string maximum power point numbers are:

Vmp = 550V Imp = 5.5 amps.

Table 8 in Chapter 9 of theNECgives conductor resistance per 1000 feet at 75°C.

For an uncoated, stranded 10 AWG conductor, the resistance is 1.24 ohms per 1000 feet.

The total conductor length (both ways) must be used in the calculation and this is 400 feet.

The resistance for 400 feet of a 10 AWG conductor is 400 / 1000 x 1.24 = 0.496 ohms.

The current at the maximum power point is 5.5 amps. Voltage drop is found by multiplying this current by the conductor resistance:

5.5 x 0.496 = 2.728 volts.

Expressed as a percentage, 2.278/550 x 100 = .496% or about 0.5% and that is much less than the FPN recommendation of three percent for most circuits. Of course, the losses in the PV dc disconnect were not counted, but they are typically less than one percent on these circuits.

For Additional Information

If this article has raised questions, do not hesitate to contact the author by phone or e-mail. E-mail: jwiles@nmsu.eduPhone: 575-646-6105

A color copy of the latest version (1.8) of the 150-page,Photovoltaic Power Systems and the 2005 National Electrical Code: Suggested Practices, published by Sandia National Laboratories and written by the author, may be downloaded from this web site: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html

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. Copies of "Code Corner” written by the author and published inHome Power Magazineover the last 10 years are also available on this web site: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html

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. A schedule of future presentations can be found on the IEE/SWTDI web site.

Read more by John Wiles

Photovoltaic (PV) systems will be producing hazardous voltages and currents for 50 years or more. Over that period of time, they may or may not be operational and they may or may not be maintained. Proper grounding of all exposed metal surfaces in the system that may be energized by internal faults, poor terminations or failing conductor insulation is one of the most important requirements in a code-compliant system. Even in a failing or failed system, maintaining all metal surfaces at ground (or earth) potential will minimize the possibility of electrical shocks. Those grounding connections must be maintained in a harsh outdoor environment where they are exposed to heat and cold, solar radiation (ultraviolet radiation and added heat), dirt, rain, wind, ice, sleet, and snow.

Photo 1. Aged PV modules - still producing power

Why is grounding PV different from grounding HVAC?

PV modules, with an active life measured in many decades, will be in place longer than the outdoor unit of a HVAC system. When the performance of an HVAC system deteriorates, it is usually inspected and repaired promptly. PV systems suffer gradual degradation that is not usually monitored, and the PV array may remain installed on the roof even after the system has been decommissioned or abandoned when the inverter fails—a common occurrence when sufficient funds are unavailable to make the inverter repair or replacement. (See photos 1 and 2).

Photo 3. HVAC outside unit, well maintained and with single grounding point

HVAC units have only a few separate pieces, the equipment grounding points are well marked, and the factory installed bonding jumpers and screws effectively bond all parts of the listed device together (photo 3). HVAC components are typically made of steel and the equipment-grounding terminals are electrically and chemically compatible with copper conductors.

Photo 4. Thousands of PV modules in a large array, each to be grounded

On the other hand, PV systems have numerous modules (tens to thousands) and mounting racks that must be individually grounded (photo 4). PV modules and mounting racks are typically made of aluminum and are not compatible with copper conductors. See "Perspectives on PV” in the September-October 2004 and March-April 2008IAEI Newsfor issues related to grounding aluminum-framed PV modules.

Are we getting better?

Inspectors throughout the country have been flooding Underwriters Laboratories (UL) with e-mails about poor PV module and PV system grounding techniques and equipment that they are seeing in the field (photo 5). And, as a result, UL is getting tough on grounding. In the fall of 2007, UL issued an "Interpretation” of the existing standard for PV modules (UL 1703). The current state of affairs with respect to grounding is in part due to a confusing section in UL 1703 that combines bonding requirements and instructions

Photo 5. Poor PV module grounding

(connecting the module frame parts together in the factory) with grounding requirements (installing the external equipment-grounding connection in the field) in one section. Methods and equipment used in the factory to bond the module frame sections together are evaluated during the listing process. However, the same level of scrutiny cannot be applied to field-installed, equipment-grounding methods, and the same parts and techniques used in the factory are generally not appropriate in the field.

The Interpretation clarifies the intent of the standard in several areas:

1. Dissimilar metals, like copper and aluminum, cannot come into contact with one another at the equipment-grounding connection point. A chart is provided showing numerous metals and which types can be in contact without galvanic corrosion problems.

2. Any threaded fastener used for grounding must pass the same durability tests as any threaded fastener used for other electrical connections. It must be fastened and unfastened ten times without damage to the threads. This requirement will probably result in the demise of the use of thread-cutting or thread-forming screws for module grounding because threads in soft aluminum cannot pass this requirement.

3. The module manufacturer must provide or designate the specific hardware and methods used to ground the module, and those instructions must be included in the module instruction manual. UL will evaluate the grounding hardware and methods throughout the entire testing and listing/certification process on new modules and also when existing modules come up for recertification.

UL is also working on changes to UL 1703 that will clarify the requirements, markings, and instructions for grounding PV modules. At some point, they will develop a separate standard that will allow the evaluation and listing of various universal PV module grounding methods and devices that will work with a number of different module frame geometries. The use of this standard will allow grounding-device manufacturers to meet the standard without having to be tested with each and every separate type of PV module.

In the meantime…

As theCoderequires, instructions and labels provided with a certified/listed product must be followed [110.3(B)]. The listing and certification process is slow, and modules only come up for review every five years. Therefore, it may be some time before all of the instruction manuals meet the clarified intent of UL 1703. And this brings us to the question of new grounding devices

New grounding devices

With respect to new PV module grounding methods and devices, such as clips and washers, the situation is somewhat murky. Of course, the local AHJ can call it as they see it and some jurisdictions have accepted these new devices.

As mentioned above,NEC110.3(B) requires that the instructions and labels provided with a listed product be followed. PV modules are marked for grounding at specific points. Hardware (when provided) and these instructions require the use of the marked points. The instructions do not generally address grounding the module at the mounting holes or at other locations.

A few manufacturers may have tech bulletins that show other methods. These tech bulletins may or may not have been reviewed by UL where they differ from the listed grounding points. UL is attempting to review new manuals and directions submitted by the manufacturer, but at times, the manuals get published without a proper review. Also, even if reviewed, they may not be in compliance with allNECrequirements or may show grounding techniques that have not withstood the test of time. The future UL Standard for PV Module Grounding Methods/Devices will evaluate the long-term durability and reliability of the various grounding methods and devices.
When using a new grounding method, other than a separate wire to each PV module, grounding continuity must be addressed. One of the oldest requirements in the Code is to make a grounding connection first and break it last [250.124(A)]. Consider a module with an internal ground fault to the frame. If the circuit conductors are left connected and the module is unbolted from the grounded rack (disconnecting the frame grounding first rather than last), the module frame may be energized with up to 600 volts to the grounded rack.

Photo 6. One module grounding method

A few PV module manufacturers have listed their grounding devices and racks with specific PV modules so they have a listed combination. Rack manufacturers also are developing grounding devices, but they are not associated or listed at the present time with any particular module.

See Appendix G in the latest version (1.8) of the PV/NEC Suggested Practices Manual for the grounding method we currently use at SWTDI (photo 6). This method is used only if it does not conflict with the module instructions and when those instructions allow the use of a properly listed lug attached to the marked grounding points after appropriate surface preparation has been accomplished.

I have long been encouraging module manufacturers to get their modules tested with these new grounding products and get that information into the instruction manuals, so the AHJs won’t have any questions and the installation will be code-compliant.

TheNECis not holding up any new grounding device or method and Section 690.43 ofNEC-2008 allows the use of these new devices as soon as they have been listed/certified and identified for the use and appear in the module instruction manuals.

We aren’t connected to Mother Earth yet

A related question that will eventually have to be addressed is: To what are these new grounding devices attached? It is necessary to first verify that they can make a durable connection with the module frame, and then the device must make a connection to an acceptable grounding electrode (such as building steel) or to an accepted equipment grounding conductor such as a copper conductor? Aluminum module mounting racks are not currently listed as equipment grounding conductors, but some of the rack manufacturers are getting such a certification/listing. This is necessary because the racks are typically designed for mechanical durability and not electrical connections. Joints may be designed to allow for thermal expansion and contraction, and with aluminum, such "slop” does not make for good electrical conductivity. As theCoderequires for loosely jointed metal raceways (250.98), a provision for electrically bonding the sections of the rack together must be incorporated into the design.

Where we want to be

Photo 7. Integrated modules, rack, conductors, and grounding connections

For Additional Information

If this article has raised questions, do not hesitate to contact the author by phone or e-mail. E-mail: jwiles@nmsu.edu Phone: 575-646-6105

A color copy of the latest version (1.8) of the 150-page, Photovoltaic Power Systems and the 2005 National Electrical Code: Suggested Practices, published by Sandia National Laboratories and written by the author, may be downloaded from this web site: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html

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. Copies of "Code Corner” written by the author and published inHome Power Magazineover the last 10 years are also available on this web site: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html

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. A schedule of future presentations can be found on the IEE/SWTDI web site.

Read more by John Wiles

The final connection between the photovoltaic (PV) power system and the electrical utility grid is always an area of high interest to both inspectors and to the utility, because both agencies are responsible for safety. These connections vary significantly from PV system to system due to the size of the PV system and to the configuration of the existing service-entrance equipment. These variations are made more complex because of differences in Section 690.64 in the National Electrical Code (NEC) between the 2005 and 2008 editions.

Load Side Connections

Section 690.64(B) establishes the requirements for connections of the output of utility-interactive inverters on the load side of the main service disconnect. The key to understanding this section is in carefully reading 690.64(B)(2) and noting that the ratings of overcurrent devices supplying a busbar or conductor must be added so that the sum of these ratings does not exceed the rating of the busbar or conductor. Note that overcurrent devices supplying loads are not counted. Also note that the overcurrent-device (normally a circuit breaker) rating is used in this calculation and not the current flowing through the circuit. Overcurrent devices that would be counted are the main breaker and all breakers being back fed from utility-interactive PV inverters. We can use an equation of breaker ratings to express this requirement:

PV + Main <= Bus or Conductor

In the 2005NEC, this requirement applies to commercial (nonresidential/dwelling unit) PV installations. The requirement essentially says that if, for example, the site has a 400-A main service panel with a 400-A main breaker, then no (zero) PV can be added to the panel. In many commercial installations, this limitation forces the installer to a supply-side connection discussed below.

For residential installations a 120% allowance is added and to make the installations somewhat easier. The equation for residential looks like this:

PV + Main <= 120% Bus or 120% Conductor

In the residential example, a 200-A panel with a 200-A main breaker could have up to 40 amps of backfed PV breakers connected.

In the 2008NEC, 690.64 was rewritten and the 120% allowance was applied to commercial installations if an additional requirement was met. That requirement [690.64(B)(7)] says that the PV backfed breakers must be mounted at the opposite end of the bus from the main breaker or feeder. This location prevents overloading the busbar. If this requirement cannot be met, then the sum of the breakers will be limited to no more than the busbar rating on commercial installations. Note that the requirements apply to both the busbars in a panel or load center and to any conductor that is fed by overcurrent devices from multiple sources.

Figure 1. Section 690.64(B)(2) requirements in the 2005 NEC

In figure 1, the requirements in the 2005 NEC are applied to a multi-story building where a PV system requiring a 15-A circuit breaker is needed in a 100-A main lug panel on the tenth floor. This panel is fed through a 100-A breaker in a 400-A main lug panel on the fourth floor which is, in turn, fed by a 400-A circuit breaker in the 1000-A main distribution panel, which has a 1000-A main disconnect. Since this is a load-side connection, 690.64(B) applies to each panelboard and conductor supplied through an overcurrent device from multiple sources. To meet the requirement in the top floor panel, the panel would have to be removed and replaced with at least a 115-A panel. The feeder between the 100-A panel and the 100-A breaker would also be required to have an ampacity of at least 115 amps. If that top floor panel had a 100-A main breaker, then the feeder would need to be rated at 200 amps to meet the 690.64(B)(2) equation.

At the fourth floor panel, the sum of the rating of the breakers is 100 + 400 = 500 and this exceeds the panel rating of 400 amps. The panel would have to be replaced with a panel having a rating of at least 500 amps. The feeder between the fourth floor panel and the main panel would also have to be rated at 500 amps with a main lug panel. If that fourth floor panel had a 400-A main breaker, then the feeder would be required to be rated for 800 A. Now look at that 1000-A main service panel. The sum of the rating of breakers supply it is 400 + 1000 = 1400, which is significantly larger than the 1000-A rating. It needs to be replaced with at least a 1400-A rated panel.

Yes, life is tough and seemingly unfair, but these requirements were established in 1984 with the concept that they would protect those buses and conductors from overloads even when the PV system was enlarged, the panels had excessive loads placed on them or when the feeders were unknowingly tapped. The 2008 NEC provides some relief as shown in figure 2 and even more relief might come in the 2011 NEC.

Figure 2. Section 690.64(B)(2) requirements in the 2008 NEC

In figure 2, the 120% allowance is put in the calculations for this commercial installation as allowed by 690.64(B)(2) in the 2008 NEC. That 100-A panel on the top floor is OK, because 100 + 15 = 115 which is less than the allowed 120 amps. The same equation applies to the cable when the top floor panel is a main lug panel and the feeder does not need to be changed. If the top floor panel had a 100-A main breaker, then the equation for the feeder conductors would still be 15 + 100 = 115 <= 120 A, and the conductor would remain unchanged because a new sentence in 690.64(B)(2) requires that only the first overcurrent device connected to the inverter output be counted in subsequent equations.

At the fourth-floor 400-A panel, the allowance would be 480 A (120% of 400 = 480), but the additional rule in 690.64(B)(2) requires that only the first overcurrent device connected to the inverter output be counted in subsequent equations. The equation becomes 15 + 400 <= 480 and no changes in the panel are required. With a main lug 400-A panel, the same equation applies to the feeder to the main panel. Also, even if a 400-A main breaker were installed in that 400-A panel, then the cable ampacity would not need to be changed.

Even with the allowances in the 2008 NEC for the load-side connections in 690.64(B), many systems are large enough that ripping out existing load centers and feeders is required and that becomes costly. The supply-side connections allowed by 690.64(A) are used.

Supply Side Connections

Section 240.21 tap rules don’t apply to these service-conductor taps, because the 240.21 requirements were developed over a number of years for a circuit with currents flowing one way from a single source protected by an overcurrent device. The service-entrance tap with a utility-interactive PV inverter may have currents flowing both directions from two sources, and one of them (the utility) has very limited overcurrent protection.

Actually making the tap will depend on the type of equipment involved. Many load centers do not have adequate space to splice to the incoming service conductors. The same holds true for the limited space in meter sockets. In these cases, the supply-side tap will require that a new enclosure be added between the meter and the separate load center.

Photo 2. Much space but tap would violate the listing on the device

Combined meter/load centers like the one shown in photo 1 can only be tapped with permission and instructions supplied by the manufacturers. The cables and busbars (photo 2) may be exposed with plenty of room for the tap, but in most cases, the manufacturer will not allow them to be tapped because it would violate the UL listing on the device. To add a supply-side tap to this type of installation may require adding a new external meter socket and a tap enclosure before the existing meter. Then the existing meter is bypassed with an appropriate set of jumper bars.

Photo 3. Main-Lug-Only Panel

One situation that arises in many parts of the country is the dwelling that has a main-lug-only panel (see photo 3). There is no single main breaker feeding the panel, but up to six main breakers are allowed. Where these panels have one or more empty breaker positions, they can be used as a supply-side connection. The basic restriction (not in the Code—wait for 2011) that would apply to this type of main service panel is that the sum of the overcurrent devices from the PV inverter(s) not exceed the rating of the panel bus or the rating of the service-entrance cables.

Summary

Connections from the PV system to the utility are still somewhat complex. However, the requirements in the 2008 NEC have allowed smaller systems to be more easily connected in the commercial environment. In either residential or commercial PV installations, the requirements of the Code should be studied in some detail to ensure that a safe and durable system is planned and installed.

For Additional Information

If this article has raised questions, do not hesitate to contact the author by phone or e-mail. E-mail: jwiles@nmsu.edu Phone: 575-646-6105

A color copy of the latest version (1.8) of the 150-page, Photovoltaic Power Systems and the 2005 National Electrical Code: Suggested Practices, published by Sandia National Laboratories and written by the author, may be downloaded from this web site: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/PVnecSugPract.html

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. Copies of "Code Corner ” written by the author and published in Home Power Magazine over the last 10 years are also available on this web site: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html

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. A schedule of future presentations can be found on the IEE/SWTDI web site.

Read more by John Wiles

Nearly everyone agrees that the National Electrical Code gets better with every edition. However, new technologies like photovoltaic (PV) power systems and fuel cells are still evolving with new equipment, new wiring procedures, and new installation requirements being developed every week. With new inspectors and new installers coming into the field every day, questions are bound to arise. The question addressed below is very common and is frequently posed by both oldtimers and newcomers. The answer is not directly found in the Code but must be evaluated on a case-by-case basis by examining the system.

When are overcurrent devices (fuses or circuit breakers) needed in the direct current circuits between the PV modules and the utility-interactive inverter?

Before answering this question directly, we first should address the issue that properly rated fuses and properly rated circuit breakers are equivalent in this application and are collectively known as overcurrent protective devices (OCPD). This is true even though the required label on the back of certified/listed PV modules says "Fuse.” In general, PV arrays operating at dc voltages above about 150 volts (cold-weather, open-circuit voltage) may use fuses, and those operating below this voltage may be using either fuses or circuit breakers. These applications are due to the ratings, availability, and cost of the different devices.

In most electrical systems, theNECrequires that every ungrounded circuit conductor be protected from overcurrents that might damage that conductor. Overcurrent protective devices, either fuses or circuit breakers, provide that function. However, some of the smaller utility-interactive PV systems may not need OCPD in the dc circuits that are connected to the PV modules.

PV modules are current-limited devices, and their worst-case, continuous outputs for Code calculations are 1.25 times the rated short-circuit current. An exception to Section 690.9(A) allows conductors to be used with no OCPD where there are no sources of external currents that might damage that conductor.

The module series fuse requirement

Photo 1. Label on back of PV module showing series fuse rating

External sources of current vary from system to system. These external currents can originate from modules or series-connected strings of modules that are connected in parallel to the module of interest, from batteries in the system backfeeding through charge controllers, or from utility currents backfeeding through utility-interactive inverters. The material below will deal only with the utility-interactive PV system with no batteries in the system.

Where required, only one OCPD will protect all modules connected in a single series-connected string of modules [690.9(E)]. A properly rated and located OCPD can protect the modules and properly rated conductors from external overcurrents.

Utility-interactive inverters and backfeed currents from the utility

Many of the smaller utility-interactive inverters (below about 10 kW) are designed so that they cannot backfeed currents from the utility into array faults. However, there are currently no normal operation tests in UL 1741 to validate the lack of backfeeding from the utility, so a manufacturer’s certification should be obtained that the inverter cannot backfeed from the utility into an array fault. Yes, there are abnormal operation tests for backfeed, but theses tests do not rule out backfeed during normal operation of the inverter. Larger inverters and inverters designed for transformerless or bipolar operation may require additional certification that they cannot backfeed.

The most common case—systems with inverters that cannot backfeed from the utility

Photo 1a. Large system with multiple strings of modules will require OCPD.

A basic question is, How many PV modules or strings of modules can be connected in parallel and still meet the National Electrical Code and Underwriters Laboratories requirements (marked on the back of each module) before an OCPD is needed on each module or string of modules?

UL marks the modules based on reverse-current tests as described above. The NEC requires that the manufacturer’s instructions and labels be followed [110.3(B)]. This is a maximum value for the OCPD. Lesser values can be used as long as they meet the NEC requirement of 1.56 times the module short-circuit current (1.56 Isc) to protect the conductor associated with the module or string of modules [690.8(A)&(B)].

In a few cases, module manufacturers have not met (or understood) the Code requirements, and the value of the module protective overcurrent device marked on the back of the module is less than 1.56 Isc (see photo 1). This poses a Code conflict 110.3(B) vs. 690.8,9 and is an issue for UL to rectify.

One string of modules

Photo 2. Unfused dc disconnect

Now let’s look at a PV system with several strings of modules connected in parallel. Keep in mind that we are not determining the rating of any required OCPD, we are merely making some calculations that determine whether or not an OCPD is needed on each string of modules.

Two strings of modules in parallel

Consider two modules or two strings of modules connected in parallel, then connected to the inverter input. Each string of modules can generate a maximum of 1.25 Isc. If a fault occurs in one string, the second, unfaulted string can try to force 1.25 Isc amps into the faulted string. However, we know that the modules in the faulted string can withstand currents up to at least 1.56 Isc or higher (if their marked series fuse rating is higher), and the conductors have an ampacity of at least 1.56 Isc or greater. Therefore, with only two strings of modules, no currents exist in the PV array that can damage the modules or the wiring and no OCPD are required.

Three strings in parallel

Now let us consider a system with three strings of modules connected in parallel. A fault in one string could see currents from the two other unfaulted strings. Each of these unfaulted strings could deliver up to 1.25 Isc under worst-case conditions for a total of 2 x 1.25 Isc =2.5 Isc. Suppose that the module manufacturer had a value of the maximum series fuse marked on the back of the module of exactly 1.56 Isc and the wiring was sized at exactly 1.56 Isc. The currents from the two unfaulted strings at 2.5 Isc would be greater than the series fuse rating of the module and ampacity of the conductors at only 1.56 Isc and they could be damaged. Fuses in all three strings at a minimum value of 1.56 Isc would be required.

However, the module manufacturer does not usually have a marked maximum fuse value of exactly 1.56 Isc. Typically, the module will pass the UL reverse-current tests at a higher current such as 15 amps. As an example, let’s take a module that has a short-circuit current (Isc) of 5 amps and a marked value of the maximum series fuse of 15 amps. The interconnecting conductors between the modules must also have an ampacity of 15 amps, after the appropriate deratings for conditions of use have been applied if the conductors are to be protected. In a system with three series strings of this module, the two unfaulted strings could deliver 2 x 1.25 x 5 = 12.5 amps. Since this current is less than the 15-amp ampacity of the conductors and is also less than the 15-amp maximum series fuse requirement marked on the back of the module, no fuses are required because no damage can be done by overcurrents.

In another example, the module wiring is still 15 amps, as is the fuse rating marked on the back of the module. However, this module has a short-circuit current of 8 amps. The two unfaulted strings could send up to 2 x 8 x 1.25 = 20 amps. This 20 amps exceeds both the conductor ampacity and the ability of the module to withstand reverse currents, so fuses are required in each string of modules. The OCPD must be at least 1.56 Isc (1.56 x 8 = 12.48 amps) and not more than 15 amps. A 15-amp OCPD would normally be used.

Modules with low Isc and high series fuse ratings

Some modules have a low, short-circuit current and a high, maximum series fuse rating. For example, a module with a 1.5-amp Isc and a 20-amp maximum series fuse can have up to 11 strings of modules in parallel without any OCPD. The reader is encouraged to verify this—the author may be wrong.

As can be seen from these three examples, when more than two strings of modules are connected in parallel, a calculation should be done to see if the OCPD is required in each string. When three strings of modules are connected in parallel without fuses, the conductor ampacity may have to be greater than the normal 1.56 Isc.

Larger systems and possible inverter backfeed

If the inverter can backfeed utility currents into the dc PV wiring, the NEC requires that an OCPD be installed in series with the output of all strings (or modules) to protect the cables and the modules from reverse currents from any back feed of ac currents through an inverter. In many cases where there are fused combining boxes mounted at the array, an OCPD may also be needed at the inverter input, since we are assuming that the inverter is a potential source of overcurrents (see photo 3). This OCPD will have a minimum rating based on the number of strings connected in parallel on that circuit and the short circuit current of each string. This OCPD is sized to allow maximum forward currents from the array (all strings of modules) to pass through without interruption and to keep the overcurrent device from operating at more than 80% of rating.

 

Photo 3. Large system fused combiner box

 

Summary

Most utility-interactive PV systems with only one or two strings of PV modules will not require OCPD in the dc wiring between the PV array and the inverter. Systems with three strings or more will require a simple calculation to determine the OCPD requirements. Most current inverters rated at less than 10 kW are not able to backfeed currents from the utility into the dc wiring, but larger inverters and inverters that may be transformerless or designed for bipolar operation should be certified for no backfeeding. For a slightly more technical approach to these requirements and calculations, see Appendix J in the author’s PV Power Systems and the 2005 NEC: Suggested Practices manual (below).

For additional information

If this article has raised questions, do not hesitate to contact the author by phone or e-mail. E-mail: jwiles@nmsu.edu Phone: 575-646-6105

A color copy of the latest version (1.7a) of the 150-page,Photovoltaic Power Systems and the 2005 National Electrical Code: Suggested Practices, published by Sandia National Laboratories and written by the author, may be downloaded from this web site: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/PVnecSugPract.html

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. Copies of "Code Corner” written by the author and published in Home Power Magazine over the last 10 years are also available on this web site: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html

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. A schedule of future presentations can be found on the IEE/SWTDI web site.

Read more by John Wiles

Once upon a time (the 1987 Code cycle) in the land of Quincy, a group of alchemists from a national laboratory was elaborating on the excellence of their photovoltaic (PV) test facility in the distant Land of Enchantment. They showed some senior firefighters a picture of a burned PV module that had been subject to a ground fault and had subsequently melted down. The alchemists failed to mention at the time that this was a prototype, unlisted PV module, that the module was on a concrete pad, and that ground faults in PV systems were somewhat rare. These firefighting pros said to themselves, "PV ground faults lead to fires. Fires on the roofs and in the attics of dwellings are very hard to fight.” They then told the PV industry to propose Section 690.5 for the 1987 NEC to require a ground-fault protection device (GFPD). The proposal was accepted and the requirement was established, but no hardware existed.

Photo 1. One-pole, ground-fault protective device for 48-volt PV system

In 1989, I joined the PV industry as a full-time employee at the Southwest Technology Development Institute. One of my first projects was to develop prototype hardware that could be used to meet the new Section 690.5 requirement. This effort was funded under contract to Salt River Project, a Phoenix, Arizona, electric utility. In the 1987 Code, the requirements for this fire-reduction device were to:

1. Detect ground faults in PV arrays mounted on the roofs of dwellings
2. Interrupt the fault current
3. Indicate that a ground fault had occurred
4. Disconnect the faulted part of the PV array
5. Crowbar or short circuit the PV array

Figure 1. Ground-fault currents go through the bonding conductor

The original GFPD prototype was developed in two versions that were similar except for voltage rating. The basic concept was to insert a 0.5 or 1.0 amp circuit breaker in the dc system-bonding conductor connecting the grounded circuit conductor (usually the negative) to the grounding system (the point where equipment grounding conductors and grounding electrode conductor are connected together). Any ground-fault currents must flow through this bond on their way from the ground-fault point back to the driving source, the PV module or PV array. (See figure 1). When the current in this bond exceeds 0.5 or 1.0 amp, the circuit breaker trips to the open position. This action interrupts the fault current, even when the fault is many feet away on the roof of the building and provides the indication that a ground fault has occurred. Requirements 1, 2, and 3 are satisfied by these actions.

This small circuit breaker is mechanically linked to one to four large, 100-amp circuit breakers and they open when the 0.5 amp circuit breaker opens. These added breakers are connected in series with each of the incoming ungrounded conductors from the PV array and when they open, the PV array is disconnected from the rest of the system, thereby meeting requirement 4.

Requirement 5 was added to reduce the PV array voltage to zero by shorting the positive and negative conductors together to minimize a potential shock hazard. In the original GFPD design, this was accomplished either by using a motor-driven circuit breaker on 48-volt systems or by using a solenoid-driven (closed) shunt-trip breaker on the higher voltage systems. This fifth shorting requirement was later removed from the NEC when it was determined that it might be possible to damage a "new technology” PV module by short-circuiting it. The module was never produced, but the crowbar requirement was not reintroduced even though the PV wiring can handle the worst case short-circuit currents and is oversized by a factor of 125 percent. It is an impressive demonstration when circuit breakers rated at 750 volts close and short circuit a 100-amp PV array that has an open-circuit voltage of 600 volts.

Modern Ground Fault Protection Devices

As the higher-voltage, utility-interactive PV inverters became available in the late 1990s, it was more cost-effective to use a 0.5 or 1.0 amp fuse as the sensing element and use the control electronics in the inverter to monitor the fuse, indicate that a ground fault had occurred (light or display), and shut down the inverter (effectively disconnecting the equipment). (See photo 4).

Coming in 2008

NEC-2008 will require GFPDs on nearly all PV systems including those mounted on commercial buildings (non-dwellings) and on the ground. This requirement was added to theNECbecause on the larger PV arrays, a ground fault, if not interrupted, can continue as long as the sun is shining, and may not be detected until significant damage has been done. The possible arc from the ground fault and the overloaded equipment grounding conductors may each pose hazards.

Sizing equipment grounding conductors usingNEC250.122 for PV systems with fuses does not always result in a conductor size that can withstand continuous ground-fault currents. The conductor and overcurrent sizing requirements for PV source and output circuits and the current-limited nature of PV module outputs cannot ensure that overcurrent devices will open properly in a very short time as they do on ac circuits. Therefore, a requirement was added to interrupt the ground-fault currents on all PV systems when they exceed the low 0.5 or 1.0 amp value.

Before May 2007, inverters larger than about 10 kW had only partial GFPD functionality. They detected the ground faults, indicated that the fault had occurred, and shut down. However, they did not interrupt the fault currents. Now, with a change in UL Standard 1741 for PV inverters and the 2008 NEC, all utility-interactive inverters will have full functionality with respect to ground faults and will act in a manner similar to the smaller residential units. Off grid, PV systems with batteries operating at 48 volts nominal, or less, will have the GFPD built into the charge controller, or an external device will have to be added. Small, dc off-grid systems that have no dc or ac wiring inside or on a building will be exempt from the GFPD requirement if the equipment grounding conductors are oversized by a factor of about two.

The AC Ground-Fault Issue

Photo 4. Ground-fault fuse on high-voltage inverter

Arc-Fault Circuit Interrupters

Arc-fault circuit interrupters (AFCI) are, in some ways, similar to GFCIs and should not be backfed by PV inverters unless listed and identified for backfeeding. They are being required in many locations thereby increasing the safety of electrical systems here in the U. S. DC arc-fault circuit interrupters are not currently available.

However, we know that there is some danger associated with a line-to-line fault in the dc wiring of a PV array. The PV industry and Underwriters Laboratories are studying the issue to determine the signature of a typical dc arc originating from a PV system and how, if possible, to detect, control, and extinguish that arc. This is not an easy task because the electrical sources (the PV modules) in any system are widely dispersed and numerous.

Summary

The number of PV installations is increasing at more than 20% a year. Nearly all PV systems will soon be required to have a ground-fault protective device that will minimize the possibility of fires starting from ground faults in PV arrays. Efforts are continuing to enhance the safety of PV systems for the general public through revisions and additions to the National Electrical Code and UL Standards. The goal is to have safe, reliable, and cost-effective PV systems. The green future must be a safe future.

For Additional Information

If this article has raised questions, do not hesitate to contact the author by phone or e-mail. E-mail: jwiles@nmsu.edu Phone: 575-646-6105

A color copy of the latest version (1.7a) of the 150-page, Photovoltaic Power Systems and the 2005 National Electrical Code: Suggested Practices, published by Sandia National Laboratories and written by the author, may be downloaded from this website: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/PVnecSugPract.html

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. Copies of "Code Corner” written by the author and published in Home Power Magazine over the last 10 years are also available on this web site: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html

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. A schedule of future presentations can be found on the IEE/SWTDI web site.

Read more by John Wiles

Photovoltaic power systems are a rapidly growing (30+ percent/year) segment of the residential and commercial electrical systems market. These systems operate up to 600 volts and, in the larger commercial systems, the dc and ac currents can range up to 1000 amps. These levels of voltage and current, if not properly managed, pose both shock and fire hazards. The electrical inspection is a key element to minimizing these potential hazards.

Previous articles in this "Perspectives on PV” series have covered the details of the Code requirements for these systems, and copies of those articles are available onwww.iaei.organd on the author’s web site—link is below. In a perfect world, all of those requirements have been fully met or exceeded, and the installation has been executed with exceptional workmanship.

Quality Systems Are Coming

Eventually, we may approach this ideal level of quality in PV installations. That could happen in a few years when the well-seasoned PV systems integrators, installers (hopefully also trained electricians), and electrical inspectors have worked together on hundreds of the same type of systems and installations. Those old-timers in the PV industry will be working with well-established products. They will have worked closely with the plan reviewers, permitting officials, and inspectors to submit a well-documented electrical design package that includes a clear, three-line diagram, the calculations used to determine ampacity, conductor types and conduit fill, and a copy of the equipment specifications and manuals. Inspections of PV systems will be as quick and routine as for any residential or commercial electrical system.

But Not All Systems Are Code-Compliant and Durable

Unfortunately, we are still a long way from that ideal scenario. While there are a few PV systems integrators (the larger companies) and other PV installers who have done dozens and possibly hundreds of PV installations, they are not common. PV installers, normally with little electrical installation experience, abound. They are familiar with neither Article 690 in the NEC covering PV systems nor the first four chapters of the Code that deal with the basics. On the other side of the installation/inspection equation, inspectors and plan reviewers have had little experience with the unique nature of PV systems and have not worked extensively with these new PV companies. New equipment (inverters and PV modules) is being introduced continually, and all involved with PV systems are hard-pressed to keep up with the ever-changing installation requirements due to the unique nature of each piece of equipment. Unfortunately, even a PV installer who has obtained the NABCEP (North American Board of Certified Energy Practitioners,www.nabcep.org) certificate by passing a 60-question written examination may not have extensive experience installing conventional residential or commercial electrical systems.

Safety First for the Inspector

Photos 1 and 1A. Required placards may indicate attention to details

There are many items that should be inspected on a PV system. See the "Perspectives on PV” articles in the IAEI News for March/April and May/June 2006 for a more complete list. We need to keep in mind that these systems are unique in that they will be producing significant amounts of energy for the next 40–50 years whenever they are exposed to sunlight. The inspector should evaluate the overall workmanship with this timeframe in mind.

Photo 2. Are they properly grounded?

Will the System Be Safe 10 Years from Now?

Will those exposed cables on the roof be secure and not allowed to move around in the wind or when ice slides under the PV array? Are the conductors the right type for the exposed conditions? If squirrels are scampering around the roof and near the PV conductors, possible insulation damage may be expected (see photo 4). No, we don’t have a solution for this problem, nor do we know how prevalent it is. Are the conduits securely fastened to the building? Do the conductor sizes and ampacities reflect appropriate temperature deratings for conductors in conduits in sunlight per 310.15(B)(2) inNEC-2008?

Photo 3. Must have been done by a "Grounding Guru"; violation of 250.53(G)

Are the covers on enclosures like junction boxes and combiners firmly attached with screws so that a tool is needed to open them? (see photo 5).

Inspectors in some areas are reporting that conductors can frequently be pulled loose from terminals because they have not been properly tightened. A few "pull tests” on unenergized conductors will reveal whether or not the installer used a torque screwdriver (see photo 6). Many installers (and electricians) don’t have torque screwdrivers, even though every electrical terminal has a torque specification and that torque specification should be followed for a durable electrical connection.

Photo 4. Rodent damaged cable and connector

If the system is ground-mounted or readily accessible (Code definition) from a readily accessible flat roof, have those exposed single-conductor cables been treated properly and made not readily accessible with a barrier? If not, the NEC-2008 will require that they be installed in a raceway, and that will be hard to accomplish since few modules have provisions for using conduit. At 600 volts, the general feeling is that the unqualified person should not have ready access to these conductors and the currently used, pull-apart connectors. Connectors for these exposed conductors will be locking and require some sort of tool to open starting sometime in 2008. The most likely solution in these readily accessible systems will be to put some sort of barrier behind them, possibly just a wire mesh or screen that would prevent ready accessibility.

Photo 5. How long has that cover been off?

After looking at the workmanship issue and the long-term durability of the system, the inspector can then concentrate on ensuring that the electrical components have been connected properly. For some reason, NEC 690.64 seems to be frequently abused. This may be because it is somewhat complex and the requirements hard to meet with the larger PV systems on residential services. See the "Perspectives on PV” in the September/October 2005 and January/February 2006 IAEI News for the full story.

Photo 6. Torque screwdrivers are needed for electrical connections

If the electrical transmission and distribution system suffers any long duration blackouts, then there may be an increase in the number of PV systems that, in addition to being connected to the utility grid, will also have batteries for energy storage. These systems require special inverters that can disconnect from the utility grid during the outage and supply part of or the entire house loads with power from the PV modules and/or the batteries. These more complex systems will require additional time for the inspections.

Summary

PV systems are like other electrical power systems. When they are installed incorrectly and not in compliance with the requirements of theNECand local codes, they can pose hazards, not only to the owners/users of the systems but also to inspectors. Inspections are definitely required. Teamwork between the designers, installers, and inspectors of these systems is a necessity. Teamwork coupled with increased familiarity with the equipment and the Code requirements based on experience will yield safe, durable, and reliable systems. Concern for the environment and significant financial incentives are producing significantly more photovoltaic power systems installations. A fast train is just leaving the station. Hop on board. The trip should be interesting

For Additional Information

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

A color copy of the latest version (1.6) of the 150-page, Photovoltaic Power Systems and the 2005 National Electrical Code: Suggested Practices, published by Sandia National Laboratories and written by the author, may be downloaded from this web site: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/PVnecSugPract.htm

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. Copies of "Code Corner” written by the author and published in Home Power Magazine over the last 10 years are also available on this web site: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html

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. A schedule of future presentations can be found on the SWTDI web site.

Read more by John Wiles

The currents in a PV system are somewhat different from the currents traveling through a typical alternating current (ac) electrical system. Yes, the PV system has ac circuits and they are somewhat like a typical ac load circuit, but the direct current (dc) circuits are a little unusual. This article will address the unique aspects of these dc currents and how the Code handles them.

Current Sources

While PV modules produce volts, amps, and watts, they are considered to be current sources and operate differently than the normal voltage sources commonly experienced in the 120/240-volt ac circuits in our homes or the 12-volt dc circuits in our automobiles.

A voltage source can have very high available short-circuit currents. If it were not for the overcurrent devices in the load centers and main disconnects, the typical utility transformer feeding a residence could deliver short-circuit currents approaching 10,000 amps. The larger transformers feeding commercial buildings with 480-volt ac can deliver even higher short-circuit currents. The typical 12-volt automotive battery can send several thousands of amps into a short circuit.

PV modules as current-limited current sources have a limited capability to produce high currents. A typical 208-W PV module might have an operating current of 7.5 amps and be able to deliver a short-circuit current of only 8.1 amps. The amount of current a single PV module can deliver is limited by the size of the cells in the module, the method of internal wiring, and the brightness of the sunlight falling on it.

Modules are rated in the laboratory at a set of standard test conditions (STC) that include, among other things, a standard sunlight (solar) intensity of 1000 watts per square meter (W/m2). At 1000 W/m2, the module is tested and the values of short-circuit current (Isc), and operating current (Imp) are recorded. Average production values for these two parameters are marked on the back of the module along with other items. On most modules, the short-circuit current at STC will be only about 10–15% higher than the operating current.

When modules are connected in series to form what the PV installer calls a "string” of modules, the operating and short-circuit currents do not change. The string currents are the same as the values for a single module. However, the voltage that each module produces does add up in the string and many typical residential PV systems operate with voltages in the 400- to 600-volt range.

A 480-Volt PV System is NOT like a 480-Volt Feeder

Photo 1. Burned combiner box caused by wiring error

As the PV systems get larger (commercial systems), the operating voltages will usually be limited to no more than 600 volts, except in a few experimental systems operated by utilities on utility property and behind secure utility fences. But, as the system size and power increase, the current will increase above the few tens of amps into hundreds of amps. There are now single, utility-interactive inverters rated at 500 kW ac output and they will have dc operating currents and short-circuit currents at the inverter input approaching 1000 amps (see photo 2). These large PV systems, and the high levels of dc current, while not as large as the

Photo 2. High-current dc fusing

hundreds of thousands of amps associated with 480-volt ac feeders, must be treated with extreme caution when working on such a system when energized (see photo 3).

Fortunately, most residential PV systems rated at power levels of 2500–5000 watts have dc currents in the 5–15 amp range and are proportionately less dangerous from an arcing point of view.

Working Safely on PV Arrays

With a solar energy source, it is somewhat difficult to turn off the current from an illuminated PV module. If the attached leads from each module were available, they could be disconnected (open circuited) or connected together (short-circuited) to reduce either the current or the voltage from the module to zero. However, in most PV systems, these leads and their connectors are not readily accessible, so other means must be used to work on active systems. One method is to cover the modules with an opaque surface, but this is rarely

Photo 3. 250 kW inverters

done on any but the smallest systems. The area of a PV array in a typical residential PV system might be hundreds of square feet as shown in photo 4.

In the typical PV module, the output conductors are terminated in connectors that are insulated and are, to a limited extent, considered "touch safe”— photo 5. These connectors can be plugged together safely, and, in the usual wiring sequence, at least one pair of these connectors is left open until all other wiring is done on the PV array. By leaving one connection open in each string of the array while making terminal connections to disconnects at the end of each string, the possibility of getting shocked is somewhat reduced. However, ground faults and stray leakage currents can always present a shock hazard, so insulated gloves and tools are recommended when making terminal connections.

Photo 4. Residential rooftop PV array

Continuous Currents

From the onset, the PV Industry has been aware of the nature of the PV module as a current source, the limited nature of that current, and its relationship to the intensity of the solar radiation. Article 690 of the National Electrical Code was written to address this unique nature of the PV module and the PV system. Several requirements are in the Code that will allow PV systems to be safely designed and installed in a manner that should provide an essentially hazard-free system for the life of the PV module—a life that may approach 50 years.

For purposes of calculating the ampacity of conductors, the Code requires that the rated dc short-circuit current (not the operating current) from a single PV module or the current from a combiner box that carries the paralleled output of several strings of modules be multiplied by 125 percent [690.8(A)]. This 125 percent factor is applied to address the fact that the solar irradiance on clear days in many parts of the country may exceed the standard test condition value of 1000 W/m2 by a varying amount. Values of 1150 W/m2 (115 percent) are not uncommon for periods that can last three hours or more. This 125 percent factor ensures that on a continuous basis (as defined by the NEC), the currents used in ampacity calculations are the worst possible currents that could be generated by the PV module. Also, by this calculation, we are implying that these currents exist continuously 24 hours per day when, actually, they will never reach the 125 percent level, may only be above 1000 W/m2 for only a few minutes each day, are lower most of the time, and drop to zero at night. Also note that the calculation involves the short-circuit current, not the operating current which is typically 10–15% lower, and that the short-circuit current would normally only flow under a fault condition.

Photo 5. "Touch Safe" module connectors

Then, the normal Code provision (applied to all conductors and most overcurrent devices) is added where they must have a basic ampacity of 125% of the continuous load (already 125% of Isc) [690.8(B)]. Since this is an energy supply system, we use the term source currents rather than load currents, but the same calculations apply. The Code has now required that a 156 percent (125% x 125%) factor be applied to the rated short-circuit current for the module or modules. This ensures that, after appropriate corrections have been made for conditions of use, the conductors carrying the dc currents from PV modules will never be overloaded and will be operated within their ratings for the life of the system.

Conservative Designs Yield Long, Safe Operation

PV modules may be producing hazardous voltages and currents for 40 years or longer. Using the 156% factor on the short-circuit current to size cables and rate overcurrent devices helps to ensure that these devices will safely and reliably carry the normal PV currents for many years. Even in the extreme outdoor environment (hot, wet, and ultraviolet) that provides challenging operating conditions, conservative ratings keep conductors and overcurrent devices well within their operating tolerances.

For Additional Information

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

A color copy of the latest version (1.6) of the 150-page, Photovoltaic Power Systems and the 2005 National Electrical Code: Suggested Practices, published by Sandia National Laboratories and written by the author, may be downloaded from this web site: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/PVnecSugPrac.htm

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. Copies of "Code Corner” written by the author and published in Home Power Magazine over the last 10 years are also available on this web site: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.htm

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. A schedule of future presentations can be found on the SWTDI web site.

Read more by John Wiles

The requirements and necessity for, and the location of disconnects in a photovoltaic (PV) power system are always of great interest. While PV equipment manufacturers, designers, installers, and electrical inspectors are all interested in getting safe PV systems, there are usually some "friendly” discussions on the whys and hows of disconnects needed to achieve those ends. The following information may shed a little light on those sometimes elusive disconnect requirements and how they can be addressed.

Photo 1. Small system dc PV disconnect

Disconnects defined

Article 100 in the NEC defines disconnecting means as a device or devices that could be used to disconnect circuits. Switches, circuit breakers, screw terminals, and bolted connections fall under that definition (see 690.17).

Why are they needed?

PV disconnects are generally required on both small (photo 1) and large (photo 2) systems for two reasons. The first reason is to disconnect the external power source conductors from the circuits in the building or structure (690.13, 230.70). A common disconnect of this type is the ac service-entrance disconnect for a house. On a PV system, the main PV dc disconnect falls into this category if the PV dc conductors penetrate the house. Although batteries are not power generators, they can source energy, so a battery disconnect might also fall into this category.

Photo 2. Large system dc PV disconnects

Secondly, disconnects are required to remove power from a device that needs maintenance. I could use the word "service” instead of "maintenance,” but I am trying to make these articles clearer than the Code. Of course, all of the main-power disconnects could be opened to remove all power from a building, but disconnects associated with equipment that must be maintained provide a degree of safety without shutting down the entire electrical system for maintenance on a single piece of equipment (see 690.15).

Disconnects for PV systems, let me count the ways

A main dc PV disconnect is required where the PV dc circuits from the PV array enter the building (690.13, 690.14).

A main ac PV disconnect is required where the dc PV circuits do not enter the building, but the ac output of the inverter does. No, you won’t find this one explicitly listed in 690, but see figures 1 through 4 (690.13, 690.14).

Figure 1. All components outside the building

A dc inverter maintenance disconnect is required and more than one may be required if the system has batteries (690.15).

A battery disconnect is normally required on stand-alone PV systems with batteries or utility-interactive PV systems with battery backup.

An ac inverter maintenance disconnect is required for utility interactive inverters (690.15).

Stand-alone inverters with generator inputs may also require a generator disconnect at the inverter input (690.15).

Figure 2. Main load center inside building

Charge controller input and output disconnects are required for maintenance on systems with batteries (690.15).

Systems with backup generators will normally require a generator disconnect both outside at the generator location (point of entry power disconnect) and inside near the inverter and other power processing equipment (maintenance disconnect).

The ac point of connection will require a disconnect on utility-interactive systems [690.64(B)(1)].

Many utilities will require a lockable open, visible blade ac disconnect for the PV system, and this disconnect will usually be located near the utility revenue meter.

Where art thou?

Figure 3. Inverter inside the building

Although there are two separate requirements for disconnects, in some cases a single disconnect, properly rated and located, may solve both requirements. In other cases, due to equipment placement and the necessity for grouping the maintenance disconnects, two or more disconnects may be needed in a single circuit (690.15).

With the introduction of PV and Article 690 into the 1984 edition of the NEC, the original intent of the requirements for the PV disconnect was to match them with the existing requirements for the ac service disconnect as established by Article 230. In fact, 690.14 in the 1984 NEC referred the reader directly to Article 230 Part F. Unfortunately, most PV installers did not follow this guidance because they were not electricians familiar with installing ac service-entrance conductors and service disconnects. The PV installers frequently penetrated the roof with energized PV source and output conductors and routed these conductors to the main dc PV disconnect just about anywhere in the structure they pleased. Complaints from electricians and electrical inspectors caused the NFPA (without any help from the PV industry) to rewrite Section 690.14 in the 2002 NEC. In this revised section (which mimics 230 Parts IV, V), the requirement was firmly established to install the PV disconnect in a readily accessible location at the point where the PV conductors first penetrate the structure. This requirement effectively keeps the energized PV conductors outside the structure until reaching that disconnect.

Figure 4. Inverters on the roof

The NEC does not specify whether the main ac service disconnect or the main dc PV disconnect is to be located inside or outside the structure at the point of penetration of these circuits. That is left to the local jurisdiction and the requirement for locating these disconnects varies throughout the country. Figure 1 shows the simplest configuration of a utility-interactive PV system where the local jurisdiction requires all disconnects to be on the outside of the building, the ac load center is mounted on the outside of the building, and the inverter is also mounted on the outside of the building. This meets the K.I.S.S. principle.

An addition to the 2005 NEC [690.31(E)] allows the PV source and output conductors to be routed inside the building (the dotted line in the figures) before they reach the main PV disconnect if they are installed in a metal raceway. Metal raceways include metal conduits and flexible metal conduit. Metallic cable assemblies are not allowed so the installations cannot yet use Type MC and Type AC cable assemblies—maybe in 2008?

In figure 2, the main load center is inside the building and this contains the backfed PV circuit breaker. Where the utility requires an external disconnect (usually lockable open), the utility may also allow this disconnect to be used as the grouped ac maintenance disconnect for the inverter. If the utility disconnect is not required or it cannot be used as a code-required maintenance disconnect, then a separate ac disconnect will have to be mounted in this circuit next to the inverter on the outside of the building.

In figure 3, the local jurisdiction requires that the main ac and dc power disconnects be located outside the building and the main load center containing this disconnect is also outside the building. For architectural reasons, the inverter is located inside the building. To provide for safe maintenance of the inverter, added dc and ac maintenance disconnects are needed inside the building on either side of the inverter.

While lock-out tag-out procedures might be used in an industrial environment to use just the external disconnects to de-energize the inverter safely, these procedures are not easily adapted in the residential or commercial environments.

Where batteries are located in a separate room or at some distance (typically, five feet or more) from the inverter and charge controllers, a disconnect is required at the battery location, and this disconnect is usually merged with an overcurrent protective device.

If a backup generator is used in the system, it is generally located outside the structure. A disconnect will be required at the generator and then again inside the building near the inverter or power distribution panel.

Contrary to the understanding of some inspectors, there is no requirement for a disconnect at the PV array [690.14(C)(5)]. Such a disconnect serves no safety purpose for the user or PV installer since the PV array is always energized when illuminated even if the disconnect were opened.

There are some PV installations, both residential (flat roofs) and commercial, where the inverters are mounted near the PV arrays on the roof in not-readily-accessible locations. NEC 690.14(D) addresses these systems and requires ac and dc disconnects at the inverters and an additional ac PV disconnect at ground level. Figure 4 shows this system where all of the equipment is outside the building.

For a discussion on the use of disconnects inside the inverter, see the "Perspectives on PV” in the September-October 2006 issue of IAEI News.

To disconnect or not to disconnect…

That is not the question. Disconnects are required throughout the PV system with the proper ratings and in the code-required places. As the system complexity increases with batteries, generators, and possibly wind or hydropower inputs, the number of disconnects increases. The basic disconnect requirements were in the Code long before PV systems arrived, and following those requirements as well as the newer requirements for PV systems will make for safe installations.

For additional information

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

A color copy of the latest version of the 150-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: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/PVnecSugPract.html

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. Copies of "Code Corner” written by the author and published in Home Power Magazine over the last 10 years are also available on this web site: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html

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. A schedule of future presentations can be found on the SWTDI web site.

Read more by John Wiles

PV equipment, safety standards, and electrical codes are not developed in a vacuum. How are PV equipment, PV standards, and PV codes related and how are they developed? Yes, there is a little "chicken or egg” in the process since the development of all three is an interactive process.

Equipment Development

Photo 1. Inspiration!

Although the prototype works well in the laboratory (photo 2), the manufacturer must refer to numerous standards (photo 3) as the electronic layout and mechanical packaging are developed for the final product.

The designers and developers will spend many hours reading and applying Underwriters Laboratories (UL) Standard 1741 dealing with PV inverters. This UL standard for safety establishes requirements for the construction and testing of the inverter to ensure that it will pose no overt safety hazards when properly installed and operated.

Photo 2. It Works!

The two primary standards related to PV equipment are UL 1703 for PV modules and UL 1741 for PV inverters and charge controllers. UL 1741 is not an all-inclusive standard, but like most other UL standards, it references numerous other standards that establish requirements for the various components and materials used in the inverter.

UL conducts the safety tests on the inverter outlined by the standard; and if those tests are passed, it lists the inverter as meeting the requirements of the standard. A product that meets the appropriate UL standards, and is installed in an electrical system following the requirements of the National Electrical Code will generally be free from hazards.

Photo 3. What are these?

Canadian Standards Association (CSA) and Intertek SEMKO (ETL) also perform safety tests of PV electrical products using UL standards and certify or list that the products have met the requirements of the standard.

As one of the codes and standards focal points for the PV industry, the author and other engineers at the Southwest Technology Development Institute/Institute for Energy and the Environment assist PV module and inverter manufacturers in understanding the PV requirements of some UL standards and the NEC (photo 4). Because these manufacturers rarely are deeply involved in the trials and tribulations of installing their equipment in tight spaces with limited tools, some of the equipment that is designed has unusual shapes and is not installer friendly. For those cases, SWTDI maintains a "special” training program that shows these equipment designers that large rectangular boxes with large open areas and standard terminals accessible from the front (just like standard load centers) are the preferred design (photo 5).

How Is the Standard Developed?

http://ulstandardsinfonet.ul.com/development.pdf

UL maintains standards technical panels (STP) for the two PV standards (1741 and 1703). These panels are composed of a balanced membership of volunteers invited from the industry (in the 1741 case, the PV equipment manufacturers), users, inspectors, government laboratories, and others. Other nationally recognized testing laboratories like CSA and ETL are also invited to be on the STP. The standards technical panel meets periodically to review the standard, to review technological advances that will impact the products, and to review feedback and comments from users, inspectors, and the public concerning products that have been listed under the standard. The STP drafts necessary changes to the standard. After a formatting and editing review, UL circulates these proposed changes to a wider audience including inverter manufacturers, users, regulatory agencies, and others for comment. After an extensive review and coordination process, the standard is revised and finally published. The changes usually have a phase-in date that gives the manufacturers time to revise any existing products. The balanced membership on the STP and the wide dissemination of the proposed changes ensures that the standard reflects the needs and desires of all stakeholders consistent with the basic nature of a safety standard. The author is a member of both the UL 1703 and UL 1741 Standards Technical Panels.

The Code?

Photo 5. Special training session

Photo 6. Good equipment, the result of a complex process

NFPA Code-Making Panel 13 that also has a balanced membership evaluates proposals submitted for Code changes relating to PV systems found in Article 690. In addition to Article 690, CMP-13 deals with nine other articles in the Code and is very busy during the several code meetings. There are 16 members on CMP-13 plus an equal number of alternates, who also sometimes attend and participate. They represent the following: IAEI, Solar Energy Industries Association (SEIA)—Ward Bower from Sandia National Laboratories is the representative, Alliance for Telecommunications Industry Solutions, Institute of Electrical and Electronics Engineers, Associated Builders and Contractors, Independent Electrical Contractors, Inc., Electric Light and Power Group, UL, US Fuel Cell Council, National Electrical Manufacturers Association, Intertek Testing Services (ETL), IBEW, American Society of Agricultural Engineers, and Electrical Generating Systems Association.

Photo 7. Safe, reliable, durable

CMP-13, like all other CMPs, meets shortly after the proposals have been received by NFPA. Each proposal is carefully reviewed and a Report on Proposals is issued by NFPA showing the panel actions on each proposal. The panel may elect to accept the proposal as submitted, accept-in-principle-with-changes, or reject it. The Report on Proposals is available to the general public for comment. After those comments have been submitted, CMP-13 again meets to review and act on the comments. NFPA also has a Technical Correlating Committee that oversees the entire process and coordinates between various CMPs to ensure a degree of continuity throughout the Code.

PV Industry Forum

The PV Industry Forum is a group of more that 100 individuals in and out of the PV industry that develop, review, coordinate, and substantiate proposals for the NEC that involve PV systems. In addition to members of the PV industry, the Forum includes IBEW members, electrical inspectors, utilities, and even people at NFPA headquarters. For the most part, proposals deal with Article 690, but since other areas in the Code affect PV systems, proposals for other articles are sometimes submitted. For example, a proposal was submitted to revise the wording in Section 250.166 (Size of DC Grounding Electrode Conductors) for NEC-2008.

Ward Bower from Sandia National Laboratories is the chair of the PV Industry Forum and the author is the secretary of the Forum. John makes presentations around the country on a regular basis and talks with inspectors, electricians, and PV designer installers every day. He collects suggestions for Code clarifications and changes throughout the year. Early in the year that new proposals are to be submitted to NFPA, he uses the NFPA Style Manual to convert these code suggestions into draft proposals with technical substantiation. Ward Bower circulates these draft proposals throughout the PV Industry Forum and the feedback results in a finely tuned set of proposals and even some new ideas that are coordinated even further. In November, John submits the reviewed and coordinated proposals to NFPA. As the code-making panel actions become known, John and Ward distribute this information to the PV Industry Forum and solicit feedback. The comments are folded back into the process to help the PV Industry get a clear, concise set of PV requirements in Article 690 of the next edition of the National Electrical Code.

An Interactive Process

Equipment concepts lead to product development based on standards. The codes provide guidance on how the equipment is to be installed. PV equipment designers, PV installers, electrical inspectors, PV users, and others provide feedback to the codes and standards developers and the process continues without end. Through the hard work of thousands, the result is safer, reliable, and more durable PV systems being installed in ever-increasing numbers (photo 6 and 7).

For Additional Information

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

A color copy of the 150-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: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/PVnec-SugPract.htm

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. Copies of "Code Corner” written by the author and published in Home Power Magazine over the last 10 years are also available on this web site: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.htm

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. A schedule of future presentations can be found on the SWTDI web site.

Read more by John Wiles

Electrical inspectors and other inspectors are curious people and when faced with reviewing plans for a PV system or inspecting such a system, there are many new features that are worth questioning. Here are some of the questions that inspectors have raised via e-mail, telephone calls, and during my PV/NEC presentations over the last four months.

Question: When are fuses required in the dc wiring of a PV system?

Answer: Fuses are generally required in the dc sections of a utility-interactive PV system for two reasons. First, all ungrounded conductors must be protected from over currents. Second, each PV module must be protected from reverse currents that exceed the value of the module protective fuse that is marked on the back of the module (fuses and circuit breakers are considered equivalent) [see photo 1]. Overcurrents may result from a short circuit in the wiring, and reverse currents may result from either a short circuit or a shaded module or modules. In most cases, a single overcurrent device will satisfy both of these requirements and, in many small residential PV systems, no overcurrent device at all is required.

These overcurrent devices are required only when there are sources of over currents that could damage either the wiring or the module during shading or fault conditions. In the utility-interactive PV system, with a listed inverter, the only source of currents or over currents in the dc part of the system originate in the modules themselves. The inverter is not able to provide any current into the dc PV array, so it is not a source of currents other than a short transient current as the input noise filtering capacitors discharge.

Photo 1. Label on back of PV module

In a single string of PV modules (a series connection of several modules from 2-20+), the only current in question is the current generated by the modules in the string. This current is, at a worst-case maximum, 125 percent of the rated module short-circuit current (Isc). This current is marked on the back of the module as shown in photo 1. Per NEC requirements (690.8 and 690.9), all circuit conductors will be sized at 156 percent of the same short-circuit current. Therefore, the conductors have no source of high overcurrents that would exceed their ampacity and they do not need overcurrent protection (690.9, Exception). Currents generated within a string of modules cannot produce reverse currents in that string and, since there are no external sources of currents, no overcurrent device is needed to protect the PV module. The result is that in a utility-interactive PV system with a single string of modules, no overcurrent device is needed in the dc circuit.

Photo 2. DC combiner box with circuit breakers operating up to 125 volts

When there are two strings of modules, it is possible for one string to attempt to force currents back into the other string when that string is shaded. The unshaded string can produce up to 125 percent of the rated short-circuit current. All wiring in each string is sized at 156 percent of that same current so no overcurrent devices are required to protect the module wiring. Most PV modules have a marked, module-protective fuse that is well in excess of 156 percent of the rated short-circuit current, so again, there is no requirement for an overcurrent device to protect the modules. With two strings of modules connected in parallel, no overcurrent device is needed in the dc wiring.

When three or more strings of modules are connected in parallel, the situation may be different and a calculation must be made. If we assume that one string of modules is shaded, then the two unshaded strings of modules may attempt to force reverse current into the shaded string. Each of the unshaded strings can source up to 125 percent of the rated short-circuit current, so two strings can source up to 2 x 1.25 x Isc = 2.50 Isc. If this current (2.50 Isc) is greater than the value of the maximum module protective fuse marked on the module, then an overcurrent device must be installed in the ungrounded conductor of each string, and the value will be typically be 1.56 Isc or larger, up to the value of the maximum protective fuse. A minimum value of 1.56 Isc will protect the module from reverse currents and will also protect the conductors that have also been sized at 1.56 Isc. If a larger value of series overcurrent protective device is used (up to the allowed maximum protective fuse value), the ampacity of the conductors connecting the modules must be adjusted accordingly.

Photo 3. DC combiner boxes with fuses operating up to 600 volts.

When there are more than three strings, the same calculation applies. Just take the number of strings in parallel and subtract one. Use this number times 1.25 x Isc to get a number that will be compared to the value of the module protective fuse. If the calculated number is larger than the protective fuse value, then one overcurrent device will be required on each of the series-connected strings of modules. The overcurrent devices are usually mounted in a dc combiner box as shown in photos 2 and 3.

In summary, one and two strings of modules on a utility-interactive inverter will require no overcurrent devices in the dc circuits. When three or more strings are used, a calculation must be completed to determine if overcurrent devices are required or not.

There are a few modules currently on the market that have a series fuse rating that is less than 1.56 Isc. This creates a quandary for the installer and the inspector. NEC 110.3(B) requires that the module label be followed, but 690.8 and 690.9 require that an overcurrent device rated at 1.56 Isc be used. When these cases come up, it is time to call UL or enter a complaint through their AHJ/regulatory web site and get this continuing issue resolved.

Question: On PV systems with batteries, how is the ampacity of the conductor for the charge controller output circuit determined?

Answer: The ampacity of the charge controller output circuit must be based on the rated maximum output of the charge controller. This information should be in technical specifications or the instruction manual for the controller. The circuit ampacity and the rating of any overcurrent device must be at least 125 percent of the rated steady-state output currents. In some cases, the rated output current is not stated.

Photo 4. Battery charge controller

Some controllers use a relay as the switching/controlling element. In this case, the rating of the relay becomes the rating for the controller.

In other cases, the charge controller does a voltage conversion and can take higher input voltages (such as 48-72 volts from the modules) and charge batteries at lower voltages such as a 24-volt or even a 12-volt battery. While the manuals for these charge controllers usually specify a rated output current, the installer (and the inspector) should verify that the PV system is not designed so that excessive currents are forced through the controller. If this happens, NEC 110.3(B) may be violated by using the listed controller in a manner that is not covered by the instructions. For example, a controller may be rated at 60 amps output when connected to a 24-volt battery. If this controller is connected to a 48-volt, 60-amp PV array, the controller will reduce the output voltage to 24 volts and, at the same time, try to increase the output current to almost 120 amps. While the controller will presumably protect the output circuit by limiting the output to 60 amps, the controller is not being used in accordance with the manufacturer’s instructions [110.3(B)]. Most of these controllers list the maximum PV input power levels or maximum currents at various voltage levels for each battery output voltage.

Question: What safety precautions should I observe when inspecting a PV system?

Photo 5. High voltage, high currents - exercise caution!

Answer:

Keep in mind that the PV dc circuits between the PV modules and the dc disconnect will be energized any time the modules have light on them (even at dawn and dusk). Connections, switchgear, and other devices can be at voltages up to 600 volts. On any system showing signs of poor workmanship at a distance (inspectors know poor workmanship when they see it), the proper grounding of all metal surfaces should be inspected first. After that, it should be safe to open boxes and switchgear and inspect further. For additional details, see the "Perspective on PV” in the May/June 2006 edition of IAEI News (PDF available on the author’s web site).

Question: What types of information should I be requesting on plans for PV systems being used to obtain a permit?

Answer: Since none of us have seen, installed, or inspected hundreds of PV systems and each one is different, we really need to get as many details as possible in the permitting package. It is far easier to verify Code compliance on paper in the comfort of the office and then check to see if it was installed per the permit. We need the following items in the permit package: 1) an overall description of the system and how it works, 2) specifications for each of the major components and manuals for the modules, inverters, and any charge controllers, 3) a two- or three-line diagram showing the equipment-grounding provisions and system-grounding provisions, 4) calculations showing Code compliance for conductor ampacity and conditions of use deratings. See "Perspectives on PV” in the March-April 2006 edition of IAEI News (PDF available on the author’s web site) for more details.

Question: What are the requirements for grounding a PV system that is installed on a metal roof.

Answer: The National Electrical Code (NEC) requires that any exposed non-current-carrying conductive surface that may be energized be grounded to minimize electrical shock hazards (Section 250.110).

Rooftop PV systems may operate at voltages approaching 600 volts. These voltages pose a significant shock hazard if they are allowed to energize conductive exposed surfaces that may be touched. Such exposed non-current-carrying conductive surfaces include the PV module frames, the metallic module mounting racks, and possibly the metal roof the racks are attached to. Effectively bonding these conductive surfaces together and grounding them will minimize shock hazards.

There are two primary wiring methods used for connecting PV modules together; single-conductor exposed cables and conduit. Each will dictate a different grounding method. In both situations, the PV module frames must always be grounded properly. See the "Perspectives on PV” article in the September-October 2004 issue of the IAEI News titled "PV System—Should They Be Grounded” for information on grounding PV modules. This article is also available on the author’s web site

PV systems using exposed, single-conductor cables

Photo 6. Grounding a metal roof, THHN questionable

In many cases, it would be difficult to keep these exposed cables from touching the metal roof. They could touch at initial installation, or they may come into contact with the roof at a later date as cable ties break or loosen. Wind, rain, and ice could cause the cable to rub against the metal roof, abrade the insulation, and allow the energized copper conductor to energize the roof.

Where these exposed single conductor cables are used for modules, the racks and the roof should be grounded. Instructions on how to properly ground a metal roof are not readily available, but photo 6 shows a possible method that might be used provided the non-UV rated THHN conductor were not used. A bare grounding conductor would be a better, code-compliant choice. Such connections should be made where water penetration would not be an issue.

PV systems using conduit between modules

When conduit is used between the individual modules (currently a rare situation) and there are no exposed, single-conductor cables, then it is unlikely that either the module racks or the roof would require grounding. The module frames should be grounded, and conduit should surround the conductors, protecting them from damage. The conduit may be insulating types like rigid nonmetallic conduit (RNC) and liquidtight flexible nonmetallic conduit (LFNC) or a metal type like electrical metallic tubing (EMT). The EMT would be grounded, the LFNC, RNC would not be grounded, and both would provide the desired physical protection. Even if the conductor insulation should fail, the conduit would prevent the rack or the roof from becoming energized. Neither the metal racks nor the metal roof would require grounding except in the event that significant and likely PV module damage could be expected. Such damage could cause the internal conductors of a shattered PV module to contact the rack or the roof. If such damage were expected, then grounding both the rack and the roof would be advised.

For Additional Information

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

A color 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: (http://www.nmsu.edu/~tdi/roswell-8opt.pdf.) The Southwest Technology Development Institute web site (http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html) maintains a PV Systems Inspector/Installer Checklist and all copies of the previous "Perspectives on PV” articles for easy downloading. Copies of "Code Corner ” written by the author and published in Home Power Magazine over the last 10 years 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. A schedule of future presentations can be found on the SWTDI web site.

Read more by John Wiles

When inspectors see a photovoltaic (PV) power system for the first time, they will usually be faced with a type of wiring method not normally seen in residential or commercial electrical systems. That wiring method is the use of single-conductor exposed cables to connect the individual PV modules together in the PV array and is permitted by NEC 690.31. Exposed, single-conductor wiring is usually seen only in older neighborhoods as aerial feeders between buildings and in obsolete (but still with us) knob-and-tube wiring systems.

Photo 1. Modern PV module with leads and connectors

A Little History

Photo 2. Early (1980s) PV module with exposed, widely spaced terminals

Historically, this exposed wiring method was allowed into the Code in 1984 because PV modules at that time had single, widely spaced output terminals diagonally opposed at opposite corners on the back of the modules [see photo 2/inset 2].

Inset 2. Exposed terminal minus the insulating cover

It was deemed too difficult (and wasteful) to use one of the conventional wiring methods to make connections to these single terminals when many of the connections were routed to another single terminal on an adjacent module only a few inches away. Subsequent to the early days, where exposed terminals and insulating caps were used, junction boxes were added at each end of the module, one for the positive and one for the negative contact [see photo 3/inset 3].

In the 1990s, both positive and negative contacts were placed in a conduit-ready junction box at one end of the modules [see photo 4/inset 4].

These types of modules with conduit-ready junction boxes are still available on special order from a few manufacturers for use where local codes require the use of conduit, particularly in commercial installations.

Workmanship Is Important

Conductor Types

The conductors permanently attached to the PV module are part of the listed module assembly and, presumably, Underwriters Laboratories (UL) has verified that the cables meet the necessary safety requirements. In most cases, the cables will be marked USE-2 or USE-2/RHW-2, and some also will be marked "Sunlight Resistant” indicating better ultra-violet capability than the basic USE-2, which is tested for UV resistance but not marked as such.

Photo 4. Special order PV module with conduit-ready junction box

PV modules are connected in series (called strings) and, after making anywhere from 4 to 24 series connections, the positive and negative conductors at the ends of the string are some distance apart. In order to bring these two points to a common location, single conductor wiring is again used. Although USE, SE, and UF cables are allowed by Section 690.31, the installer typically uses a USE-2 or USE-2/RHW-2 cable to get both the negative and positive negative conductors to a common junction point in the PV array. At this point, the exposed conductors are transitioned, using a junction box to one of the common wiring methods found in chapter 3. Don’t be misled by extraneous markings like MSHA and DLO as shown on the cable in the lead-in picture. This sunlight-resistant RHW-2 cable is not allowed by Section 690.31 for exposed, field-installed, PV module interconnections.

Inset 4. Junction box, both polarities

Since the environment is hot and wet on exposed roofs, usually THHN/THWN-2 or RHW-2 conductors are installed in conduit. EMT is commonly used and, where allowed by local codes, RNC may be used. In some cases, LNFC has been used and when properly attached to the supporting structure may be acceptable. A discussion of the routing of this output circuit may be found in the "Perspectives on PV” in the May/June 2007 IAEI News.

In NEC-2008, cable types USE, UF, and SE are being removed from Section 690.31 due to temperature limitations and availability in the needed sizes (10, 12, and 14 AWG) for the module interconnections.

A new PV conductor will appear in NEC-2008 in Section 690.31. It is mentioned in the comment for Section 690.35 in the 2005 NEC Handbook. This is a single-conductor cable designated "PV Wire,” "Photovoltaic Wire,” "PV Cable,” or "Photovoltaic Cable.” This cable will have an insulation that is thicker than the insulation on USE-2 (conduit fill will have to be calculated), it will be marked "Sunlight Resistant,” and it will have the necessary flame retardant and smoke properties that will allow it to be used inside buildings in conduit. This cable will be one of the wiring methods required when the PV array is operated in an ungrounded manner in PV systems that use the new transformerless inverters. See Section 690.35 for the current requirements for such systems.

A Typical System

Conductor Ampacity

The module short-circuit currents may range from 1 amp to about 17 amps (in unusual cases). The larger 300+ watt PV modules have short-circuit currents approaching 12 amps. The ampacity of the attached and any field-installed cables should be 1.56 times the module short-circuit current (Isc) after the conditions of use are applied. In most cases, the factory-attached cables have sufficient ampacity. However, in very hot climates, the ampacity calculations should be checked. The ampacity of these conductors in free air should be evaluated using Table 310.17.

Equipment Grounding Conductors

Equipment grounding conductors connected to the PV module frames should be sized at 1.25 times the module short-circuit current (Isc). On large PV arrays, where fuses are used to protect these conductors, Table 250.122 can be used. This will result in a smaller, but adequate, equipment-grounding conductor than will be calculated using the 1.25 Isc value.

INSPECTION AREAS REQUIRING ADDITIONAL ATTENTION

Inspectors have seen the following problems in non-code-compliant installations.

Common Sense and Durability
The exposed, single-conductor cables should only be used for module interconnections. They should not be run across the roof away from the PV array, but should be transitioned at or under the PV array to another wiring method found in chapter 3 that is appropriate for the conditions of use.

Cables Like It Hot
The modules may operate up to 80°C and wiring touching or near the backs of these hot modules should have 90°C-rated insulation. The outdoor environment is a wet environment so "-2” conductors should be used that have a 90°C, wet–rated insulation both in and out of conduit.

Conduits in sunlight on roofs are going to be hot. See fine print note 2 for Section 310.10 in NEC-2005, and also see proposals in this area for the 2008NEC. An added 17°C to the average high temperature will be the minimum addition to the ambient temperature inNEC-2008. In areas where average high ambient temperatures of 40°C (104°F) are experienced, then conduits are going to be operating at least at 57°C. Appropriate temperature deratings may dictate the use of larger conductors than have been used previously to accommodate the reduced ampacity at the higher temperatures.

Grounding—Critical
Module grounding deserves at least a book by itself. With PV modules serving as power sources that will be generating hazardous voltages for the next 40–50 years, individual module grounding is a critical issue. This is particularly important since the module frames are difficult-to-ground aluminum and should remain solidly grounded for the life of the module. A ground fault in a module could energize an ungrounded frame at dangerous voltages if the module were still connected to the rest of the PV array while the module is being removed or otherwise serviced. The old, old Code requirement of connecting the ground first and disconnecting it last must certainly apply to PV modules.

Module Protective Fuse
The backs of all listed PV modules are marked with a value of a "Maximum Series Fuse” or similar wording. The overcurrent device, where required and used, protects the internal module conductors from damage from overcurrents that could be forced through the module from external sources. While many residential PV systems do not require overcurrent protection in the dc circuits, the larger commercial systems usually do require dc overcurrent protection. This will be the subject of another "Perspectives on PV.” The Code requires that any overcurrent device installed in the output of a module be rated for 1.56 Isc. There are a few modules being made (for unknown reasons) that have a maximum series fuse value of less than 1.56 Isc. This poses a Code quandary. Section 690.8 says use a fuse rated at 1.56 Isc, but Section 110.3 says to follow the product labels. Any inspector seeing such a module should report the problem to UL through the AHJ channel on the UL web site.

Summary

PV module wiring can indeed pose questions. However, the basic requirements can be found in Article 690 and as soon as those curious currents travel away from the PV array, they are contained in wiring systems familiar to all inspectors. Don’t forget, it is a hot and wet environment.

For Additional Information

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

A color copy of the latest version (1.6) of the 150-page, Photovoltaic Power Systems and the 2005 National Electrical Code: Suggested Practices, published by Sandia National Laboratories and written by the author, may be downloaded from this web site: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/PVnecSugPract.html

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. Copies of "Code Corner” written by the author and published in Home Power Magazine over the last 10 years are also available on this web site: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html

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. A schedule of future presentations can be found on the SWTDI web site.

Read more by John Wiles

With electrical systems lifetimes exceeding forty years, PV systems must be installed using the best available workmanship to ensure public safety over the life of the system. Article 110, Requirements for Electrical Installations, and particularly Section 110.12, Mechanical Execution of Work, of theNational Electrical Code(NEC) establish some general requirements for the installation of electrical equipment. A fine print note (FPN) to Section 110.12 references the National Electrical Contractors Association standard ANSI/NECA 1-2000 (latest edition is 2006) as describing accepted industry practices for electrical installations. This article will illustrate some areas that need attention when the workmanship of PV installations is being inspected. Of course, the local authority having jurisdiction (AHJ) determines what is acceptable.

Photo 1

Modules

PV modules must be securely mounted to a supporting structure. Mounting holes are provided in the frames of PV modules, and the modules have been tested under simulated high wind loadings using only these holes to ensure that the module can withstand normal and expected environmental conditions. These holes must be used to secure the module to a mounting rack, which is secured, in turn, to the roof of a building or to the ground. The hardware used must be of the appropriate size and be resistant to the exposed outdoor conditions. Stainless steel hardware is most commonly used (see photo 1).

Photo 2. Module rack mounting bracket

The devices used to attach the PV array to the building must be robust and connect the mounting rack to the structural elements of the roof, such as the trusses or rafters. Attachment to only the roof sheathing generally does not provide adequate strength. All penetrations must be sealed against the environment. Photo 2 shows a PV array mounting bracket attached to a 2 x 6 under the shingles and sheathing with sealing to keep out the light rains found in New Mexico.

A few PV modules do not have frames but may have other mounting systems. Some have mounting attachment points bonded to the rear of the fameless modules (called laminates), and others are intended to be installed in a glazing system as part of a building integrated curtain wall or overhead transparent walkway covering. In all cases, the instructions furnished with the modules will show the mounting requirements. It should be noted that some PV modules without frames are not fully listed to UL Standard 1703. Modules in this category are marked with the UR (UL recognized component) mark and should be subject to a field inspection conducted by a nationally recognized testing laboratory (NRTL) that has field evaluation services (see photo 3).

Photo 3. Frameless PV modules in overhead canopy

Many PV modules now have exposed, single-conductor cables (one positive and one negative) attached to the backs of the modules. While these exposed conductors are allowed by Section 690.31, they are only to be used to make connections between the individual modules and should be terminated under or very near the PV array. At that point, the array output wiring should transition to one of the more common NEC Chapter 3 wiring methods, such as conductors in electrical metallic tubing (EMT). In general, these exposed single-conductor cables, with attached connectors, will be longer than necessary when the modules are mounted side by side (see photo 4). The excess length must be controlled by gathering and fastening the excess cable and the connectors to the module racks. It should not be allowed to droop down and be exposed to abrasion damage due to wind and ice.

Photo 4. Typical PV module with long interconnecting cables

The fastening means should be robust; however, some plastic cable ties (especially the white nylon variety) do not resist the heat and ultra violet exposure well. Stainless steel pipe clamps in various sizes with EDPM rubber inserts appear to withstand various environments quite well, but other options are available.

Some installers will cut off the connectors and excess cable lengths and then solder the two cables together minimizing the excess length. The soldered splice is insulated with outdoor rated heat shrink tubing with an internal sealant that yields a splice that has the same electrical, mechanical, and insulation properties as the unspliced conductor. While this meets the Code requirements and results in a neat, durable, workman-like installation as shown in photo 5, a few module manufacturers maintain that splicing may violate the listing and/or the warranty on the module. If the heat shrink tubing does not have the same or greater thickness as the conductor insulation or the heat shrink is not rated for UV exposure, then the splice must be enclosed.

Photo 5. Shortened, spliced, and secured module interconnections

Bare, equipment grounding conductors should also be afforded the same mechanical protection as the exposed, single-conductor, insulated circuit conductors. When these bare conductors are spliced, the proper device must be used—usually a copper split bolt. Photo 6 shows a crimp-on splicing connector that has been evaluated only for indoor applications (usually in a junction box) being used improperly outdoors.

Exposed Conduit Runs

Photo 6. Dry location splicing device used improperly outdoors

Equipment Mounting

Photo 7. Flooded, lead-acid batteries in containers

While the NEC (404.8) requires that the center of the grip on the disconnect handles be no higher than 6’ 7” in the upper position, there appears to be no minimum height requirement. Common sense dictates that equipment, including PV inverters, not be mounted so low that water or splashing rain or mud can get into it. Some PV inverters have minimum space requirements at the bottom for ventilation. Access panels and fittings must be accessible.

The distance between disconnects associated with the term grouping is left to the AHJ. Since inverters must have ac and dc disconnects to allow for safe service and removal, it would seem appropriate that these disconnects be located adjacent to the inverter. While some inverters have internal disconnects, the AHJ must determine whether or not the inverter can be safely removed for service using these internal disconnects or whether external disconnects must also be required. If the inverter is mounted on the other side of a wall from the main PV dc disconnect or not near the back fed breaker in the main ac load center, then additional "servicing” disconnects will generally be required adjacent to the inverter.

Photo 8. VRLA batteries with terminals covered

When all of the PV-related equipment is mounted outside (or inside) the building, including the PV dc disconnect, the inverter, any utility-required disconnect, and the main load center for the dwelling, a minimum number of disconnects can be used since all equipment is on one wall and is in close proximity. See "Perspectives on PV” in the July/August IAEI News for examples.

Batteries

A comparatively small number of PV systems, both off grid and utility-interactive, will employ batteries for energy storage. There are two general categories of batteries used in renewable energy systems. The older types are like car batteries and are called flooded, lead-acid batteries (see photo 7). They outgas water vapor, some sulfuric acid fumes, hydrogen, and oxygen gas when being charged vigorously. The other category of battery is known as a valve-regulated, lead-acid (VRLA) battery and, under proper charging, does not release gas or fumes (see photo 8). Both battery types will have terminals between the cells and connecting cables that must be checked periodically. Therefore, both types should be installed in a manner that does not allow inadvertent contact with any exposed, energized terminals. The flooded, lead-acid batteries will require weekly to monthly addition of water to the cells, and contact with the cell caps should be restricted due to the normal presence of battery acid in these areas. In general, the flooded batteries should be mounted in containers (battery boxes) that will allow for frequent servicing while still preventing unqualified people from coming into contact with the battery tops or the energized contacts. Lockable, heavy-duty plastic toolboxes work well in this application. Spilled-electrolyte containment is also a consideration due to the infrequent overcharging that may occur. Hydrogen gas from the batteries is not normally found in explosive concentrations unless contained in small volumes, and small ventilation holes in the top of any battery box will allow it to escape into the room, which should be a well vented area like a garage or utility shed. Venting manifolds are generally not required or desired.

VRLA batteries are more easily installed and generally only need the terminals protected from accidental contact. Containers are normally not needed.

Conduit penetrations in containers with flooded batteries should be made in the sides of the container below the tops of the batteries. This will minimize the possibility of any hydrogen gas (which rises) from getting into the conduits.

Clearance Spaces

NEC110.26 defines the clearances around electrical equipment that must be serviced when energized. Such equipment might include the PV dc disconnect, the inverter, and any batteries. The six-inch depth allowance in 110.26(A)(3) allows some leeway, but the AHJ will have to evaluate each installation. This is particularly true when the inverter has been placed above the batteries that have been mounted on the floor. The inverter requires clear space from floor to 6 1/2 ft and the batteries may stick out 6 in. in front of the inverter. Also, the batteries need the same clear space, but since the inverter usually has less depth than the batteries, it will not be an issue.

Some inverters have access requirements from the sides and this may pose additional space requirements. Also, the 90° opening requirements for doors and access panels may dictate additional space.

Summary

With the use of exterior or interior conduit runs and the use of surface mounted inverters and disconnects, it becomes obvious that the materials, techniques, and workmanship requirements for a PV installation are going to resemble more closely a commercial electrical installation than a residential one. With PV modules generating dangerous amounts of electrical energy for 40 years or more, it behooves every one working with PV systems, from the designer to the inspector, to do everything possible to achieve the highest standards of workmanship.

For Additional Information

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

Here is a link to the National Electrical Contractors Association web site. They sell ANSI/NECA 1-2006, Good Workmanship in Electrical Contracting:http://www.necanet.org/store/index.cfm?fuseaction=search_results&index_number=NECA1-06. A color 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: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/PVnecSugPact.html.

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. Copies of "Code Corner ” written by the author and published in Home Power Magazine over the last 10 years are also available on this web site: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html.

Proposals for the 2008 NEC that were submitted by the PV Industry Forum may be downloaded from this web site:
http://www.nmsu.edu/~tdi/pdf-resources/2008NECproposals2.pdf.

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. A schedule of future presentations can be found on the SWTDI web site.

Read more by John Wiles

Based on this series of articles and presentations that I make to groups of inspectors around the country, I get several calls and e-mails a week and sometimes several calls a day from inspectors looking at PV plans or inspecting PV systems. The questions that they pose are always challenging because most of the inspectors have done their homework and found the Code lacking in clear concise answers. I usually gain new insights on the Code from these calls. Here are some of the more common questions and the best answers that I have. I encourage these calls so that everyone involved can help to ensure that the numerous PV systems being installed are as safe as possible.

Location of main dc PV disconnect

Question: Where should the main dc PV disconnect be located? NEC Section 690.14 says either inside or outside at the point of first penetration of the PV source or output conductors in a readily accessible location. Is there a preference between inside and outside locations?

Answer: The dc PV disconnect resembles the ac service-entrance disconnect in function, although it is not required to be rated as service-entrance equipment. The location of this dc PV disconnect should take into account the local requirements for locating the ac service

Photo 1. DC PV disconnect grouped with ac service disconnect

disconnect since they more than likely take into account emergency response requirements. If the ac service disconnect for the house or structure is outside, it seems reasonable to put the dc PV disconnect outside in the same vicinity. In a similar manner, an inside ac service disconnect would seem to point to an inside location for the dc PV disconnect. Both ac and PV disconnects should be "grouped” (as defined by the AHJ) since they both shut off power to the building (see photo 1). In a few cases it has been argued that the PV system is a second supply to the house and may have the main dc PV disconnect remotely located from the ac service disconnect if all disconnects are properly placarded.

Many jurisdictions allow an inside ac service disconnect, although a locked house may not be readily accessible. If an inside disconnect is allowed, then many locations for the dc PV disconnect are possible including on the exterior wall of an upstairs bedroom for example. Some installers would like to put the disconnect in an attic to eliminate the wiring on the outside of the building, but an attic would not be considered readily accessible unless permanent, fixed stairs were available to the attic.

Location of ac PV disconnect

Question: Where should the ac PV disconnect be located?

Answer: In the smaller residential systems, the ac PV disconnect is usually a backfed breaker in the load ac center and, if the inverter is close to the load center containing the backfed breaker,

Photo 2. AC and dc disconnects grouped at the inverter

no additional ac disconnect is required. The ac circuit between the inverter and the load center is very similar to any ac branch circuit. If there is some distance between the inverter and the backfed breaker, then an additional disconnect should be located at the inverter to allow safe servicing of that product (see photo 2). The AHJ determines how far apart the inverter and the disconnect may be. Some require a spread-arms’ distance between the ac and dc disconnects at the inverter, and other AHJs allow the disconnect to be some distance apart as long as they are both visible from the inverter.

Inverters with internal ac and/or dc disconnects

Question: I am seeing inverters with ac and dc or just dc disconnects built into them. Do these inverters meet code requirements when installed without external ac and dc disconnects?

Answer: The NEC provides little guidance in this area. The inverters have been listed to UL

Photo 3. Internal ac and dc disconnects

Standard 1741 and are considered to be safe in operation. They do have the internal disconnects that allow the unqualified user to safely turn them on and off during normal operations (see photo 3). The AHJ or the jurisdiction should decide on the safety requirements for servicing these electronic devices. Section 690.18 suggests that the PV array be covered before servicing the system and that blocking the light from the modules would de-energize the output circuits if done properly. However, on large roof-mounted arrays, covering the entire array is not a common or easy practice. If the AHJ or jurisdiction judges that qualified people are going to be disconnecting those energized dc input conductors from the PV array in the inverter, then the internal disconnect is probably OK. However, if there is a possibility that the inverter will be removed for service by unqualified people, they probably should not be handling those energized PV input conductors, and at least an external dc disconnect should be required (see photo 4). Hopefully, anyone servicing one of these inverters would know enough to open the backfed ac breaker to remove ac power from the inverter before disconnecting the ac circuits.

Several older inverters (out of production) and some newer inverters have an electronics section that can be removed for service from a lower input/output circuit section. The AHJ should evaluate the difficulty of the removal process. Some units can require that energized conductors be pulled through conduit knockouts. The input/output power section remaining attached to the wall should be examined to ensure that it is safe for contact by unqualified people and that it is somewhat weather resistant if the inverter is mounted outside. If these conditions are not met, the AHJ might consider requiring external disconnects.

Location of manual disconnect

Question: The local utility requires a manual safety switch (disconnect) between the inverter and the utility point of connection. What are the Code requirements pertaining to the installation of this disconnect?

Answer: This safety switch is a common requirement imposed by many, but not all, utilities. The utility wants to ensure that there is no possibility of a PV system "islanding” and energizing a feeder that a lineman has disconnected from the utility. The listed, utility-interactive inverter will sense a turned off grid and shut down. This automatic action plus the lineman’s safety procedures of measuring, shorting, and grounding the line to be serviced plus wearing protective gear are sufficient to allow some utilities to not require the safety switch. Other utilities will require the safety switch and will dictate its location—usually near the utility meter. However, this safety switch is being installed on the premises wiring and must follow the general Code requirements as far as rating, conductors, wiring methods, grounding, height, and clearances. In this position on the dedicated branch circuit serving the PV inverter, the safety switch would not have to be rated as service-entrance equipment.

If the inverter is adjacent to the utility-required disconnect on the outside of the house, in many cases, it can also be used as the inverter ac disconnect. In a situation where the PV utility connection is made on the supply side of the service disconnect, this utility-required disconnect may also serve as the PV ac inverter disconnect if it were rated as service-entrance equipment.

Aluminum lay-in lugs

Question: I have a PV system where aluminum lay-in lugs have been attached to the narrow sides of the modules for equipment grounding. These modules are marked for grounding points only on the long side of the modules. Does this comply with the Code?

Answer: There will be a couple of things that the installer must verify. First, aluminum lay-in

Photo 5. Dry-location lug rusting outdoors

lugs are generally not listed for outdoor/wet applications because the setscrew is typically plated steel and will rust quickly (see photo 5). The correct lay-in lug for these applications is a tin-plated, solid-copper lug that has a stainless-steel screw (see photo 6). These lugs are listed for underground, direct-burial applications and have been found to be suitable for wet/outdoor applications. While they are not listed for use with aluminum conductors, the tin plating allows them to be bolted to aluminum surfaces (like aluminum bus bars and aluminum module frames). The aluminum module frame should be scraped to remove the invisible oxidation and an anti-oxidation compound like Burndy PENETROX A-13 should be applied between the lug and the aluminum module frame at the contact point. A solid-copper lug without the tin plating should not be used since copper should not come into contact with aluminum (see photo 7). Drilling the module on the short side away from the marked grounding points may violate both the listing and the warranty on the module. The module manufacturer should be contacted before any modification of the module is undertaken that deviates from the instructions supplied with the module or the markings on the module.

Photo 6. Direct burial lug with stainless-steel screw

Unbalanced PV array and inverter ratings

Question: I have a PV system where the PV array is rated at 3000 watts, but the inverter connected to the array is rated at only 2500 watts. Won’t this arrangement damage the inverter, make the system unsafe, and be non-code-compliant?

Answer: The rating (3000 watts in this case) of a PV array is normally expressed at a set of standard test conditions (STC) of 1000 watts per square meter of irradiance (sunlight intensity) and a module temperature of 25°C (77°F). These laboratory test conditions are infrequently met in the installed PV array. At an outdoor temperature of 35°C (95°F), the PV modules will be operating at a temperature of about 65°C (149°F) and the array will only be putting out about 2350 watts when the irradiance is 1000 watts per square meter. The lower power output is due to the fact that PV modules lose

Photo 7. Copper direct burial lug, not suited for aluminum contact

power at the rate of about 0.5 percent per degree Centigrade as the temperature increases. At lower temperatures, higher power levels from the array can be expected, but the inverter simply limits the input current from the array and/or the output power to the utility grid to keep the output from exceeding the inverter rated power. Sizing the array slightly larger than the inverter rating is normal and allows more energy to be delivered to the grid during hot sunny days and during cloudy periods. The inverter protects itself; there is no safety issue, and no Code violation.

For Additional Information

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

A color 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: (http://www.nmsu.edu/~tdi/roswell-8opt.pdf.) The Southwest Technology Development Institute web site (http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html) maintains a PV Systems Inspector/Installer Checklist and all copies of the previous "Perspectives on PV” articles for easy downloading. Copies of "Code Corner,” written by the author and published in Home Power Magazine over the last 10 years, are also available on this web site.

Proposals for the 2008 NEC that were submitted by the PV Industry Forum may be downloaded from this web site:
http://www.nmsu.edu/~tdi/pdf-resources/2008NECproposals2.pdf

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. A schedule of future presentations can be found on the SWTDI web site.

Read more by John Wiles

Those who have been following this series of articles for the last year or so may wonder what is involved in designing and installing a code-compliant, durable, reliable, and cost-effective PV system. Utility-interactive photovoltaic (PV) power systems are a mature technology. PV modules have warranties to 25 years and are predicted to produce significant amounts of power for 30 years or more. Inverters have warranties to 10 years and estimated life spans of 15 years or more with even greater longevity predicted in the future. PV systems can be designed and installed following existing guidelines and codes that will achieve long life, durable service, excellent safety, and cost effective power production. However, it is evident that great numbers of systems being installed today will not achieve the art of the possible because of poor design and installation practices. This article will address some of the steps that the PV systems vendor/designer/installer must accomplish to achieve a safe, durable, reliable, and cost-effective system.

Photo 1

The Equipment and the Design

PV systems can be designed and installed in a manner that will yield high levels of performance over the life of the PV modules, which is expected to be more than 30 years. Yes, inverters will have to be repaired or replaced during that time, but advances in inverter designs are driving their lifetimes ever longer. As in other fields, the quality of the products may vary and nearly all manufacturers have production problems from time to time. In most cases, the defective products are repaired or replaced under warranty and the properly designed and installed system will have a long and productive life.

Photo 2

The design of a system involves some complicated steps and details, a few of which have been outlined in previous "Perspectives on PV” articles. A full understanding of how the PV modules respond to the environment is needed. See the "Single Conductor Exposed Cables! Not In My Jurisdiction!” article in the July-August 2004 issue of theIAEI News. The electrical characteristics of the inverter must be matched to the output of the PV array under a wide variety of environmental conditions. The site electrical service must be examined to determine how to best interface the inverter to the utility in a code-compliant manner. See the "Making The Utility Connection” article in the September-October 2005 issue of theIAEI News. A site visit is absolutely necessary before any design can be completed.

The Site Visit

It is imperative that each site be visited to determine a number of critical design parameters. The proposed PV array location must be examined for available space, shading (now and in the future as the trees grow), and orientation (see photo 1). Special tools are available to the PV installer for predicting the impact of shading during each month of the year. Restrictive covenants frequently prohibit the installation of PV arrays on roof planes facing the desired direction. In some extreme cases, these covenants may prohibit any PV system from being installed on the roof. No one wants to cut down the 200-year old oak tree just south of the proposed PV array location. For the common roof-mounted systems, the structure of the roof must be examined not only for attachment methods, but also for structural loading. The location of the existing utility service entrance and the existing load center coupled with the proposed array location will determine where the inverter can be located. All dimensions must be recorded, as they will affect both the mechanical and electrical design. Access to the area where the PV array is to be located must be mapped out.

The Mechanical Design

The geographical location of the PV array will determine the environmental conditions (wind, snow, ice) that will strongly affect the mounting of the PV array. Both the array-to-rack and rack-to-roof or rack-to-ground mounting systems must be addressed in all areas. Structural loading may be positive (dead weight) or negative (wind uplift). High winds, particularly in coastal areas, and earthquakes will significantly impact the mechanical design. Lowered PV output from non-optimum orientations or shading may necessitate larger arrays if a certain output is required. Roofing materials from asphalt shingles, to metal roofs, to tile roofs must be penetrated without damage and then the penetrations effectively sealed against wind and water for the life of the system (see photo 2). Provisions should be made to allow easy removal of the PV array if the roof needs repair at some future date.

Routing of conduits and electrical wiring must be planned in advance. Codes generally require that the power conduits from the PV array remain outside the building shell until a readily accessible disconnect is reached. In some cases, metal conduits are allowed to penetrate the shell before reaching that first disconnect.

Nearly all roof structures in recent yea rs have either been designed by professional engineers (via software used by truss manufacturers) or by the installer strictly complying with the applicable building codes. Attaching any structure to these roofs that would affect either the dead weight or the live load should be preceded by an analysis of the possible effects on the roof.

An iterative process between the mechanical and electrical design is usually required. This is especially true when the site assessment does not permit an optimally sized (smallest) PV array.

The Electrical Design

The desired ac output, the available solar resource, the efficiency of the PV modules, the efficiency of the PV inverter, and the array orientation as well as any shading should be included in designing the system. After the system is sized, application of the requirements in theNational Electrical Code(NEC) and any local codes will determine the balance of systems (BOS) components such as conductor types and sizes, disconnects, and overcurrent protection. To some extent, these items are driven by the installation location (ground or roof) and the design of the inverter (internal disconnects). However, the local electrical inspector may apply local preferences/codes to some of these items. For example, external (rather than internal) disconnects for the inverter and an outside main PV disconnect may be required. Because the rules established by the NEC are numerous and complex, a PV design should only be attempted by someone fully familiar with theCodein the areas of residential and commercial electrical systems.

Coordination and Permitting

After the code-compliant design is completed (both electrical and mechanical), the PV system designer should coordinate with the building officials responsible for permitting and inspecting the system. The PV system design, at this stage, should be presented to the inspectors including as much appropriate documentation as possible. See the "PV Plan Check” article in the March-April 2006 IAEI News. The documentation should include all calculations used to ensure code compliance as well as specifications/cut sheets for each product being used. The inspectors may have their own interpretations of the code requirements of a PV system. Their comments should be integrated into the design, where possible and appropriate, before any hardware is purchased or installed. Conflicts between the requirements of the inspector and the designed system should be resolved at this point. Permits, both electrical and mechanical, should be obtained. In some cases, professional engineering approval must be obtained. Such approvals usually apply to commercial installations and, in some cases, to residential installations where roof loading is questioned.

Installation and Workmanship

PV modules will be generating hazardous amounts of power (voltage and possibly current) for the next 30 years or more even when inverters fail and are not repaired or replaced. These hazardous voltages must be well contained for that time in the face of severe outdoor environmental conditions. Daily sunlight (ultra violet radiation) over long periods of time, coupled with high temperatures (80°C +), make the use of the best materials and installation techniques mandatory. Residential PV installations typically resemble commercial electrical installations (with substantial use of conduit) more than they resemble residential electrical installations. The details of properly installing a high-quality, safe, durable PV system at the nuts-and-bolts level is a task best left to the electrician who has years of practical experience installing (but possibly not designing) electrical power systems (see photo 3).

Education, Training, and Experience Are the Keys

There is no "cookbook” for PV system design and installation. While a number of helpful written guides have been developed, none of them are, or can ever be, all inclusive; none of them will be able to teach the hands-on skills required; and none of them can imbue the installer with the years of experience required to learn the tricks of the trade. The needed hands-on details are not usually found in written guides, although some of the do-it-yourself manuals on electrical wiring try to provide instruction in these areas. Hands-on training given by various organizations is important and everyone involved in PV design and installation should avail themselves of every training opportunity. Most PV equipment manufacturers offer short (1–3 day) training sessions for people using their equipment (see photos 4 and 5).

Photo 5

Photo 6

Anyone involved in PV system design and installation must have a personal library (well-read and absorbed). That library should include as a minimum, the latest versions of the following:

• National Electrical Code Handbook
• Local electrical codes
• Factory manuals for all products being installed
• Manuals for related products (each manual has a few unique tips and techniques),
• Guides

– The author’s PV/NEC suggested practices manual
– The North American Board of Certified Energy Practitioners (NABCEP) Study Guide (www.NABCEP.org)
– A set of this IAEI News series of articles, "Perspectives on PV.”

Because most PV systems are more complex than the typical residential electrical system, and the environment is more extreme (roof tops), the experienced electrician has the best experience base for installing these systems. In all cases, no PV installations should be attempted without significant experience in the electrical trades.

The Team

A team consisting of a competent PV systems designer working with an electrician using the best available equipment from the component manufacturers and the best available guidance on PV installations can design and install a safe, durable, and cost-effective PV system. The views and comments of the electrical inspectors (and any other building inspector) should be solicited and followed at the design stage (see photo 6). The system should be installed using only the highest quality balance of systems components with the highest standards of workmanship—typically commercial electrical system levels of craftsmanship. Full compliance with the requirements of theNational Electrical Codeand any local codes is an absolute minimum. The electrical inspector is a key player as that person verifies the safety of the completed installation. Close coordination, even teamwork, among the PV systems designer, the PV installer, and the electrical inspector will be required on nearly every PV installation if the art of the possible is to be achieved.

For Additional Information

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

A color 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: (http://www.nmsu.edu/~tdi/roswell-8opt.pdf.) The Southwest Technology Development Institute web site (http://www.nmsu.edu/~tdi) maintains a PV Systems Inspector/Installer Checklist and all copies of the previous "Perspectives on PV” articles for easy downloading. Copies of "Code Corner” written by the author and published in Home Power Magazine over the last 10 years are also available on this web site.

Proposals for the 2008 NEC that were submitted by the PV Industry Forum may be downloaded from this web site:
http://www.nmsu.edu/~tdi/pdf-resources/2008NECproposals2.pdf

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. A schedule of future presentations can be found on the SWTDI web site.

Read more by John Wiles

As I make presentations on photovoltaic power systems and the National Electrical Code around the country, I frequently talk to inspectors who have as little as 15 minutes to make a residential electrical inspection. A common question is, "Can I inspect a residential PV system in 15 minutes?” This article will examine that question and also take up the question, "Should only 15 minutes be allocated for inspecting a residential PV system?”

Photo 1. Improperly wired 240-volt inverter; neutral wired to PE terminal

Let’s start with an ideal situation. The inspector is familiar with PV systems in general and has inspected quite a few. He or she receives an application for a permit for a PV system, and that application is accompanied by all of the material outlined in the "PV Plan Check” article in IAEI News, March/April 2006. A review of the supplied material shows no major problems in code compliance, and the installer quickly rectifies the few minor problem areas found. A team consisting of a PV vendor with a history of good PV installations and an electrical contractor/electrician who has a commercial electrical license and some PV experience has done the design of the system and the installation.

Here are some of the items that an inspector should verify during the site visit. They are listed in order of importance and in order of safety for the inspector. For a more complete list, see "Perspectives on PV,” in IAEI News, May/June 2005.

Grounding and Bonding

Photo 2. Inverter with three DC inputs

Many residential PV systems (6 kW and below) have all of the PV equipment, both ac and dc, grounded by a single equipment grounding conductor connected from the modules to the grounding bus bar in the residential ac load center. The module frames, the PV array mounting rack, the dc disconnect, the inverter, and the one or more ac disconnects are all grounded by the single equipment grounding conductor routed to the ac load center. The first item a careful inspector should verify is that the equipment grounding conductor from the PV system inverter has been connected properly in the ac load center grounding bus bar and that the ac load center has a proper connection to ground (earthed). If this equipment grounding has not been done properly, a ground fault in the PV array or elsewhere in the system may put several hundred volts on the ungrounded exposed metal surfaces of any PV equipment.

As PV systems mature and UL standards and the Code evolve, it is hoped that the grounding of PV systems will become more robust. Even now, some systems will be installed with a dc grounding electrode conductor connected to a dc grounding electrode or to the ac grounding electrode.

If the backs of the PV modules can be closely observed, proper grounding of the modules should be checked. The use of the hardware and instructions supplied by the module manufacturer should have been followed as shown in the instruction manual that was delivered, hopefully, with the permit request. See "Perspectives on PV” in the September/October 2004 issue of the IAEI News for more details on grounding PV systems.

AC Point of Connection to the Utility

While the residential ac load center is open to check the grounding connection, the value of the backfed PV circuit breaker can be noted. It should match the value on the permit application and not be generally greater than 20% of the load center rating. This assumes that the main breaker and the load center have the same rating [see NEC 690.64]. This requirement limits the backfed PV breaker to a maximum of 20 amps on a 100-amp load center and to a maximum of 40 amps on a 200-amp panel. Breakers larger than this indicate that the utility connection should have been made on the supply side of the service disconnect. See "Perspectives on PV” in the January/February 2005 issue of the IAEI News for supply-side connection requirements.

Inverters

The inverter should be opened to check the field-installed connections. Some inverters will require metric hex socket drivers (or Allen wrenches) to open. One manufacturer makes a sealed inverter with permanently attached cables for connections to the adjacent ac and dc disconnects.

Inverters with a 120-volt output should have line, neutral (grounded), and equipment grounding conductors between the load center and the inverter. Inverters made outside the U.S. may have the equipment grounding terminals marked PE for "Protective Earth.” Some 240-volt inverters have only line 1, line 2, and equipment grounding conductors with no neutral (grounded) conductor, while others will have line 1, line 2, neutral, and equipment grounding conductors. The inverter manual (submitted with the permit request) will show the proper connections. Inverters requiring no neutral connection must not have the neutral conductor attached to anything, particularly an equipment grounding terminal, because such a connection would establish a connection between ground and the neutral conductor that is prohibited by NEC Section 250.6 and 250.24(A)(5).

The dc input connections to the inverter may include one or more sets of positive and negative conductors as well as at least one dc equipment grounding conductor routed to either an external dc disconnect or to the PV array (see photo 2).

AC and DC Disconnects

Photo 3. Improperly grounded dc disconnect; violates 250.8, 110.3(3), 250.96(A), and 250.4(A)(5)

 

While the dc PV disconnect enclosure is opened, the color coding of the conductors should be checked. Most current PV systems use a negative ground and the negative conductor should be colored white and should not be switched or fused by the disconnect. There are a few positive grounded PV systems being installed, and in this case, the positive conductor is now colored white and is not switched. Section 690.35 of NEC-2005 permits the use of ungrounded systems (neither of the circuit conductors is grounded) and these will be showing up. These ungrounded systems must meet several additional requirements including switching both of the ungrounded circuit conductors with neither conductor colored white [see NEC 690.35]. The inverter or the system should be clearly marked (not yet a Code requirement) showing the type of grounding (negative ground, positive ground, or ungrounded) to allow easy determination of the proper color codes.

Table 1. Typical DC Wiring Conductor Colors

There is no specified color code for the ungrounded conductors, and any color is permitted as long as gray white, green, and green and yellow are not used. Typical conductor insulations are shown in table 1.

Both circuit conductors (positive and negative) should be routed through the disconnect enclosure even though only the ungrounded conductor is switched. Avoiding a "switch loop” configuration ensures that both circuit conductors are always in close proximity for best functioning of overcurrent devices and to allow a bolted connection point for the grounded conductor on an isolated "neutral bus” in the enclosure, if required.

In the dc PV disconnect, the always "hot” conductors from the PV array wiring should be connected to the top (covered) "Line,” terminals on the switch while the lower, exposed, "Load” terminals should be connected to the inverter. On the ac disconnect, the upper "Line” terminals should be connected to the utility power conductors that come from the backfed ac load center. The lower "Load” terminals should be connected to the inverter.

Workmanship and the Roof

The equipment used and the workmanship on most residential PV systems will more closely resemble the equipment and workmanship on a commercial electrical installation than those items in a residential electrical system. There will usually be surface-mounted disconnects and much of the wiring will be in exposed, surface-mounted conduit.

Photo 5. Module wiring properly secured

The installer should have a ladder on site the day of the inspection to facilitate examining the installed PV array. A quick look at the PV array on the roof should verify that any exposed wiring is firmly secured to the PV modules or the mounting structure and is not dangling down where it would be subject to physical damage (photo 5).

If the backs of the PV modules can be closely observed, proper grounding of the modules should be checked. The hardware supplied by the module manufacturer should have been used as shown in the instruction manual delivered with the permit application. Each PV module must be grounded, and if exposed, single conductor cables touch the mounting racks or a metal roof, those objects should also be grounded. See "Perspectives on PV” in the September/October 2004 issue of the IAEI News for more details on grounding PV systems.

The conductors used for module interconnections should be as specified in the permit application with respect to size (AWG), insulation type, and temperature rating. Any PV combiners containing overcurrent devices exposed to sunlight should be noted and the plans and technical data reviewed to determine if adequate temperature deratings were applied. Conduits in sunlight will also be exposed to higher-than-ambient temperatures.

Inspect in 15 Minutes?

Yes, it might be possible to perform the above inspections in 15 minutes if the inspector has spent some time at the plan-check stage and is experienced in PV systems employing this inverter and the installer is there to answer questions, open the inverter and other equipment as necessary and to provide a ladder for roof access. However, any problems found in the above areas should warrant a closer look at the entire system; and when more details are examined, the inspection time can grow. A lack of familiarity with either PV in general, the equipment being installed, or the installer would normally dictate that the inspection take more time. How much? Some residential PV inspections for new inspectors are somewhat of a training session and with a knowledgeable installer, examining and discussing all of the details relating to a durable, safe (for 50 years) installation might take two or more hours.

Should We Do 15-Minute Inspections?

See the little girl in the lead-in photo? That PV system she is touching will still be producing power when her grandchildren are her age. It will take more than a 15-minute inspection to ensure that the PV system will be as safe then as it is now. Fifteen minutes is probably insufficient time to ensure the public safety over a 40–50 year period.

For Additional Information

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

A color 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: (http://www.nmsu.edu/~tdi/roswell-8opt.pdf.) The Southwest Technology Development Institute web sitehttp://www.nmsu.edu/~tdimaintains a PV Systems Inspector/Installer Checklist and all copies of the previous "Perspectives on PV” articles for easy downloading. Copies of "Code Corner” written by the author and published in Home Power Magazine over the last 10 years are also available on this web site.

Proposals for the 2008 NEC that were submitted by the PV Industry Forum may be downloaded from this web site: http://www.nmsu.edu/~tdi/pdf-resources/2008NECproposals2.pdf

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. A schedule of future presentations can be found on the SWTDI web site.

Read more by John Wiles

Electrical inspectors and electrical permitting personnel are seeing increasing numbers of photovoltaic (PV) power systems, both at the permitting stage and at the initial inspection. Both processes go much more smoothly for all concerned when the electrical system is properly documented. Since the typical PV installer has not installed hundreds of the same PV system, and the inspector has not seen hundreds of these systems, the documentation for these systems must, by necessity, be somewhat more detailed than the documentation associated with a typical residential electrical system. This article will examine a typical residential, utility-interactive PV system in terms of a package that should be submitted by the installer when applying for a permit or discussing the system with the inspector prior to installation. Installers can use this material to develop the package.

The Single-Line Diagram

A one-line diagram such as shown in figure 1 should accompany the permit application. Actually, since the details of disconnects and grounding are not familiar to all involved, a three-line diagram would be even better as shown in figure 2. While a formal CAD-generated diagram on 24″ x 36″ paper is not generally required, something better than a back-of-the-envelope sketch should be presented. The circled letters in the figures will be referenced below to indicate information that should appear on or be attached to the plan.

Figure 1. One-line PV system diagram

Figure 2. Three-line PV system diagram

Equipment Lists and Specifications

A list of the equipment used and the specifications for that equipment should be included with the permit. This list would include the PV-specific equipment such as the PV modules, the inverter, the fuses, and circuit breakers. Listing/certification and rating information must be included. The specifications of this equipment are necessary to determine if the conductors have been properly sized and that the fuses and circuit breakers used in the dc portions of the system are properly rated. Factory cut sheets or pages from instruction manuals are the preferred way to present this information.

The System

On the one- and three-line diagrams, the following information should be indicated, or that information should be attached.

A. PV Array

A.2. The ampacity of module interconnection cables, after corrections for conditions of use, must not be less than 1.56 times module short-circuit current (Isc) marked on the back of the module. Due to the exposed, outdoor location and high operating temperatures, all conductors should have insulation rated for 90°C and wet conditions (in conduit, THHN/THWN-2 or RHW-2). Exposed conductors (usually USE-2) must also be sunlight resistant.

B. Conduits
B.1. Conduits will typically be used throughout the system and specifically after the wiring leaves the PV array. They will be installed in various locations, some of which may be in sunlight. [See NEC-2005, 310.10 Exception No. 2]. Conduit fill and conductor ampacity calculations for conduit fill and temperature calculations should be included.

B.2. The PV source circuit or PV output conductors must remain outside the structure until they reach the readily accessible PV dc disconnect switch unless the conductors are installed in a metallic raceway [690.14, 690.31(E)].

Photo 2. DC PV disconnect with required marking

C. Module and String Overcurrent Protection and PV DC Disconnect
C.1. Overcurrent protective devices (OCPD) in dc circuits may not be required when there are only one or two strings of modules. Three or more strings of modules typically require an OCPD in each string. The current rating of the OCPD, when required, should be 1.56 Isc for that circuit [690.8, 690.9]. The voltage rating of the OCPD should be not less than the maximum PV systems voltage found in A.1. The strings may be combined in parallel in a combiner box ahead of an unfused dc PV disconnect or combined at the output of the dc PV disconnect (figure 1 and photo 2). Appendix J in PV Power Systems and the National Electrical Code: Suggested Practices by the author has detailed calculations on the requirements for OCPD in the dc PV array circuits [see Additional Information below]. Any OCPD connected in series with a module or string of modules should not have a value greater than the maximum series fuse value marked on the back of the module (photo 1).

C.2. The PV array output should be connected to the top or line side of the main dc PV disconnect. The circuit to the inverter dc input should be connected to the bottom or load side of the disconnect. The grounded PV output conductor (usually the negative conductor) must not be switched by the disconnect, and this grounded conductor must be color-coded white. Some recent PV systems have a positive conductor that is the grounded conductor; it will be color-coded white, it will not be switched, and in this case, the ungrounded negative conductor will be connected to the switch pole. Future PV systems may not have any grounded PV array circuit conductors and then both PV output conductors would be switched and neither would be color-coded white [690.35].

C.3. PV output conductors, after any combining of series strings, should have an ampacity, after corrections for conditions of use, of not less than 1.56 times the module Isc times the number of strings in parallel.

D. The Inverter
D.1. The inverter must be listed for utility-interactive (U-I) use [690.60].

D.2. The inverter maximum input voltage must not be exceeded in cold weather [110.3(B)]. See A.1.

D.3. For PV systems with the modules mounted on the roofs of dwellings, the inverter must have a 690.5 ground-fault protection device (GFPD). When a GFPD is built in to the inverter (most U-I inverters below 10 kW), there should be no external (to the inverter) bond between the grounded circuit conductor and the grounding system.

D.4. In addition to ac and dc equipment grounding conductors, the inverter must also have a provision for a dc grounding electrode conductor, and that conductor must be properly connected to the grounding system (690.47). This requirement is not clearly spelled out in the Code and many U-I inverters meet the dc grounding requirements by using the ac equipment grounding conductor. The dotted lines in figure 2 show alternate routing and bonding for the dc grounding electrode conductors. See the July-August 2005 IAEI News "Perspectives on PV” article for details.

Photo 3. Inverter with internal ac and dc disconnects

D.5. AC and/or dc disconnects internal to the inverter are acceptable if they are readily accessible and the AHJ judges that only qualified people will service the inverter (photo 3). Otherwise, external disconnects will be needed (photo 4). Internal disconnects, if circuit breakers, may not be suitably rated for the ampacity of PV output conductors (the rating may be too high) and external OCPD may be needed.

E. Inverter AC Output Overcurrent Device and Disconnect
E.1. Any OCPD located in the inverter ac output should be rated at 1.25 times the maximum continuous output current of the inverter. The maximum continuous current is specified in the inverter manual or is calculated by dividing the inverter rated output power by the nominal ac line voltage. This OCPD may be a backfed breaker located in the dwelling load center, the place where any possible fault currents for the inverter ac output conductor would originate. A backfed breaker in the dwelling load center could also be the inverter ac disconnect if the inverter were located near the load center.

Photo 4. Inverter with external ac and dc disconnects

E.2. The inverter ac disconnect should be "grouped” with the dc inverter disconnect and both should be "near” the inverter. The AHJ determines the meaning of "grouped” and "near.” Most systems use the PV disconnect (see B.2.) as the dc inverter disconnect, but if the PV dc disconnect is on the outside of the building and the inverter is on the inside, a second dc inverter disconnect may be required inside the building at the inverter location. The same thing would apply if the backfed circuit breaker in the building load center was on the outside wall and the inverter was on the inside. A disconnect (usually a circuit breaker) would be required inside the building near the inverter.

E.3. From the above, it becomes obvious that the system diagram should show the physical location of all components.

F. Utility-Required AC Disconnect

Photo 5. Inverter ac disconnect combined with the utility disconnect to the right of the inverter

F.1. Many utilities require a visible-blade, lockable-open disconnect in the ac output circuit of the inverter. This disconnect is usually located within sight of the service entrance meter so that emergency response people can easily find it. The top terminals (line side) of this disconnect should be connected to the circuit that comes from the ac load center since it will usually be energized by utility voltage. The bottom terminals (load side) should be connected to the circuit from the inverter. This disconnect may be fused or unfused depending on the specific requirements of the utility. Photo 5 shows an ac disconnect to the right of the inverter that serves as both the ac inverter disconnect and the utility-required ac PV system disconnect. The utility point of connection is inside the house through a backfed circuit breaker in the load center.

F.2. The utility disconnect must have a minimum current rating of 1.25 times the maximum continuous output current of the inverter [690.8].

G. Point of Connection-Load Center
G.1. Most of the smaller residential PV systems will make the point of connection with the utility through a backfed breaker in the dwelling. NEC Section 690.64(B) establishes the requirements. If the load center is rated at 100 amps and has a 100-amp main breaker, the maximum current from all backfed PV breakers would be 20 amps (either or both phases of the 120/240 panel). A 200-amp load center with a 200-amp main breaker would be limited to 40 amps of backfed breakers. However, many installations have PV systems that are larger than the 100-amp or 200-amp load centers can accommodate. Other combinations are possible as is a supply-side tap of the service entrance conductors. See 690.64 and "Perspectives on PV” in the IAEI News in the September-October 2005 and January-February 2006 issues for more details.

Summary

All of the above information should be included in plans submitted for obtaining a permit for the installation of a PV system. The more information submitted, the easier it will be for the PV system designer/installer to communicate to the inspector/permitting official that the system design and component selection meet the requirements of the NEC. It is far more cost effective to change the design on paper before any hardware is purchased and installed than it would be after the system has been installed. Ready for the inspection? See the checklist and more details in "Perspectives on PV” in the May-June 2005 issue of the IAEI News.

For Additional Information

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

A PV Systems Inspector/Installer Checklist will be sent via e-mail to those requesting it. A color 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: (http://www.nmsu.edu/~tdi/roswell-8opt.pdf.) The Southwest Technology Development web site (http://www.nmsu.edu/~tdi) maintains all copies of the previous "Perspectives on PV” articles. Copies of "Code Corner” written by the author and published in Home Power Magazine over the last 10 years are also available on this web site.
Proposals for the 2008 NEC that were submitted by the PV Industry Forum may be downloaded from this web site: http://www.nmsu.edu/~tdi/pdf-resources/2008NECproposals2.pdf

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. A schedule of future presentations can be found on the SWTDI web site.

Read more by John Wiles

In the September/October 2005 issue of IAEI News, the "Perspectives on PV” article discussed making the utility connection for utility-interactive PV systems. In some of the larger residential PV systems and in many commercial PV systems, the grid connection must be made on the supply side of the service disconnect to comply with the requirements of NEC 690.64. In designing PV systems for code compliance, knowledge of all of the various Code requirements is a must. This article will cover some of these requirements as they apply to a supply-side tap of the service-entrance conductors. PV systems employing supply-side connections should be inspected with these requirements in mind.

Photo 1. Utility-required AC PV system disconnect. Note improper grounding connections

Service-Entrance Conductor Taps for Utility-Interactive Inverter Systems

Section 690.64 of the NEC establishes how and where a utility-interactive PV system may be connected to the utility system. The point of connection may be either on the load side of the service disconnect or the utility (supply) side of the service disconnect. In many cases, the complex requirements for load-side connections established by 690.64(B)(2) make such a connection impractical and dictate that the utility-interactive inverter be connected on the supply side of the service disconnect. Figure 1 shows the basic one-line diagram of a supply-side tap. Here are some, but not all, of the major Code sections that address the requirements for such a connection.

Can a Service-Entrance Conductor be Tapped?

Section 690.64(A) allows a supply (utility) side connection as permitted in 230.82(6).

Section 230.82(6) lists solar photovoltaic equipment as permitted to be connected to the supply side of the service disconnect.

It is evident that the connection of a utility-interactive inverter to the supply side of a service disconnect is essentially connecting a second service-entrance disconnect to the existing service and many, if not all, of the rules for service-entrance equipment must be followed.

Section 240.21(D) allows the service conductors to be tapped and refers to 230.91.

Section 230.91 requires that the service overcurrent device be co-located with the service disconnect. A circuit breaker or a fused disconnect would meet these requirements.

A Frequent Utility Requirement May Also Be Met

When the new PV service disconnect consists of a utility-accessible, visible-break, lockable (open) fused disconnect (safety switch), it may also meet utility requirements for an external PV ac disconnect. While this utility-required switch is not a Code requirement, it is installed on the premises, and the NEC requirements for such an installation must be followed. Photo 1 shows a typical disconnect required by a utility for a 10 kW three-phase PV system. Note that it has been grounded improperly by using lugs and sheet metal screws rather than with the required ground-bar kit listed by the manufacturer.

Section 230.71 specifies that the service disconnecting means for each set of service-entrance conductors shall be a combination of no more than six switches and sets of circuit breakers mounted in a single enclosure or in a group of enclosures. The addition of the photovoltaic equipment disconnect would be one of the six.

Locations and Markings

Photo 2. Label on ac PV disconnect

Section 705.10 requires that a directory be placed in a central location showing the location of all power sources for a building. Locating the PV service disconnect and the direct-current PV disconnect (690.14) adjacent to or near the existing service disconnect may facilitate the installation, inspection, and operation of the system. See photo 2 for a typical label that is applied to the ac PV Disconnect.

Size and Rating

Section 230.79(D) requires that the disconnect have a minimum rating of 60 amps. This would apply to a service-entrance rated circuit breaker or fused disconnect used to connect the output of the PV system to the utility grid.

Section 230.42 requires that the service-entrance conductors be sized at 125 percent of the continuous loads (all currents in a PV system are considered worst-case continuous currents). The actual rating should be based on 125 percent of the rated output current for the utility-interactive PV inverter as required by 690.8. The disconnect must have a 60-amp minimum rating. This 60-amp minimum requirement would apply even if the inverter rated continuous output current dictated only a 15-amp circuit. Conductor ampacity adjustment factors for temperature and conduit fill may have to be applied.

For a small PV system, say a 2500-watt 240-volt inverter requiring a 15-amp circuit and overcurrent protection, these requirements would require a minimum 60-amp rated disconnect, but 15-amp fuses could be used; fuse adapters would be required. While 15-amp conductors could be used between the inverter and the 15-amp fuses in the disconnect, 230.42(B) requires that the conductors between the service tap and the disconnect be rated not less than the rating of the disconnect; in this case 60 amps.

How we would deal with the minimum 60-amp disconnect requirement and a 15-amp inverter overcurrent requirement using circuit breakers is not straightforward. A circuit breaker rated at 60 amps could serve as a disconnect and it could be connected to a 15-amp circuit breaker to meet the inverter overcurrent device requirements. In this case, the requirements of 690.64(B)(2) should be applied to the ampacities of any conductors involved, because the 15-amp circuit breaker now becomes a load-side connection on the new 60-amp service disconnect.

Interrupt Capability

Section 110.9 requires that the interrupt capability of the equipment be equal to the available fault current. The interrupt rating of the new disconnect/overcurrent device should at least equal the interrupt rating of the existing service equipment. The utility service should be investigated to ensure that the available fault currents have not been increased above the rating of the existing equipment. Fused disconnects with RK-5 fuses are commonly available with interrupt ratings up to 200,000 amps (Photo 1).

Section 230.43 allows a number of different service-entrance wiring systems. However, considering that the tap conductors are unprotected from faults (except by the primary fuse on the utility distribution transformer), it is suggested that the conductors be as short as possible with the new PV service/disconnect mounted adjacent to the tap point. Conductors installed in rigid metal conduit would provide the highest level of fault protection.

Photo 3. Exothermic weld splice in grounding electrode conductor

All equipment must be properly grounded per Article 250 requirements. For example, photo 3, shows an exothermic weld irreversible splice in a grounding electrode conductor.

Additional service-entrance disconnect requirements in Article 230 and requirements in other articles of the NEC will apply to this connection.

Where to Connect?

The actual location of the tap will depend on the configuration and location of the existing service-entrance equipment. The following connection locations have been used on various systems throughout the country.

On the smaller residential and commercial systems, there is sometimes room in the main load center to tap the service conductors just before they are connected to the existing service disconnect. In other installations, the meter socket has lugs that are listed for two conductors per lug. Combined meter/service disconnects/load centers frequently have significant amounts of interior space where the tap can be made between the meter socket and the service disconnect. Of course, adding a new pull box between the meter socket and the service disconnect is always an option.

Figure 1. Supply-side interconnection diagram

In the larger commercial installations, the main service-entrance equipment will frequently have bus bars that have provisions for tap conductors.

In all cases, safe working practices dictate that the utility service be de-energized before any tap connections are made.

Summary

Utility-interactive PV systems can be designed to be safely connected to the supply side of an existing service disconnect. These connections are being made throughout the country on both residential and commercial PV systems.

Back to the Grid, The End of an Era?

There is one long-term downside of installing a PV system on the roof of a building. At some point the roof may have to be repaired.

The conventional wisdom in New Mexico, where the author lives, is that it is a pretty arid state. Average rainfall in the southern end of the state is about 9–10 inches per year, but most of this rain comes in the form of heavy thunderstorms during the July–October rainy season.

This year, the author was unfortunate enough to have downpours of 4.5 inches and 1.5 inches hit his home in two successive weeks. Two significant roof leaks occurred on his 18-year old "flat” roofed home and neither could be located nor fixed, even after significant patching. The house will have to be re-roofed after all of the solar equipment is removed. That solar equipment consists of a large solar hot water collector system and a 4 kW PV system covering most of the roof area. On Tuesday, October 4th, the local utility reinstalled the KWH meter and the house became grid powered after 16 years of off-grid PV operation. The end of an era? No, hopefully, just a temporary, 2–3 month interruption, until the roof is repaired.

For Additional Information

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

A PV Systems Inspector/Installer Checklist will be sent via e-mail to those requesting it. A color 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: (http://www.nmsu.edu/~tdi/roswell-8opt.pdf.) A black and white printed copy will be mailed to those requesting a copy via e-mail if a shipping address is included. The Southwest Technology Development web site (http://www.nmsu.edu/~tdi) maintains all copies of the previous "Perspectives on PV” articles. Copies of "Code Corner” written by the author and published in Home Power Magazine over the last 10 years are also available on this web site.

Draft proposals for the 2008 NEC being developed by the PV Industry Forum may be downloaded from this web site:
http://www.nmsu.edu/~tdi/pdf-resources/2008NECproposals2.pdf

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. A schedule of future presentations can be found on the SWTDI web site.

Read more by John Wiles

Well, not exactly. Yes, all of those things will usually keep a system uses sunlight for fuel. However, these and other weather conditions also affect how a PV system is designed and installed to comply with the requirements of the National Electrical Code. With a PV power system lifetime exceeding 40 years, Mother Nature is going to use every trick in the book to make that system fail before its time. PV designers, installers, and inspectors need to devote significant attention to the weather-related safety requirements for PV systems to help ensure long-lived, hazard-free electrical installations.

Photo 1. THHN conductors exposed to sunlight

Intense Solar Radiation and High Temperatures

Before we look at the dark side of PV, let’s examine hot and sunny. PV modules are designed to operate in sunlight and the more sunlight they get, the more power and energy they will produce. The "Perspectives on PV” article in the July-August 2004 IAEI News (available on the SWTDI web site) addressed how the PV module’s electrical output is affected by the intensity of the solar radiation. But what about the related issues of the effects of temperature and ultra-violet radiation on the other equipment? Any equipment exposed to the sunlit environment should be rated for the exposure. Exposed conductors and cables must be marked sunlight resistant (UF and TC cables) or be tested during the listing process for UV exposure (USE and SE, Table 310.13) cables. Using the wrong conductors can lead to failures (photo 1). Because of the normal operating environment, cables attached to PV modules must be listed for wet (the W designator) and hot environments (the HH designator) and a -2 after the cable type gets them both. We have tested PV installations that have been in hot, sunny, dry weather for two weeks or more, opened module j-boxes and conduit bodies and had hot water run out. -2 cables are a must.

Underwriters Laboratory is releasing a specification for a new "PV” cable. Cables meeting this specification will have to pass a 720-hour accelerated UV exposure test, be rated for wet locations, have at least a 90°C rated insulation, have a flame retardant compound, and have a physically tougher insulation than type USE cable. Although the intent of the specification was that compliant cables would now meet the requirements for use in ungrounded PV systems as permitted by Section 690.35 of the NEC, it has yet to be determined how the "PV” cable will be used, given the existing code language in 690.35(D). The issue will hopefully be clarified in the 2008 NEC and the PV industry is looking at ways to use this cable long before the 2008 Code is enacted. Enlightened electrical inspectors who may see the new cable as an acceptable alternative to USE-2 may be the key to early its adoption.

Photo 2. Pipe clamps with inserts holding cables securely

Cord grips and cable clamps used on outdoor junction boxes should be UV rated. In some cases, metal cord grips have been used, and while metal is resistant to UV, these generally have not been listed for outdoor use because they can corrode rapidly. Nylon cable ties are frequently used to tie conduits and exposed cables to module racks. The white cable ties have no UV resistance, and even some of those that are black fail in a few months. The use of listed cable ties specifically marked (at least on the package) for outdoor use and sunlight resistance should be encouraged. Even better is the use of stainless steel pipe clamps with neoprene rubber inserts to firmly secure exposed single conductor cables to racks and frames (photo 2).

Photo 3. PVC conduit and cement darkened with age

The Fine Print Note No. 2 in 310.10 of the 2005 NEC points out that conduits on buildings in sunlight operate at temperatures of 17°C above the ambient temperatures. Because conduits in PV systems are exposed to sunlight for decades, the raceways many times become discolored or darken with age (photo 3). Therefore, I suggest to the PV installers that 20°C be added to the highest ambient temperature when doing ampacity calculations, to account for the higher solar energy absorption of the aged materials. With PV module junction boxes operating in the 65–75°C (and hotter) ranges and conduits in sun in ambient temperatures of 40–50°C plus the added 20°C for solar heating, it becomes evident that 310.15 temperature corrections are critical in calculating ampacities of wiring for PV systems.

Photo 4. PV combiner in the sun

PV combiner boxes that combine the outputs of strings of PV modules are also mounted in the sun. These devices (photo 4) usually contain overcurrent devices, and most overcurrent devices are rated for operation in ambient temperatures up to 40°C. With ambient temperatures in many locations of 40°C (45–50°C in the Southwest), solar heating of these enclosures pushes the internal temperature well above 40°C. The overcurrent device manufacturer must be consulted for appropriate temperature corrections. After applying the corrections by increasing the rating of the overcurrent device, the installer must then go back and verify that conductors and modules are properly protected from fault currents.

We also have to deal with those often overlooked terminal temperature limitations in NEC 110.14(C) because the high PV module temperatures require the PV installer to use 90°C rated conductors. While the modules all have terminals rated for use with 90°C conductors, the combiner boxes and most of the other fused disconnects and overcurrent devices have terminals that are restricted to use with 60°C or 75°C rated conductors. Some of the combiner boxes do not have temperature markings, and since the overcurrent devices are usually below 100 amps, a conductor temperature limitation of 60°C must be assumed. Things get pretty

Photo 5. PV combiner in shade

complex when we deal with a fused combiner box, for example, with unmarked terminal temperature limitations. Consider one operating in the sun in Phoenix, Arizona, where the ambient temperature may be 45°C for weeks at a time. The box temperature could be 55–60°C (requiring 90°C insulated conductors), the fuse rating must be temperature corrected for the 55–60°C operating temperature, and then the operating temperature of the conductor/terminal at these elevated temperatures must be estimated to be less than 60°C. Obviously, if the internal temperature of the enclosure is near 60°C, it is going to be difficult to have fuse terminals operating below 60°C with any appreciable current in the terminals. In this case, the prudent path would be to replace this PV combiner with one that is marked for use with 75°C insulated conductors. At the very least, any enclosure containing overcurrent devices installed in the hot Southwest (and other hot locations) should be mounted in the shade where it will be subjected to no more than the high ambient temperatures (photo 5).

Wind, Sleet, Snow and Rain

Moving from the hot summer Southwest (and other parts of the country) to winter and the colder locations, we see other weather related issues. Equipment has to be able to withstand wind-driven rains. The use of appropriate types of NEMA enclosures will generally ensure that the internal equipment will not be subject to direct water spray. The use of listed devices will ensure that the internal connections are also generally immune to the effects of wind-driven rain. However, some custom, field-assembled enclosures may have been made with materials that are not well designed for even a little moisture. Rust may form when the internal components have not been properly specified for outdoor/damp areas (see photo 6).

 

Photo 6. Rust due to improper use or location of components

 

High winds are an issue in coastal areas where hurricanes are common as well as in many other areas of the country. Building codes in these areas generally specify how items on the roof and on the ground are to be fastened down to resist the lifting forces of the wind. The Study Guide for the North American Board of Certified Energy Practitioners (NABCEP) has some guidance for PV installers in this area that is based on information in the National Design Specification for wood construction and on roofing manuals. The Study Guide may be downloaded from the Resources section of the NABCEP web site (www.nabecp.org).

In areas of the country where there is snow buildup on roofs, attention must be directed to securely fastening all conductors and cables to the module racks or mounts and to the roof. Otherwise, sliding snow can rip wires loose and pull conduits loose. Similar attention to these workmanship details should be applied to windy areas and in all installations, a neat, workman-like installation will usually be safer that a messy installation (photo 2).

The PV designer/installer will usually be required to make a tradeoff between the best tilt angle for PV array performance and the angle that will best shed snow. Fortunately, as the installation location moves farther north (into snow country), the tilt angle for best performance gets greater and even assists in shedding snow. However, these higher tilt angles usually result in the PV modules being subjected to higher wind loading, so secure mounting is a must.

Photo 7. Too much snow means no juice (Photo courtesy of NREL)

At very low temperatures, snow, sleet and freezing rain may adhere to the PV modules and must be removed if full output from the PV system is desired (photo 7). Obviously rooftop installations may make this more difficult. On the other hand, ground-mounted arrays must be high enough to avoid deep snow and drifts.

Hail? Usually, hail doesn’t pose too much of a problem. The PV modules are made with tempered glass and the modules are tested with impacts simulating hailstones.

Summary

Yes, sleet, snow, rain, and the dark of night will prevent a PV system from producing energy. But when the snow melts and the sun comes up, that PV system will again be generating power for a very, very long time. The wide range of environmental conditions in which PV systems are installed impose significant design and installation requirements. The NEC has been addressing such requirements for many years. The long life of these systems points to the need for durable hardware and high levels of workmanship. The equipment is required to be up to the task. Installers and inspectors must also be up to the job.

For Additional Information

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

A PV Systems Inspector/Installer Checklist will be sent via e-mail to those requesting it. A color 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: (http://www.nmsu.edu/~tdi/roswell-8opt.pdf. ) A black and white printed copy will be mailed to those requesting a copy via e-mail if a shipping address is included. The Southwest Technology Development web site (http://www.nmsu.edu/~tdi) maintains all copies of the previous "”Perspectives on PV”" articles. Copies of "”Code Corner "” written by the author and published in Home Power Magazine over the last 10 years are also available on this web site.

Draft proposals for the 2008 NEC being developed by the PV Industry Forum may be downloaded from this web site: http://www.nmsu.edu/~tdi/pdf-resources/2008NECproposals2.pdf

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. A schedule of future presentations can be found on the SWTDI web site.

Read more by John Wiles

More than 90 percent of the new PV systems being installed throughout the United States are connected to the local utility with utility-interactive inverters (figure 1). These inverters range in size from about 250 watts (rated ac output) to about 250 kW. Multiple inverters may be used at a single location to provide even higher outputs. The connection requirements to the utility are established in various sections of the Code. Unfortunately, in many cases, these requirements are not fully understood or complied with. This article will concentrate on the requirements of the 2005 National Electrical Code Section 690.64, Point of Connection.

Figure 1. Utility-interactive inverter

This section of the Code allows the output of the inverter to be connected either on the supply (utility) side of the service disconnect or on the load (inverter) side of the service disconnect. Supply-side and load-side connections will be addressed for non-dwelling (commercial) installations first, followed by the requirements for dwellings.

Supply-Side Connections—690.64(A)

Figure 2. Supply-side interconnection diagram

Figure 3. PV inverter connected to service conductors

The inverter will normally be connected through a disconnect/overcurrent protection device before being connected to the service-entrance conductors between the meter and the service disconnect. This is equivalent to connecting a second service entrance to the building and the disconnect/overcurrent device (circuit breaker or fused disconnect) should be rated as service-entrance equipment. Elsewhere, Article 690 requires that the output circuit from the inverter be sized and protected at 125 percent of the rated continuous ac output of the inverter. Obviously, the existing service-entrance conductors must be at least this size in case they have to handle the full rated output of the PV system. Like other service conductors, the conductors between the disconnect/overcurrent device and the existing service-entrance conductors are not protected, and it is suggested that they be as large as the disconnect/overcurrent device terminals will accept. It is also suggested that these conductors be kept as short as possible and that they follow the general requirements for service-entrance conductors. Since the inverter output circuit is not a load or feeder circuit, I do not believe that the general tap rules are applicable.

Figure 4. Load-side interconnection diagrams

Of course, the connection could be made with the addition of a new meter, and this would be a complete second service entrance to the facility. Usually, this complicates the measuring and billing for energy used or produced where net metering is in effect and the system is associated with a building or structure. However, this complete separate service entrance is frequently used on the larger (100 kW and up) systems.

Since many utilities require a visible blade, lockable (open) disconnect between the output of the inverter and the utility point of connection, the disconnect described above and required by the NEC, may also serve as the utility-required disconnect. In some cases, the utility will not allow a fused disconnect, so a second, non-fused disconnect must be added.

Load-Side Connections—690.64(B)

The requirements of 690.64(B)(2) are complex. Here is what the section (without the exception) says with emphasis added by the author. "The sum of the ampere ratings of overcurrent devices in circuits supplying power to a busbar or conductor shall not exceed the rating of the busbar or conductor.”

The key word that many readers miss is the word "supplying.” In a load center or panelboard, the main circuit breaker supplies power to the internal busbars, as do any backfed circuit breakers supplying power from the PV inverters. The potential problem can be seen in figure 4. The load center is rated at 100 amps, the main circuit breaker can supply 100 amps to the busbars, and at the same time, the inverters may add another 30 amps to the busbars. If the loads were increased to 130 amps (for example, increased plug loads), no circuit breakers would trip, but the busbars in the center of the panel rated at 100 amps would be overloaded carrying 130 amps.

In the deliberations for the 2002 NEC, the determination was made that while placing the backfed PV circuit breakers at the bottom of the panel (as far away from the main circuit breaker as possible) would prevent overloading the panel busbars, it was not an acceptable long-term solution (even with placards). Placards get lost or damaged and people who may not be familiar with PV installations and interconnections move around circuit breakers in load centers after the initial installation.

In designing PV systems for commercial (non-dwelling) installations, an existing load center is usually considered. In many commercial installations, the size of the main circuit breaker in the load center has the same rating as the load center itself. Therefore no additional current may be supplied to the load center from backfed PV circuit breakers. In this case, one alternative is to go to a supply-side connection as outlined above. Another option is to remove the existing load center and replace it with a new, larger load center that has a main circuit breaker rated the same as the original main circuit breaker. The amount of PV current that can be backfed is the difference between the panel rating and the main circuit breaker.

In all cases the main circuit breaker, the load center, and any conductors (including feeders) carrying the output of a PV system must be sized for at least 1.25 x the rated output of the inverter (see 690.8 and 690.9). As will be seen below, the load center will usually be significantly larger than just the size required by the PV circuits.

In some installations, an oversized load center is being used with an adjustable main circuit breaker. Assuming that the main circuit breaker is set at a trip point below the rating of the panel, then the difference between the two ratings is the allowable current that can be backfed from the PV array.

It is usually not a good idea to replace an existing main circuit breaker with one that has a lower rating or to adjust an adjustable main to a lower trip point in an attempt to accommodate a PV system. The original installer of the system sized that main circuit breaker based on code-required load calculations, and if the circuit breaker rating were changed, it could result in nuisance trips or an overloaded circuit breaker, not to mention a Code violation.

Connecting PV Systems to a Commercial Feeder Panel or Subpanel

Figure 6. Multiple feeder panel connection diagram

For example, the backfed PV current at the top floor 100-amp feeder panel could require only a 15-amp circuit breaker. Section 690.64(B)(2) would normally require that the feeder panel be increased to 125 amps (next standard size) to accommodate the 15-amp backfed PV circuit breaker. However, when we get to the first 400-amp intermediate panel, the rating of the backfed circuit breaker carrying the PV currents is now 100 amps, not the 15-amp rating of the circuit breaker in the top floor panel. Meeting 690.64(B)(2) is more difficult with the larger backfed circuit breaker. Since this 100-amp circuit breaker is the only circuit breaker limiting backfed currents, its full 100-amp rating must be considered, not just the 15-amps that it is carrying at the present time. If only the 15 amps were considered, then at some future date the PV array might be expanded and the intermediate feeder panels could be overloaded since any backfed currents could reach 100 amps before a circuit breaker tripped in the intermediate 400-amp panel. At this point, the 400-amp panel would have to be increased to at least a 500-amp panel to accommodate the 100-amp backfed circuit breaker to meet 690.64(B)(2) requirements.

The same analysis applies to the main 1000-amp panel. The backfed circuit breaker is now rated at 400 amps and to meet Code, the main panel would have to be upgraded to at least a 1400-amp panel to keep the 1000-amp main circuit breaker. All of these difficulties could be avoided by doing a supply-side connection (at 15 amps). Of course, those 15-amp PV output circuit conductors would have to be routed from the roof to the main service panel, and the output voltage of the inverter would have to match the voltage of the service entrance. In some cases a transformer might be required to match the inverter output voltage to the service-entrance voltage.

In all cases, connecting a second service-entrance disconnect with a 15-amp rating (probably using a higher-rated disconnect) to an existing 1000-amp service must, of course, be accomplished in a safe, code-compliant manner using appropriate equipment.

Applying 690.64(B)(2) to the feeder conductors carrying backfed PV currents between the various panels indicates that they usually will not have to be enlarged in size when a PV system is added. There is no place on these circuits where the feeder can be overloaded (unless the PV output current exceeds the feeder rating) because there are no places between circuit breakers where loads can be connected that could be inadvertently increased as they could be inside a panel board as shown in figure 4.

Supply-Side Connections—690.64(B)(2) Dwelling Units

Now, let us examine the installation requirements for dwelling units. The exception for 690.64(B)(2) reads: "For a dwelling unit, the sum of the ampere ratings of the overcurrent devices shall not exceed 120 percent of the rating of the busbar or conductor.”

Now we can add PV backfed circuit breakers to the dwelling (residential) load center with some leeway before we have to start changing equipment. Normally, the main circuit breaker in a residential load center is rated the same as the residential load center. This exception allows the sum of the main circuit breaker plus the sum of any backfed PV circuit breakers to be 120 percent of the rating of the load center. This additional 20 percent allowance is made because, generally, residential circuits are more lightly loaded (due to demand factor calculations) than circuits in commercial buildings. Where the main circuit breakers and panels have the same rating, the exception to 690.64(B)(2) allows 20 amps of backfed PV circuit breakers to be added to a 100-amp panel and 40 amps to be added to a 200-amp panel. Although these numbers translate to a 3840-watt (ac inverter output) PV system on a 100-amp panel and a 7680-watt PV system on a 200-amp panel, some people want to install bigger PV systems and that means creative thinking must be used. These limits include the normal 80 percent maximum continuous operating-current limitations on the circuit breakers.

Many common PV inverters are rated at 2500 watts, 240 volts. The rated output current is 2500/240 = 10.4 amps. Using the code-required 1.25 multiplier (690.8) yields a circuit breaker requirement of 13 amps, which rounds up to 15 amps as the rating of the backfed circuit breaker. On a 100-amp panel, with a 100-amp main circuit breaker, only one of these inverters can be accommodated. On a 200-amp panel, only two of these inverters may be connected limiting the PV system to 5000 watts and not the maximum potential of 7680 watts.

However, figure 7 shows a code-compliant way to add three of these 2500-watt inverters to a 200-amp panel by using a subpanel. A subpanel is selected to accommodate the three 15-amp backfed circuit breakers, one from each of the 2500-watt inverters. The main circuit breaker on this dedicated (PV-only) subpanel has to have a minimum rating of the 3 x 10.4 x 1.25 = 39 amps (round up to a 40-amp circuit breaker). This would also be the rating of the backfed circuit breaker in the main panel and, at 40 amps, would meet the Code requirements for a 200-amp main panel. Of course, two 40-amp circuit breakers would not be needed, and only one at the main panel would suffice.

What should the size of the subpanel be? Using a formula derived from the Code requirements, we see that the minimum size of the panel would be about 75 amps, which would round up to a 100-amp, standard-sized panel.

3 * 15 + 40 <= 1.2 X, where X is the panel size required

Solving for X gives us

X >=(45 +40)/1.2 = 71 amps

For those desiring to install larger PV systems on residential services, the use of a supply-side connection as outlined above can meet the Code requirements.

Line Side of Ground Fault Equipment—690.64(B)(3)

The Code generally requires that all PV inverters be connected on the line side of any ground-fault protection equipment with an exception that allows backfed GFP equipment when the protected circuits have ground-fault protection from all sources.

However, tests (by SWTDI and Sandia National Laboratories) on the typical 5 milliamp GFCIs, 5 and 30 milliamp GFP circuit breakers have revealed that the internal sensing and trip circuits are destroyed when they are tripped while being backfed by a PV inverter. Conversations with manufacturers of the larger 100–800-amp ground-fault protection devices also indicate that these devices will be damaged when tripped while being backfed. Therefore, it is recommended that ground-fault protection equipment never be backfed. A proposal deleting the exception to 690.64(B)(3) is being developed for the 2008 NEC.

Markings Required—690.64(B)(4)

Figure 7. Three 2500-watt inverters on a 200-amp residential panel

Backfed Circuit Breakers—690.64(B)(5)

Although another section of the Code [408.36(F)] requires that backfed circuit breakers be clamped, changes to 690.64(B)(5) in the 2005 NEC no longer require them to be clamped when connected to the output of utility-interactive inverters. Section 690.3 indicates that the 690 requirements override the 408 requirement. A fine print note explains that circuit breakers suitable for backfeeding are not marked with "Line” and "Load” designations.

Battery-Backed-Up, Utility-Interactive Systems—More Complexity

The specifications in Underwriters Laboratories Standard 1741 require all utility-interactive inverters cease exporting power to the utility grid when the utility grid voltage and frequency deviate from very narrowly defined values. In blackout situations, the PV system and the standard utility-interactive inverter cease to operate and will not even supply power to local loads. In areas where utility blackouts are common or are anticipated to be common, some systems are being installed that have a battery-based energy storage system installed to provide local power during utility outages. The batteries are connected to a specially designed and listed utility-interactive inverter that, in the event of a utility outage, will disconnect from the utility system and provide a set of designated circuits with power from the PV system and the battery. All of these actions are done automatically with transfer devices built into the inverter. Figure 8 shows a simplified block diagram of a typical system. Several variations are possible.

Figure 8. Utility-interactive PV system with battery backup

In normal operation, the utility is present and the inverter acts as any other utility-interactive inverter. Any power from the PV system in excess of local load requirements is fed into the utility grid. When insufficient power is available from the PV system, the system buys power from the utility. The batteries are kept at full charge (float charged) by the utility power and are generally not used. However, when there is a utility outage, the inverter automatically senses this outage, ceases to export power to the utility, and feeds the backup load subpanel with ac power derived from the PV array and the batteries. The backup loads will receive ac power from the batteries and PV array to the extent that the energy draw does not exceed the capacity of the supply and storage systems.

Interfacing these systems with the utility grid and meeting 690.64(B)(2) requirements presents challenges for the system designer, the installer, and the inspector. Many of these inverters have internal transfer relays that are rated for 60-amps continuous duty, and that information is presented in the specifications. This specification leads designers and installers to size the backup load subpanel for 60 amps and to use a 60-amp backfed circuit breaker to connect the inverter to the main load center where the utility connection is made. The use of 60-amp circuit breakers in both positions provides for best use of the internal 60-amp relay and appears to allow maximum loads to be connected to the backup subpanel. Unfortunately, the use of 60-amp circuit breakers poses two problems and Code violations.

First, even though the inverter may be rated (and can be adjusted) to carry 60 amps, the external wiring and circuit breakers require the normal 80 percent continuous current derating. For a 60-amp continuous current, an 80-amp circuit breaker and conductors rated for at least 75 amps would be required. Another option, that will allow the 60-amp circuit breakers to be retained, would be to adjust the inverter to not allow more than 48 amps of continuous current to be handled by these circuits. That adjustment is commonly available on most of these inverters, although there is some question about who has access to the adjustment (qualified or unqualified people).

A second issue is the 690.64(B)(2) requirements discussed above. In a residential installation, a 60-amp backfed PV circuit breaker would dictate that at least a 300-amp main panel be used (60 amp PV circuit breaker + 300 amp main circuit breaker = 360 amps = 1.2 x 300 = 360). Residential load centers rated at 300-amps and above, while not impossible, are not common. In a commercial installation, the existing load center would have to be replaced with one having at least a 60 amp greater rating. In either case, a supply-side interconnection [690.64(A)] might be the more practical alternative. If the full 60 amps of the inverter are to be used, then, of course, 80-amp circuit breakers and 75-amp conductors should be used.

To further complicate the system design, many of these systems have an external inverter-bypass switch that is used if the inverter fails. This bypass switch, usually consisting of a pair of interlocked circuit breakers, is used to connect the back up subpanel directly to the main panel when the inverter fails. These circuit breakers are typically also rated at 60 amps and installed in a small 60-amp, three-position (three-phase) load center. Obviously neither the circuit breakers nor the load center are rated to carry 60-amps continuously. The use of a larger load center and interlocked 80-amp circuit breakers would allow a full 60-amp rating for the inverter-bypass switch.

Summary

The requirements of NEC Section 690.64 can be met in nearly all installations. While the requirements, at first glance, are somewhat complex and sometimes overlooked, attention to these details in the design, installation, and inspection of these systems should help to ensure a safe, durable, and code-compliant installation.

For Additional Information

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

A PV Systems Inspector/Installer Checklist will be sent via e-mail to those requesting it. A color 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: (http://www.nmsu.edu/~tdi/roswell-8opt.pdf.) A black and white printed copy will be mailed to those requesting a copy via e-mail if a shipping address is included. The Southwest Technology Development web sitehttp://www.nmsu.edu/~tdimaintains all copies of the previous "Perspectives on PV” articles. Copies of "”Code Corner”" written by the author and published in Home Power Magazine over the last 10 years are also available on this web site.

Draft proposals for the 2008 NEC being developed by the PV Industry Forum may be downloaded from this web site: http://www.nmsu.edu/~tdi/pdf-resources/2008NECproposals2.pdf

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. A schedule of future presentations can be found on the SWTDI web site.

Read more by John Wiles

Grounding

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

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: (https://www.ul.com/regulators/ahjprod.cfm). Others can file a report to UL at this site: (https://www.ul.com/consumers/conproddb.cfm). I can supply a PDF of the original article, if needed.

Germany Does It Right

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. E-mail:jwiles@nmsu.edu; 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 (http://www.nmsu.edu/~tdi/roswell-8opt.pdf.) The Southwest Technology Development web site (http://www.nmsu.edu/~tdi) 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

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).

Disconnects

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).

Grounding

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).

Disconnects

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).

Summary

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: jwiles@nmsu.edu. 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 (http://www.nmsu.edu/~tdi/roswell-8opt.pdf.) The Southwest Technology Development web site (http://www.nmsu.edu/~tdi) 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

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.

Warning
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.

Summary

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: jwiles@nmsu.edu 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 (http://www.nmsu.edu/~tdi) 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

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?

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.

Solutions

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: jwiles@nmsu.edu, 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 (http://nmsu.edu/tdi) 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

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

Photo 1. Framed PV modules

 

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

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: jwiles@nmsu.edu 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 (http://www.nmsu.edu/~tdi) 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

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

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).

Summary

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: jwiles@nmsu.edu 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 (http://www.nmsu.edu/~tdi) 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

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.

Read more by John Wiles

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.

CONDUCTORS FOR PV MODULES

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).

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.

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

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.

CONDUCTORS FOR BATTERIES

Photo 7. Battery bank

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: jwiles@nmsu.edu 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 (http://www.nmsu.edu/~tdi) 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.

ENVIRONMENTAL CONDITIONS

Sunlight

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.

Temperatures

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.

Read more by John Wiles

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.

Read more by John Wiles

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

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.

Stand-Alone

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

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

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

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 www.eren.doe.gov/millionroofs.

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

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

Code Requirements

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.

Wiring

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

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

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

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

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.

Disconnects

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.

Installations

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).

Summary

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 atwww.sandia.gov/PV.

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 http://www.homepower.com/and 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.

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