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.

The requirements pertaining to the connection of utility-interactive photovoltaic (PV) power systems to the load side of the main service disconnecting means have been with us for years. In the earlier codes, the driver was 690.64(B) and now those requirements are found in 705.12(D).

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

Most inspectors don’t have or have not read the UL Standards related to PV systems, because the standards are expensive and do not relate directly to the job of ensuring that listed PV modules and inverters are installed in a manner that meets the requirements of the National Electrical Code (NEC–NFPA 70). However, the requirements in the standards affect what the instruction manuals must say and those instructions guide the PV installer because NEC Section 110.3(B) requires that the instructions and labels on listed products must be followed. On May 8th of 2012, Underwriters Laboratories (UL) released a revised version of UL Standard 1703, the "Standard for Safety for Flat Plate Photovoltaic Modules and Panels.” This UL standard is also an American National Standard Institute (ANSI) approved as ANSI/UL 1703-2012.

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

Microinverters and AC PV modules are becoming very common in residential and small commercial PV systems. See photos 1 and 2. They have even been used in PV systems rated at 60 kW and above. They have some common features. For example, microinverters and AC PV modules have similar ac output characteristics, connections and code requirements. However, they are different from the typical PV string inverters that use multiple modules connected in series and have dc voltages in the 200–600 volt range. The microinverters and AC PV modules typically operate with just one PV module and the dc voltages are less than 100 volts.

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

The following questions and answers result from some of the more common situations that many inspectors face throughout their working day when seeing a new PV installation or reviewing a set of plans for a PV system. The questions are simplified versions of questions I receive in e-mails and from questioned plan sets as well as sometimes long, involved phone calls.

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