Products & Equipment : Inverters

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[Fort Collins, CO] In 2012, REFUsol brought one of the early UL-listed 3-phase string inverter product lines to the US market. US-based Advanced Energy acquired REFUsol’s US product line in 2013, before exiting the inverter market altogether in 2015. REFUsol is currently a REFU Elektronik GmbH division under parent company German Prettl Group. Prettl Energy North America operates a US sales office in Fort Collins, Colorado. Two REFUsol 3-phase inverter models are available in the US, the 24 kW 24K-UL-USA and the 48 kW 48K-UL-USA. Both models feature natural convection cooling, 3-phase 480 Vac output and a maximum dc voltage of 1,000 Vdc.

Prettl Energy North America / 970.231.6695 / /

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[Fremont, CA] SolarEdge has announced that it is now shipping two models of its single-phase HD-Wave string inverter, the 3 kW SE3000H-US and the 3.8 kW SE3800H-US, for US-based projects. SolarEdge will begin shipping three additional HD-Wave models,  the 5 kW SE5000H-US, 6 kW SE6000H-US and 7.6 kW SE7600H-US, in the near future. The units in the HD-Wave product line weigh in at a remarkable 25.5 pounds (safety switch included) and have a weighted CEC efficiency of 99%. Designed for compatibility with SolarEdge’s module-level power optimizers, the HD-Wave inverters feature automatic optimizer ID and string assignment detection. The inverters meet NEC 2014 and NEC 2017 rapid-shutdown requirements with automatic shutdown upon ac grid disconnection. SolarEdge offers an optional revenue-grade meter with ±0.5% accuracy. The HD-Wave inverters carry a 12-year warranty. Extended warranties of 12–20 years and 12–25 years are currently available for $120 and $192, respectively.

SolarEdge / 510.498.3200 /

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The 2014 and 2017 editions of the National Electrical Code provide solar companies with more interconnection options than previous Code editions did. In this article, I offer an overview of the Code requirements and allowances for interconnecting parallel power production sources, such as PV or energy storage systems, to premises wiring supplied by a utility or other primary on-site electric power sources. My goal is to help solar company personnel identify the most appropriate point of connection (POC), which is specific to both the system and the site.

To cover the maximum number of interconnection scenarios in as much detail as possible, I have chosen to focus specifically on distributed generation applications, where parallel power production sources interconnect at utilization voltage levels in properties with on-site loads. I assume that readers have a working knowledge of and access to the NEC, which contains many important definitions and references. In the interest of brevity, I italicize on first use those terms that the NEC defines; if you are unfamiliar with any italicized terms in this article, especially those in Figure 1, please refer to Article 100, “Definitions,” or to the NEC index. I provide Code references in square brackets throughout the article, indicating the 2014 or 2017 revision cycle where relevant.

POC Options

NEC Article 705 details the basic safety requirements for interconnected electric power production sources. Though distributed PV systems are a common parallel power production source, other sources include on-site generators, fuel cells, wind electric systems and some energy storage systems. Regardless of the power source, qualified persons must install these systems [2014-705.6; 2017-705.8] using approved equipment, such as listed interactive inverters certified to UL 1741 [2014-705.4; 2017-705.6].

The first step when planning a safe interconnection is to document relevant PV system equipment ratings. The essential data for Code compliance include utility-interactive inverter output circuit ratings [690.8(A)(3), 705.60(A)(2)] and the associated overcurrent protection device (OCPD) ratings [690.9(B), 705.60(B)]. Where multiple inverters interconnect to a single POC, it is useful to record individual inverter output circuit currents as well as the sum of these currents wherever you combine inverter outputs.

The next step is to assess the configuration and condition of the existing premises wiring, paying special attention to any equipment or locations that provide potential interconnection opportunities. As shown in Figure 2, the Code allows for two basic types of interconnections: supply-side connections [705.12(A)] and load-side connections [2014-705.12(C); 2017-705.12(B)]. Note that the delineation point between supply- or load-side connections is the disconnecting means for the utility-supplied service; this is an important distinction, as feeders rather than services supply some buildings or structures.

As illustrated in Figure 2, multiple potential interconnection opportunities exist on both the load side and the supply side of the service disconnecting means. Generally speaking, cost and complexity increase as the POC moves from left to right. I have generally organized the following scenarios accordingly, from the most common and least complex options to those that are less common and more complex. In most cases, I provide a formula that you can use to evaluate the Code compliance of different interconnection methods using existing equipment. You can easily adapt these formulas to evaluate potential equipment modifications or upgrades, while that is beyond the scope of this article.

Though I focus here on a few key metrics—most notably, supply overcurrent device ratings, panel busbar ratings and feeder conductor sizes—a thorough site survey is a prerequisite for identifying the optimal POC. Ideally, this survey identifies the locations and ratings of the utility transformer, revenue meter, service entrance conductors, main service panel, service disconnecting means, grounding electrode, subpanels, supply breaker ratings, on-site power production sources and even load breaker ratings. In addition to photographing and taking notes on the general as-built conditions, be sure to take pictures of any electrical equipment labels, as these data will invariably prove essential later.

Note that often a manufacturer-applied label on the panelboard identifies the busbar or mains rating for existing equipment. In some cases, however, you may need to find the original equipment documentation to determine this value. If you are unable to document a busbar rating conclusively, the generally accepted practice is to use the rating of the associated OCPD.

Load-Side Connections

The 2014 and 2017 editions of the NEC provide detailed requirements for making load-side connections to busbars in panelboards or to load-side conductors [2014-705.12(D)(2); 2017-705.12(B)(2)]. The additional load-side connection guidelines, compared to those in earlier Code editions, are beneficial for system designers and AHJs. The most significant change, however, is the directive to use 125% of the inverter output circuit current, rather than the interactive inverter breaker rating, for load-side ampacity calculations.

All else being equal, the simplest and most cost-effective interactive inverter interconnection is to connect to a panelboard busbar by adding a circuit breaker. In addition to providing a Code-compliant POC, this new breaker also provides overcurrent protection for the inverter output circuit and often serves as the PV or interactive system disconnect. The NEC details five different methods or scenarios for interconnecting an electric power source to a busbar, each of which is potentially useful in a subset of real-world situations. Note that while the following examples assume the use of circuit breakers, the Code also allows for the use of fusible disconnecting means.

Power sources do not exceed busbar rating. Where applicable, this is likely the easiest and most cost-effective POC. As long as the busbar rating is greater than or equal to that of the primary power source (the busbar OCPD rating) plus the sum of the parallel power sources (125% of the inverter output circuit currents), the Code does not limit the locations or number of sources or loads connected to a panelboard busbar [2014-705.12(D)(2)(3)(a); 2017-705.12(B)(2)(3)(a)]. Since any inverter OCPD location is acceptable, the Code does not require a warning label adjacent to a backfed breaker in this scenario.

Though opportunities to use the busbar interconnection method shown in Figure 3 are relatively uncommon, they do exist. For example, a site evaluation might identify a residential panelboard with a 225 A–rated busbar but a 200 A main breaker, or a commercial main distribution panel with a busbar rating higher than its main OCPD. In this type of scenario, you can use Equation 1 to confirm that a proposed interconnection is Code compliant:

Busbar ≥ Supply OCPD + (Inverter Current x 125%) [1]

120% allowance. This is the busbar interconnection method familiar to most solar professionals. Since 1987, the Code has included some version of “the 120% rule,” which allows primary and parallel power sources to exceed a panelboard’s busbar rating under certain circumstances. This allowance originally applied only in residential applications, where load diversity prevents overload conditions. Eventually, the Code-Making Panel was able to extend the 120% allowance to commercial and industrial applications by requiring that the primary power source (utility) and parallel power sources (interactive inverters) connect to opposite ends of the busbar, as shown in Figure 4.

Whereas earlier Code editions used the inverter OCPD rating in calculations related to the 120% allowance, calculations under NEC 2014 and NEC 2017 are based on 125% of the inverter output circuit current [2014-705.12(D)(3)(b); 2017-705.12(B)(2)(3)(b)]. You can use Equation 2 to confirm that a proposed interconnection complies with the 120% allowance:

Busbar ≥ (Supply OCPD + (Inverter Current x 125%)) ÷ 120% [2]

Since the physical location of the inverter OCPD prevents any potential overload conditions, the Code requires a warning label to alert someone not to inadvertently move this device in the future:



Limit load and supply OCPDs. This calculation method is unique insofar as it ignores the rating of the overcurrent device protecting the busbar and instead evaluates the total rating of all the applied load and supply OCPDs. In this scenario, a proposed POC is Code compliant as long as the panelboard busbar rating is greater than or equal to the sum of the attached OCPDs, regardless of whether these connect to loads or inverters [2014-705.12(D)(3)(c); 2017-705.12(B)(2)(3)(c)]. Since an overload condition cannot exist in this scenario, the Code does not limit the number or locations of load or inverter breakers, as illustrated in Figure 5. In this scenario, you can use Equation 3 to confirm Code compliance:

Busbar ≥ Load OCPDs + Inverter OCPDs [3]

This new method of interconnection is particularly advantageous when you are adding a new panelboard to aggregate multiple inverter output circuits, as might be the case on a commercial project deployed with 3-phase string inverters or a residential project deployed with microinverters. Since this method accommodates load breakers, you are free to add breakers to an inverter aggregation panel to supply power to monitoring equipment or equipment servicing receptacles. You could also use this method to connect an interactive system to a lightly loaded subpanel. Note that you must include a warning label to ensure that the installation remains Code compliant in the future:



Center-fed panels in dwellings. During the 2017 cycle of revisions, the Code-Making Panel introduced a new busbar interconnection method that applies specifically to center-fed panelboards in dwellings. With a center-fed panelboard, the main breaker is located in the middle of the busbar, rather than at the top. This center-fed configuration makes it impossible to locate the utility and inverter supplies at opposite ends of the busbar as required to comply with the standard 120% allowance. Due to the diversity factor that applies to residential loads, the Code-Making Panel determined that it is safe to apply the 120% allowance (see Equation 2, to center-fed panelboards in dwellings, provided that the inverter POC is located at only one end of the busbar [2014-TIA 14-12; 2017-705.12(B)(2)(3)(d)]. In Figure 6, for example, you could connect a parallel power source to either the top or the bottom of the busbar, but not to both ends.

Solar companies that encounter center-fed panelboards will welcome this new interconnection method. Since center-fed panelboards are relatively common in California, it is not uncommon for solar customers there to incur $2,000–$3,000 service upgrades in order for system integrators to interconnect even small residential PV systems. The new 120% allowance for center-fed panelboards in dwellings eliminates these expenses where they are otherwise unnecessary. In August 2016, the National Fire Protection Association issued a rare Tentative Interim Amendment (TIA), 14-12, which retroactively adds the center-fed panel allowance to NEC 2014 as 705.12(D)(2)(3)(e).

It is a good idea to speak to your AHJ prior to making this type of connection under NEC 2014. Though this is an official change to the 2014 Code edition, the revised language will not appear in hard copy of the Code, which could cause some confusion. Code does not specifically require a warning label, but it is advisable to add such a label alongside the inverter breaker to ensure that the installation remains compliant in the future. This warning label might read:



Multiple-ampacity busbars. Panelboards with multiple-ampacity busbars are primarily found in industrial applications and do not fit neatly into any of the previous categories. Since there is no practical limit to as-built conditions, it is necessary to evaluate each situation individually to ensure that a proposed POC is safe. To make a Code-compliant connection to a multiple-ampacity busbar [2014-705.12(D)(3)(d); 2017-705.12(B)(2)(3)(e)], a supervising engineer must evaluate busbar loading and available fault currents.

Although connections to conductors are less common than connections to busbars, the NEC allows them under certain conditions. This method of interconnection is perhaps most common when a suitably sized feeder is significantly closer to or more accessible from the proposed inverter location than a suitable panelboard is. In such a scenario, connecting to the feeder conductor results in meaningful savings.

When evaluating a conductor’s suitability as a POC, several general rules apply. Where you are making an inverter connection to a feeder or tap, the ampacity of the conductor must be equal to or greater than 125% of the inverter output circuit current [705.60]. Inverter output circuit conductors must be protected in accordance with Article 240 [705.65], and the number and location of OCPDs must provide protection from all sources [705.30]. Any feeder or feeder tap conductor supplying loads must have adequate ampacity to supply the loads [215.2(A)(1)]. Conductor ampacities must account for actual conditions of use, including ambient temperature and conduit fill [310.15]. Note that the formulas in this section will determine the minimum conductor ampacity before the applicable conditions of use.

Provided that the system meets these general criteria, the Code allows for direct connections to feeders or indirect connections via tap conductors [240.2].

Connections to feeders. Solar professionals routinely connect PV systems to the end of a feeder, opposite the primary source OCPD. The Code also allows for a connection to other locations in a feeder, provided that the conductor on the load side of the inverter output is protected [2014-705.12(D)(2)(1); 2017-705.12(B)(2)(1)]. System integrators have two options for protecting this portion of the feeder.

Option 1: Make sure that power sources do not exceed conductor ampacity. The first protection option is based on the logic that the downstream conductor is protected as long as it is rated to carry power from all sources. In other words, the connection is compliant as long as the sum of the primary power source (the main OCPD rating) and the interactive power source (125% of the inverter output circuit current) does not exceed the ampacity of the feeder, specifically between the POC and the loads [2014-705.12(D)(2)(1)(a); 2017-705.12(B)(2)(1)(a)]. Figure 7 illustrates this schematically.

Note that this conductor connection method effectively assumes two different feeder ampacities. The ampacity of feeder A, which is upstream from the POC and protected by the primary supply breaker, needs to be greater than 125% of the inverter output circuit currents. Since there are loads at the other end of the feeder, however, the ampacity of feeder B and any downstream busbars must account for both the primary and the parallel power sources. You can use Equations 4a and 4b to verify Code compliance in this scenario:

Feeder A ≥ Inverter Current x 125% [4a]

Feeder B ≥ Supply OCPD + (Inverter Current x 125%) [4b]

Opportunities to take advantage of this feeder connection option are relatively few and far between, simply because it is uncommon to come across oversized conductors and busbars in the field. Generally speaking, it is cost prohibitive to upgrade the downstream feeder conductor unless its length is short and the downstream panelboard already has an oversized busbar.

Option 2: Add an OCPD on the load side of the feeder. The second, and generally more practical, option uses an overcurrent device to protect the downstream feeder. In this scenario, the POC is compliant so long as the ampacity of the feeder is greater than or equal to the OCPD rating on the load side of the inverter connection [2014-705.12(D)(2)(1)(b); 2017-705.12(B)(2)(1)(b)]. Figure 8 shows a connection with a breaker added to protect the downstream feeder and busbar.

Note that the size of the OCPD on the load side of the inverter POC must also take the downstream loads into account. One way to install an OCPD in the feeder is to add a new panelboard at the POC to enclose the inverter breaker and the load breaker. Alternative methods could use wireway with fused disconnects. Either way, this interconnection method likely involves splicing and extending the feeder with the possible addition of tap conductors, which are subject to unique Code requirements (discussed next). You can use Equations 5a and 5b to ensure that this type of connection to a feeder conductor is Code compliant:

Feeder Ampacity ≥ Inverter Current x 125% [5a]

Load-Side Breaker ≤ Feeder Ampacity [5b]

Connections involving tap conductors. The ability to connect to feeders using tap conductors offers solar professionals additional flexibility when optimizing site-specific interconnections. The Code provides multiple allowances, based on tap length or location, for tapping feeder conductors without overcurrent protection at the tap [240.21(B)]. New language in Article 705 clarifies how these general tap rules apply where inverter output connections use tap conductors. Specifically, the Code requires that you base the OCPD rating used to determine the ampacity of tap conductors per 240.21(B) on the sum of the source OCPD and 125% of the inverter output circuit current [2014-705.12(D)(2)(2); 2017-705.12(B)(2)(2)].

The following examples illustrate how to apply tap conductor rules where you are using taps for downstream loads, inverters or both. These specific examples assume that the tap conductors are not longer than 25 feet and that some portion of the tap conductors is located indoors. Moreover, some general rules apply that merit reviewing. You are allowed to tap feeder conductors but not other tap conductors [240.21(B)]. You are generally not allowed to tap branch circuits [210.19]. You are not allowed to tap inverter output circuits [240.4(E), 705.12(D)(1)]. You must size any conductors serving loads, including taps, to supply the load [Article 220, Part III]. You must provide overcurrent protection for panelboards connected to tap conductors [408.36].

Example 1: New tap for loads. This option is worth investigating if you want to connect to a feeder but avoid upsizing the downstream feeder and busbar. Instead of adding overcurrent protection at the POC, as illustrated previously, you may prefer to add a circuit breaker or fused disconnect directly ahead of the busbar serving the downstream loads. This approach, shown schematically in Figure 9, essentially converts the downstream portion of the existing feeder, between the inverter connection and the loads, into a tap conductor.

If the tap does not exceed 25 feet and meets Code-mandated minimum size and installation requirements, you can use Equations 6a and 6b to verify that the connection is compliant:

Feeder Ampacity ≥ Inverter Current x 125% [6a]

Load Tap Ampacity ≥ (Supply OCPD + (Inverter Current x 125%)) x 33% [6b]

Example 2: New tap for inverters. This option comes in handy where you would like to locate the inverter overcurrent device some distance away from the feeder, perhaps to make it readily accessible. In this scenario, illustrated in Figure 10, the tap conductors serve the interactive system only.

Where the tap does not exceed 25 feet and meets Code-mandated minimum size and installation requirements, you can make a compliant connection by sizing the tap conductor to the worst-case scenario as determined by Equations 7a and 7b:

Inverter Tap Ampacity ≥ Inverter Current x 125% [7a]

Inverter Tap Ampacity ≥ (Supply OCPD + (Inverter Current x 125%)) x 33% [7b]

The larger of these values determines the size of the inverter tap conductor.

Example 3: New taps for both inverters and loads. This option is worth investigating where an existing feeder is available to serve both a new inverter system and a new load, but you would like to locate these at some distance away from the end of the feeder and avoid adding a panelboard. The strategy here is to make two Code-compliant taps, where one feeder tap conductor serves the inverter and the other feeder tap conductor serves the load. Figure 11 illustrates this two-tap scenario.

To ensure that the connections are Code compliant, size the inverter feeder tap conductor according to the larger value as determined by Equation 7a and 7b, and size the load feeder tap conductor according to Equation 6b.

Supply-Side Connections

The NEC language pertaining to supply-side connections is concise and not overly prescriptive. In short, the Code allows for connections on the supply side of the service disconnecting means provided that the sum of the parallel power source overcurrent devices does not exceed the rating of the service [705.12(A)]. A definition in 705.2 clarifies that power production equipment does not include the utility-supplied service, but rather consists of other sources of electricity, such as generators and interactive systems.

When planning an interconnection on the supply side of the service entrance disconnecting means, it is important to establish or verify equipment ownership and control. Technically, the service point (see Figure 1) is the demarcation point between the serving utility and the premises wiring, per the definition in Article 100. In practice, the location of this demarcation point varies depending on the utility’s policies and the type or conditions of the service. Furthermore, ownership and control do not always go hand in hand. For example, the utility generally controls metering equipment even when customers own some or all of this hardware. In most cases, AHJs want to verify that you are making the proposed supply-side connection in a manner consistent with utility requirements applying to services. As such, it is a good idea to start the planning process by obtaining a copy of the serving utility’s design standards.

Connections to service entrance conductors. The Code allows for splicing or tapping service entrance conductors [230.46] and connecting power production equipment on the supply side of a service disconnect [230.82(6)]. In some cases, you may be able to make a connection inside the existing service equipment; in other cases, the AHJ or utility design criteria may require that you add a new enclosure to make a connection.

While the Code does not explicitly state that you must treat the wiring on the line side of the inverter disconnect as a set of service entrance conductors [see 230.40, Exception 5], it is generally considered a best practice to install this wiring in accordance with the long-established Code requirements pertaining to service conductors [Articles 230, 250.92, and so forth]. This is consistent with the revised language in NEC 2017 [690.13(C)]: “If the PV system is connected to the supply side of the service disconnecting means as permitted in 230.82(6), the PV system disconnecting means shall be listed as suitable for use as service equipment.” Understand, however, that a new disconnect for parallel power production equipment does not meet the Code definition of a service disconnecting means [Article 100]; therefore, the inverter disconnect does not count as one of the six switches allowed per set of service entrance conductors [230.71(A)].

As part of the 2014 revision cycle, the Code-Making Panel added a new section limiting the length of unprotected conductors in a supply-side connection. Specifically, it now requires overcurrent protection within 10 feet of the POC [705.31]. An exception allows for the use of cable limiters at the POC if you cannot locate overcurrent protection for power production source conductors within 10 feet of the connection point.

Connections to Other Equipment

The preceding examples intentionally assume a relatively generic set of circumstances, as my goal is to provide high-level guidance for making Code-compliant connections. In the real world, you will encounter a great deal of variety in terms of service types, equipment configurations and as-built conditions. Some facilities will provide multiple opportunities for a safe connection; others will present many obstacles. In some cases, you will need to upgrade the service or some of the existing electrical equipment to connect interactive systems in a way that satisfies the AHJ and the NEC. Though it is beyond the scope of this article to consider all of the methods and opportunities to connect at existing equipment, some common scenarios and challenges merit discussion.

Connections to subpanels. The NEC does not restrict your ability to connect to a panelboard based on its location or hierarchy in the premises wiring. Any panelboard fed by feeder conductors is a potential POC, provided that you evaluate any busbars or feeders between the primary power source and the inverter interconnection according to the calculation methods detailed previously. Pay special attention to breaker location and labeling requirements, as these also apply to upstream equipment. There should no longer be any confusion about what ratings to use in upstream calculations, since the default value is now 125% of the inverter output circuit current rather than the backfed breaker rating.

Adding lugs to busbars. The NEC does not specify how to make mechanical connections to busbars. Where it is not possible or practical to add a circuit breaker for this purpose, you may be able to add lugs to accommodate an inverter connection. When adding lugs, you must do so in a way that does not violate the product listing.

To add lugs, you do not simply make a mechanical connection wherever there is room to do so. Drilling a hole in a busbar to accommodate a mechanical connection removes conductive material. This type of field modification could violate the product listing or result in unintended consequences, both of which increase liability exposure. Moreover, many AHJs will not approve a modification that the manufacturer does not specifically allow or that was not designed under engineering supervision.

Some manufacturers identify approved locations and methods for adding lugs and may even provide hardware for this purpose. Feed-through lugs are perhaps the most common example of an opportunity to add lugs to a busbar using manufacturer-provided hardware. At sites with larger, custom-built panelboards, it may prove more challenging to add lugs to a busbar. Engineering supervision and field labeling may be required where the equipment vendor does not have instructions and recognized hardware kits for this purpose.

Adding lugs to other equipment. On either side of the service disconnecting means, it may be possible to add lugs or studs to existing equipment, including disconnects, meters, meter sockets, connector blocks and so forth. Many of these options are highly site specific, based on the equipment and jurisdiction. Relatively recently, equipment manufacturers and even utilities have begun to offer meter socket adapters or solar-ready panelboards specifically designed to provide the capacity and termination points needed to make a Code-compliant connection. While equipment upgrades are unavoidable in some cases, an increasing number of vendors are developing listed solutions for making a Code-compliant interconnection at existing equipment.

Adequacy of existing equipment. When planning interconnections, it is important to evaluate the adequacy of the existing equipment or service. As-built conditions could prove unsuitable for an interconnection where equipment is damaged, perhaps due to a previous overload condition, or where it is not rated for the environment. You may need to repair or replace equipment due to poor workmanship. In some cases, you may encounter equipment that is subject to a recall or is generally known to be faulty.

Most AHJs grandfather existing conditions to some extent, meaning that you do not have to upgrade everything to the most recent Code requirements to perform a limited scope of work, such as adding a power production source. However, a grandfather clause does not automatically extend to existing equipment that you plan to modify or use as a POC. Especially in older dwellings, it is not uncommon to encounter legacy wiring methods or electrical equipment that AHJs will ask you to upgrade before making an interconnection.

Also, keep in mind that the Code addresses minimum safety requirements only. Once you touch the existing equipment, you own it—certainly as far as the customer is concerned. Every veteran contractor is familiar with this complaint: “Everything was working fine before your crew worked on it.” If you spot a potential reliability issue with the existing equipment, you should either create a budget to fix it, or bring it to the customer’s attention and have that customer sign off on leaving it as is.


Jason Fisher / Solar City / Charlottesville, VA /

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Updated for 2017, SolarPro’s string-inverter dataset includes 158 single- and 3-phase string inverter models from 16 manufacturers. A Nationally Recognized Testing Laboratory (NRTL) has listed all the products in the table to the UL 1741 standard. All of the manufacturers represented maintain one or more established US sales and technical support offices.

The technical evolution of string inverters has been fascinating to watch in recent years. The gains in efficiency, design flexibility and installability have been nothing short of impressive. A few years back, not many integrators would have imagined a 7.6 kWac single-phase inverter with a CEC efficiency of 99% that weighs 25 pounds, or a 125 kWac 3-phase string inverter certified for 1,500 Vdc applications that, at 143 pounds, is light enough for two installers to lift and mount. Today, the range of applications for string inverters stretches from small residential systems to multimegawatt PV plants.


Joe Schwartz / SolarPro  / Ashland, OR /


ABB / 877.261.1374 /

Chint Power Systems / 855.584.7168 /

Delta / 510.668.5100 /

Fronius USA / 877.376.6487 /

Ginlong Solis / 866.438.8408 /

Growatt / 818.800.9177 /

HiQ Solar / 408.970.9580 /

Huawei / 214.919.6000 /

Ingeteam / 408.524.2929 /

KACO new energy / 415.931.2046 /

Pika Energy / 207.887.9105 /

Schneider Electric / 888.778.2733 /

SMA America / 916.625.0870 /

SolarEdge Technologies / 877.360.5292 /

Sungrow USA / 510.656.1259 /

Yaskawa–Solectria Solar / 978.683.9700 /

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SolarPro’s 2016 utility-scale central inverter specification dataset provides PV plant designers with a high-level comparison of the electrical and mechanical specifications for inverter models that are well suited for centralized, large solar applications. The products included in the following table have an ac output capacity of 250 kW at 50°C or greater, and their makers currently offer and support them in the US market (with a few exceptions).

While many US solar developers now consider decentralized designs that utilize high-capacity 3-phase string inverters for projects up to 10 MW or even larger, central inverter platforms are still currently the standard for most utility-scale projects over 10 MW in the US. As a result, we continue to see the rapid advancement of central inverters and platforms that integrate them into blocks that can process 2 MW or more of PV power.

The aggregated specifications presented here cover 58 central inverter models from 10 manufacturers. Most of the included solutions are listed to the UL 1741 standard. In addition, 19 currently available models from six manufacturers (ABB, Ingeteam, Power Electronics, SMA America, Sungrow and TMEIC) are listed for deployment in 1,500 Vdc systems, which is becoming the new standard for many utility-scale PV plants.

Joe Schwartz / SolarPro / Ashland, OR /


ABB / 877.261.1374 /

Eaton / 855.386.7657 /

Ingeteam / 855.821.7190 /

KACO new energy / 210.446.4238 /

Power Electronics / 602.354.4890 /

Schneider Electric / 888.778.2733 /

SMA America / 916.625.0870 /

Sungrow USA / 510.656.1259 /

TMEIC / 540.283.2000 /

Yaskawa–Solectria Solar / 978.683.9700 /

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The fire service wants module-level rapid shutdown. But is this commercially viable in nonresidential applications? And will this reduce hazards within the array?

While it has proven relatively easy for solar companies to comply with the rapid-shutdown requirements in NEC 2014, many in the solar industry are justifiably concerned about the implications of the revised and more restrictive rapid-shutdown requirements adopted as part of the 2017 cycle of revisions. Specifically, the International Association for Fire Fighters introduced language that seeks to mandate module-level rapid shutdown for PV systems on buildings. This would, of course, require module-level disconnecting devices for all building-mounted PV modules, including those on commercial rooftops, which is a daunting paradigm shift in terms of both system reliability and economic viability.

In this article, I explore different perspectives on the prospects of deploying module-level power electronics (MLPE) in commercial rooftop applications in light of these evolving rapid-shutdown requirements. Generally speaking, there are two sides to the debate. On one hand, fire service representatives and some MLPE vendors contend that module-level rapid shutdown will improve safety for firefighters and first responders. On the other, the Solar Energy Industries Association (SEIA) and some of its most prominent constituents—including  SolarCity, SunPower and Sunrun—point out that there is no scientific basis for using module-level rapid shutdown to protect emergency responders and that doing so could have unintended negative consequences. Staking out a middle ground, UL promises to take a science-based approach as it develops an NEC 2017 rapid-shutdown PV array product safety standard.

Evolving Rapid-Shutdown Requirements

Introduced as part of the 2014 cycle of revisions and significantly revised for the 2017 Code, the goal of NEC 690.12 is to reduce shock hazards for emergency responders.

2014 version. Under NEC 2014, rapid shutdown of PV system circuits on buildings is accomplished by limiting the potential of controlled conductors to 30 V or less beyond 5 or 10 feet of the array, depending on whether the conductors enter the building or travel along its exterior. Markets have generally shrugged off this Code change and continued apace. Certainly, states that adopted NEC 2014 early, such as Massachusetts, experienced some growing pains associated with rapid-shutdown compliance and enforcement. However, system designers were quick to identify and implement a standard set of cost-effective and application-specific approaches to rapid shutdown.

Where the 2014 version of rapid shutdown becomes the law of the land, residential markets shift away from string inverter–based designs in favor of MLPE-based designs. Arguably, the design response is even simpler in commercial applications. Many commercial project designers started switching from central inverter–based to 3-phase string inverter–based designs to meet the dc arc-fault protection requirements in NEC 2011. To ensure that these distributed inverter designs comply with the 2014 version of rapid shutdown, designers simply need to locate these 3-phase string inverters on the roof within 10 feet of the array.

This is good news for installation companies in the largest US solar market, as well as for the North American solar market in general. Though it will throw some AHJs and inspectors for a loop when California adopts NEC 2014 on January 1, 2017, experiences in other states have shown that this level of rapid-shutdown compliance is relatively straightforward and not overly disruptive to business as usual. (For more about the intent and design implications of 2014 rapid shutdown, see Bill Brooks’ article “Rapid Shutdown for PV Systems,” SolarPro, January/February 2015.)

2017 version. Under NEC 2017, the rapid-shutdown language in section 690.12 expands from a mere 133 words to more than 1,100. Many of the people who previously bemoaned the lack of specificity in NEC 2014 may find themselves longing for those halcyon days of yore. Without a doubt, the number one complaint about 2017 rapid shutdown is that it is overly prescriptive.

From a design point of view, there are two main differences between the versions of rapid shutdown. First, the 2017 Code shrinks the “not more than 30 V” zone on the roof from a maximum of 10 feet to not more than 1 foot from the array in every direction, as shown in Figure 1. Second, whereas 2014 rapid-shutdown requirements apply to conductors outside the array boundary only, the 2017 version has requirements both for conductors outside the array boundary and for conductors inside the array boundary. It is fair to say that there is general consensus on the first count. Both firefighters and solar industry stakeholders agree that shrinking the array boundary when controlling PV circuits will tangibly improve safety for proximity firefighting. Opinions differ, however, about what should happen inside the array boundary.

Which Side Are You On?

In the first draft of NEC 2017 690.12(B)(2), fire service representatives established a voltage limit of 80 Vdc within the array boundary, effectively mandating MLPE for all building-mounted PV modules. SEIA and other PV industry leaders pushed back during the public comment stage, even going so far as to commission the independent engineering firm DNV GL to study firefighter rooftop operations and hazards encountered while working around PV arrays, and to compare mitigation methods (see Resources).

Unless you actively track the Code development process, you may have missed out on the industry-wide gnashing of teeth regarding the module-level rapid-shutdown language in NEC 2017. The public comments associated with the first draft of section 690.12, “Rapid Shutdown for PV Systems on Buildings,” make for interesting reading because they illustrate the lines of debate and clarify the major concerns on both sides. Excerpts from this debate, edited for length and clarity, follow.


Firefighters are the most vocal advocates of the 80 V limit within the array, undoubtedly because module-level rapid shutdown sounds like it might render an array touch-safe. Not surprisingly, several vendors with module-level rapid-shutdown solutions also support the 80 V limit.

“Representing firefighters, I support the effort to shut down PV systems to the module level during emergencies. The recent proliferation of solar systems in our jurisdiction is having an impact on firefighters’ ability to respond to fire emergencies. Access and egress during rooftop operations and the inability to control utilities for the entire structure are concerns. It is vital that the Code development process recognize the need to protect firefighter safety. This proposal utilizes existing technology to do just that.”
—Richard Doane, fire marshal, Chico Fire-Rescue

“[PV system] circuits remain energized anytime the modules are illuminated and up to the maximum system voltage of 1,000 Vdc. This results in increased danger to first responders when the structure has been damaged. Historically, this has been accepted since there was no practical way to isolate a PV module from the PV source circuit that would operate remotely and on all PV modules in an array simultaneously. Module-level products were not readily available to provide this functionality. Today, this is no longer true: Many reliable products are available that can be either incorporated into a PV module or added to a PV module in the field to provide PV module isolation by remote control. The reliability concerns from 2014 are no longer relevant today, and market data estimates that up to 10 million units capable of module-level isolation are now in service.”
—James Penn, fire inspector, Compton Fire Department

“[The] Fire Marshal’s Association of Colorado supports the language in the first revision as well as the work from the Firefighter Safety and PV System Task Group. PV systems on rooftops can present several hazards to firefighters, the most serious being electric shock in an emergency situation. This section and the proposed change is a significant step forward in improving firefighter safety.”
—David Lowrey, fire marshal, Boulder Fire-Rescue

“[No] other appliance [is] allowed to be used in and around populated areas where there is not a clearly designated switch, plug or other de-energizing method for fully deactivating the system. Why should solar be any different? This industry inconsistency results in an even greater hazard to those untrained in solar, as the default expectation is that all electrical systems can be turned off and are fundamentally safe.”
—Tim Johnson, vice president of customer quality, Ten K Solar

“Enphase Energy supports the language proposed by Code Making Panel-4 [CMP-4], especially the reduced voltage level within an array when initiated by emergency personnel. Rooftop PV arrays should be able to [be] shut down to safe voltage levels in the event of emergency conditions. This is particularly important when considering the life span of a system, as older systems may present electrical hazards to emergency personnel.”
—Mark Baldassari, director of codes and standards, Enphase Energy


SEIA and several prominent member solar companies, both small and large, vigorously oppose module-level disconnection as a sole means of reducing shock hazards for emergency responders. Public comments suggest this opposition is not due to an unwillingness to develop and adopt more-rigorous safety standards, but rather due to questions about the efficacy of the 80 V limit as a means of accomplishing these goals.

“SEIA understands and largely agrees with the fire service’s intent to further enhance rapid-shutdown requirements in the 2017 NEC. SEIA disagrees, however, with the specific requirement limits [as] the incorporation of these limits into the NEC would effectively mandate module-level electronics, resulting in a variety of negative consequences.

“SEIA’s strong contention is that, given the absence of any independent technical justification for the proposed module-level electronics mandate, it is inappropriate for the NFPA to set voltage requirements within the array equipment. Indeed, the NFPA would be setting an arbitrary level of safety based solely on statements from a few existing product manufacturers and not fact-based testing involving a wide selection of performance criteria.

“There are multiple approaches to significantly reduce the risk of shock hazard to firefighters operating within the PV array boundary. In contrast, a module-level electronics mandate would favor certain technologies over others. This is an overly prescriptive approach, which will create a disincentive to develop competing technologies and [will] stifle innovation. It should also be recognized that nearly all module-level electronic devices being sold today are principally designed for power conversion and monitoring—not rapid shutdown.

“The long-term reliability of module-level electronics is also relatively unproven. Indeed, few devices currently being sold for module-level rapid shutdown have undergone long-term reliability testing in the field.

“Reliability is not only a concern for firefighters but also for PV service personnel exposed to the inherent hazards of roof work. The concern here is that unreliable rapid-shutdown devices will significantly, and unnecessarily, increase the amount of time PV installers and electricians spend on rooftops to replace or repair failed devices. And while PV installers and electricians recognize and accept the inherent risks of rooftop environments, no one should have to accept unnecessary exposure to such hazards.”
—John Smirnow, principal, Smirnow Law (representing SEIA)

“The current language requires that only the devices controlling conductors inside the array boundary limit the voltage to 80 V. There is no mention of the conditions under which this device must function; no mention of whether the device needs to periodically self-test; no mention of whether it needs to be fail-safe; no mention of immunity to heat, electrical noise or moisture. To be clear, we don’t think that these requirements should be spelled out in the NEC,  but they are essential to the safe and reliable operation of these devices. Hence, we request that the 80 V requirement be replaced with a new certification requirement. It is critical that this certification requirement be distinct from the other rapid-shutdown requirement, because it will need to provide functionality that is distinct from [that of] the other devices. The rapid-shutdown devices outside the array boundary only need to isolate certain conductors. The devices inside the array boundary need to limit the electrical hazards on the components directly connected to the PV modules, which are always energized. The present language is also silent about the amperage requirement, which is the physical quantity that actually causes harm to humans. With 80 V and no limit on current, it is still possible to electrocute a human.”
—Mark Albers, electrical systems engineer, SunPower

“While SolarCity supports the fire service in its intent to increase safety within the boundary of the array, the first draft of section 690.12(B)(2) has been written in such a way that effectively prescribes a specific type of electronic solution. [MLPE] are complicated devices, with a wide array of functions, but they were never designed for the sole purpose of ‘turning off’ solar modules. Because of their complexity, these devices cannot last as long as solar panels.

“[It] is important to remember that not a single firefighter has been killed while on a building with solar, suggesting that existing safety provisions for PV have been largely effective. Meanwhile, falls remain the number one cause of death among all construction workers. Mandating one device beneath every solar module will directly increase the time solar construction workers will have to spend on the roof to replace them. More time on the roof [equates to] a higher risk of falling.

“Even when [MLPE] devices work as advertised, the [PV] system is never truly shut down. UL confirmed as recently as June, in its evaluation of firefighter [personal protective equipment], that voltages below 80 V still pose a risk. [Reducing the voltage without eliminating] the hazard gives unsuspecting firefighters a false sense of security that only puts them at risk.”
—Duncan Cleminshaw, director of product compliance, SolarCity

“Representatives of the fire service tell us that they need to quickly ventilate a structure that is on fire, and as a 10-year veteran of the fire service and chief of a rural fire department, I can tell you that they are right. However, the position that vertical ventilation is the best and only way to ventilate, and that the fire service therefore needs full and unlimited access to the roof, does not align with modern fire science. Studies performed by the NIST [National Institute of Standards and Technology] and others have shown that positive-pressure ventilation is more effective than traditional vertical ventilation. According to this research, vertical rooftop ventilation can no longer be considered the gold standard for effective fireground operations.

“Section 690.12 should ensure that a local source of electricity (the PV array) can be easily disconnected from a building electrical system in the event of a fire, and 690.12(B)(1) achieves that goal. Requiring conductors within the array zone to be controlled to 80 V does not provide a touch-safe environment, and there are thousands of legacy PV installations currently installed that are not controlled within the array zone; therefore, 690.12(B)(2) creates a false sense of security for the fire service. Fire operations should not be in the array zone when there are better options.”
—Phil Undercuffler, director of strategic platforms, OutBack Power

The Compromise Solution

As a result of this pushback, CMP-4 developed a second revision of NEC 2017 690.12 that provides three compliance options inside the array boundary, each of which offers a unique set of challenges. The first option is to use a listed rapid-shutdown PV array, which assumes the existence of an as-yet-unwritten UL product safety standard. The second option is to limit the potential of controlled conductors to not more than 80 V. This option assumes that UL fire testing will show that divergent product classes (such as microinverters, ac modules, dc-to-dc converters and smart modules) provide an as-yet-unproven level of shock hazard mitigation under abnormal operating conditions—most important, after a fire has compromised and damaged the PV modules and associated solid-state devices. The third option is to deploy PV arrays with no exposed wires or conductive parts at least 8 feet away from exposed grounded conductive parts, which seems to belong in a product safety standard rather than in the NEC.

While the requirements for what should happen inside the array boundary are contentious, areas of common ground do exist. For example, both fire service and solar industry representatives on CMP-4 seem to agree that the compromise solution is not ideal. A common concern from stakeholders on both sides is whether the three compliance options allowed inside the array boundary provide an equivalent level of safety. Given that no one seems particularly happy with 690.12(B)(2) as written, it seems fortunate that this subsection will likely come with a delayed enforcement date of January 1, 2019. This delay will give UL and its standards technical panel members time to develop a rapid-shutdown PV array product safety standard that meets NEC 2017.

Ultimately, 14 of 17 eligible voters on CMP-4 voted in the affirmative, which suggests that the formally adopted 2017 rapid-shutdown language, due out in October, will adhere closely to the second revision, for better or worse. Bill Brooks, a solar industry representative on CMP-4, voted in favor of the second revision. However, he concedes: “The new version of 690.12 is a significant step in PV system safety that will be difficult for the PV industry to master in the first several years of enforcement.”

Brooks continues, explaining his affirmative vote: “While [compliant] products are commonly available and used in the residential market, the more difficult market is the commercial PV market. In the commercial market, margins are even tighter, and costs and reliability have to be carefully managed. Once these new standards and products become mature, the PV industry and all those whom it affects will have safer and better PV systems. Much work is necessary between now and then.”


Commercialized MLPE are competitive in residential applications. GTM Research data show that in 2014, when US states began adopting rapid-shutdown requirements, the combined market share for module-level solutions—including microinverters, dc optimizers, ac modules and smart modules—already accounted for more than half of the total residential product mix. Since that time, the market share for string inverters has eroded—presumably because more rapid-shutdown markets come on line each year—from 48% in 2014 to 40% in 2015. GTM Research estimates that the residential market share for string inverters could fall to 30% in 2017, which may prove optimistic given that California is now poised to adopt rapid shutdown.

What is less clear is whether commercially available MLPE can have the same success in nonresidential applications. Two charts from the “US Solar Market Insight Report: 2015 Year in Review,” published by GTM Research and SEIA, put  the challenge in stark contrast. The first chart compares average system costs by market segment (residential, nonresidential and utility). According to these data, average costs in the residential market segment were roughly $3.50 per watt in both Q4 2014 and Q4 2015, suggesting that it may be difficult for system integrators to drive costs out of residential systems while transitioning from string inverter–based to MLPE-based designs. In contrast, average costs in the nonresidential segment have steadily declined quarter over quarter, from roughly $2.20 per watt in Q4 2014 to about $2.00 per watt in Q4 2015. The gap between $3.50 per watt and holding, and $2.00 per watt and falling, is substantial.

The second chart compares installed PV capacity by market segment over time. These data show that the residential PV market is the fastest-growing market segment in the US, with more than 50% annual growth for 4 years running. By comparison, GTM Research describes the nonresidential solar market as “essentially flat for the third year in a row.” Here again, the gap between these two markets—one growing at a record pace and the other stagnant—is substantial.

When one considers these two data sets side by side, as shown in Figure 2, it seems fair to wonder whether the nonresidential PV market might contract, at least initially, under the cost burden of an MLPE mandate. While that mandate would undoubtedly prove good for some—perhaps paving the way for integrated ac PV modules, smart modules and other junction box– or cell string–level disconnection devices—it could be a net loss for the industry at large, especially for commercial project developers and EPC firms working in states that will adopt NEC 2017 early, such as Massachusetts and Colorado.

Supply bottlenecks are another concern. Today, commercial project developers have access to multiple product lines and vendors. If one of these vendors exits the market (as happened with Advanced Energy) or has supply-chain issues, system integrators can substitute compatible product platforms from other vendors prior to construction or even during operations. Though MLPE vendors have made great strides in recent years, this is nevertheless a relatively immature market, largely populated with vendors who offer mutually exclusive products. Innovation and proprietary interfaces, rather than substitutability and cross-compatibility, characterize the sector.

If an MLPE mandate went into effect today, project developers would likely be forced to either put all of their eggs into one of two baskets—Enphase Energy or SolarEdge (which dominate in terms of market share)—or qualify an alternative solution with a limited track record. This is not a recipe for resilience, but rather a precarious situation susceptible to market distortion. SMA’s partnership with Tigo, which the companies announced in April 2016, suggests that supply chain could be strategically important under an MLPE mandate. In exchange for acquiring a 27% stake in Tigo Energy, SMA obtains exclusive worldwide sales rights, for a period of 30 months, to Tigo’s TS4 R product platform, which is a retrofit solution designed to add MLPE functionality to conventional PV modules.


Many in the industry, myself included, believe that MLPE are inevitable and perhaps necessary in the long term. In spite of the technological hurdles, the vendors pioneering this space have largely proven their doubters and naysayers wrong. If we could fast-forward into the future, we would likely see that module-level and perhaps even cell string–level power electronics will prove the norm, perhaps sooner rather than later. Some industry experts even predict the eventual rise of cell-level power electronics. While today’s products work well, tomorrow’s more advanced products will work even better and more reliably.

What remains to be proven is whether MLPE are the most effective way to reduce shock hazards for emergency responders within the array boundary. Do MLPE perform better in this regard than other hazard mitigation methods? While solar and fire service stakeholders agree that rapid shutdown outside the array boundary reduces risks for firefighters, initial fire research and engineering evaluations suggest that current product safety standards do not eliminate shock hazards within a damaged PV array.

Fire research. In 2011, UL conducted the first experimental investigation of the impact fielded PV systems have on fire suppression, ventilation and overhaul activities. UL’s research engineers started by reviewing the literature and standards associated with electric shock, impedance of the human body, touch-safe voltage levels, and safe distances between water hoses and live electrical equipment. They then developed electrical and fire performance experiments that would identify and quantify the electrical shock hazard associated with specific PV-involved firefighting scenarios. UL published its findings in the report “Firefighter Safety and Photovoltaic Installations Research Project” (see Resources).

In addition to testing equipment such as firefighter gloves and boots for their insulating properties, the research engineers also sought to define safe working distances between water hoses and live electrical equipment. These tests indicate, for example, that firefighters can eliminate hose stream shock hazard by working at a distance of 15 feet from a 600 Vdc power source or 20 feet from a 1,000 Vdc source. Alternately, firefighters can reduce the measured current to below the level of perceptibility by changing the hose stream from a solid stream to a 10° cone pattern. Other tests confirmed that tarps are not reliably effective as a means of de-energizing a PV array, that light striking a PV array from a fire or a fire truck is sufficient to pose an electrical hazard, and that cutting into PV modules or source circuits is a bad idea. This is all very practical information for firefighter training purposes.

Perhaps the most important UL fire test results are those showing that damaged PV arrays are inherently hazardous. For these experiments, researchers installed test arrays on a wood truss roof, ignited a fuel load inside the structure and then let the fires burn uncontrolled until the roof collapsed. The post-fire analyses revealed that while some portions of the arrays were completely destroyed and produced no power, other significantly damaged areas still produced partial or even full power. Based on these findings, the report concludes, among other things: “Severely damaged PV arrays are capable of producing hazardous conditions ranging from perception [of current] to electrocution. Damage to the array can create new and unexpected circuit paths.”

Unless follow-up fire research shows otherwise, it would be irresponsible to bet any lives on the premise that the presence of MLPE would change these findings in any meaningful way. According to UL standards, the safe voltage level in wet conditions is 30 V. In the absence of cell string–level disconnects, most PV modules are capable of putting out more than 30 V under normal operating conditions. Since module-level or cell string–level rapid shutdown does not change the inherent properties of PV cells, it is prudent for emergency responders to assume that a fire-damaged array presents a shock hazard due to the potential for inadvertent and unexpected circuit paths.

Engineering evaluation. The authors of DNV GL’s 2015 advisory, “Rooftop PV Systems and Firefighter Safety,” start by reviewing relevant literature, such as UL’s 2011 fire research findings and a joint PV and fire industry study conducted in Germany. Interestingly, the outcome of the joint industry analysis in Germany, the country with the largest number of rooftop PV installations in the world, was a set of firefighting guidelines that emphasize safe boundaries and tactics. Because module-level technologies and standards are not sufficiently established and have yet to prove their reliability, the German report advises against a MLPE mandate.

After a literature review, DNV GL researchers conducted firefighter interviews and surveys to explore the “procedures, issues and decisions that firefighters face when carrying out operations at a building that has rooftop PV.” The interviews indicate that firefighters welcome the improved setback and pathway requirements in the 2015 fire codes, but still see some room for improvement. With a building-specific approach to pathway layout, for example, AHJs could intentionally align access pathways with the best trench-cut locations for firefighters.

The surveys, meanwhile, indicate that firefighters are indeed very concerned about the inability to eliminate or significantly reduce shock hazard in the PV array. In the short term, they need to be able to identify energized versus de-energized components. On the face of it, this sounds like a collective vote in favor of module-level rapid shutdown. However, the vast majority of interviewees—and all of those in leadership roles—indicated that they would never directly engage with or remove damaged modules for roof ventilation.

According to the report: “Respondents expressed the desire for rapid-shutdown functions to work under damaged conditions, but none expected that they would. All would treat damaged arrays as energized.” The authors later conclude: “The ability to further de-energize circuits within the array is seen as a key to reducing the risk of accidental shock, but not as a rationale for intentional interaction. The real value of enhanced electrical protection is in its impact on decision making, enabling firefighters to carry out and improve operations more confidently.”

Researchers at DNV GL used an engineering evaluation methodology, known as a failure mode and effects analysis,  to estimate the risks associated with different electrical hazard mitigation approaches. This methodology accounts for circumstances such as the severity of impact and the likelihood of occurrence and detection. The researchers then characterized the risks associated with different applications and scenarios (residential, normal operation; residential, single fault; commercial, normal operation; and commercial, single fault) in the context of different product topologies or design decisions. These probability-weighted results indicated that there are multiple acceptable risk mitigation options, including module-level shutdown with an 80 V limit, as well as “combinations of 1- and 2-pole string level disconnection, access-limited conductors [and] mechanically protected conductors.” All of these approaches “scored similarly as effective means to reduce the shock hazard within arrays.”

Rapid shutdown array standard. The DNV GL advisory largely supports SEIA’s contention that a prudent approach would be to develop a product standard for PV Equipment Safe for Proximity Firefighting. According to their public comments, some members of CMP-4 believe that rapid-shutdown PV array and PV equipment safe for proximity firefighting can mean the same thing. The safety standard is a work in progress, they suggest, and a rose by any other name would smell the same. In this case, however, the meaning of these words could be a matter of grave import.

To the uninitiated firefighter, equipment safe for proximity firefighting signals: “You can get close to this equipment, but not too close. Please do not touch.” In contrast, module-level rapid shutdown sends a misleading message: “I am now off.” While a touch-safe PV array is undoubtedly the long-term goal, we do not yet have a product safety standard that can render a damaged PV array safe for firefighters. Granted, we can make the roof safer with the touch of a button, but that does not mean the power is off.

Not surprisingly, UL’s representative on CMP-4, Timothy Zgonena, is going into the standards development process with his eyes wide open. Regarding his affirmative vote for the compromise NEC 2017 rapid-shutdown language, Zgonena comments: “UL understands the desired intention of the 80 V limit to reduce shock hazards. Unfortunately, 80 V can be a lethal electric shock hazard in this application. Further, it would be most appropriate to use a listed system consistent with the concept of 690.4(B) to limit the voltage, rather than some assemblage of equipment not specifically listed as a system. UL firmly believes that PV rapid-shutdown equipment specifically listed for this intended purpose is the best solution. We have made good progress since the first revision of 690.12 for the 2017 NEC. UL understands and supports the development of a science-based solution as the basis for the upcoming standard.”


David Brearley / SolarPro / Ashland, OR /


Backstrom, Robert, and David Dini, “Firefighter Safety and Photovoltaic Installations Research Project,” UL Report, November 2011

DNV GL, “Rooftop PV Systems and Firefighter Safety,” DNV GL Renewables Advisory, October 2015

Primary Category: 

More than 600 solar equipment and service providers will display their products at the Solar Power International conference and expo in Las Vegas September 13–15. In this preview article, I highlight 17 companies that provide a wide range of solutions for system integrators. Some of the equipment detailed here recently launched or is set to launch at the event. Some is time-tested in fielded systems across the US. And some represents new or out-of-the-box ideas that may or may not take hold, but that nonetheless represent the dynamic innovation that keeps the solar industry moving forward.

Modeling, Measurement and Testing

Aurora Solar - Booth WSUA12

Aurora Solar develops cloud-based software that enables sophisticated solar project engineering design, provides workflow management functionality, and facilitates sales and customer acquisition for solar installers and financers. The company launched in 2013 with the backing of the US Department of Energy’s SunShot Initiative. The Aurora design platform includes features such as 2-D and 3-D modeling, 3-D visualizations, irradiance maps and annual shade values, automatic roof setbacks, electric bill and financial analysis, sales proposals and remote shading analysis, as well as engineering features such as performance simulations. Monthly and annual per seat pricing is available, as are enterprise-scale packages. The basic subscription is $159 per month, per seat, and includes the features listed. The premium-level product costs $259 per month, per seat, and offers additional features including monthly shade values, site modeling with LIDAR, NEC validation, single-line diagrams, BOS components and detailed bills of materials.
Aurora Solar /

Curb - Booth W902

Launched in 2012, Curb is a new entrant to the solar and energy efficiency market. Its home energy monitoring system offers integrators a compelling option for circuit-by-circuit energy use monitoring and visualization at a low price point ($399). Curb designed its data acquisition system for mounting in a home’s load center. The system includes 18 CT sensors for individual circuit monitoring. This level of monitoring granularity facilitates specialized tasks—for example, determining how much energy electric vehicle charging is consuming. The Curb system can measure on-site energy generation from PV systems and integrate production values with home consumption data. Curb includes a variety of notifications for events, such as when a user has accidentally left on a given appliance. Additional features include a power budget manager that allows users to track progress against a monthly energy budget. The software identifies changes in consumption and provides suggestions for conserving energy and money. With the upcoming launch of its home energy intelligence product, Curb plans to take its platform a step further with functionality that aims to predict appliance failure and identify required maintenance for components such as HVAC or refrigerator compressors.
Curb / 844.629.2872 /

Folsom Labs - Booth 3053

At the core of San Francisco–based Folsom Labs’ design efforts is the principle that every PV system design decision can and should be quantified in terms of its yield and financial implications. To further this goal, Folsom Labs develops HelioScope, a PV system design tool that integrates system layout and performance modeling to simplify the process of engineering and selling solar projects. The platform integrates easy-to-use design tools and bankable energy yield calculations. A core differentiator for HelioScope is that it is designed on a component-based model, which separately models each piece of the system (individual module, conductor or inverter, for example). Folsom Labs offers both monthly and yearly subscription rates. The cost of a single-seat monthly subscription is $79 and includes automatic CAD export, energy simulation, shade optimization, one-click sharing, a component library of 45,000 items, global weather data and PAN file support. Solar professionals can use HelioScope to design and model PV plants with capacities of up to 5 MW.
Folsom Labs /

Seaward Solar - Booth W824

Seaward Solar is a division of the UK-based Seaward Group. Its line of PV test equipment is one of the more recent development efforts in the company’s 75-year history in electrical safety test measurement instruments. Seaward Solar’s offerings include products used in PV system commissioning and operation verification, such as conductor insulation testers, irradiance meters and I-V curve tracers. The company recently announced the launch of its new PV210 multipurpose PV tester, which combines installation and commissioning tests with the ability to perform I-V curve analysis. Simple push-button operation allows users to conduct all the electrical commissioning tests required by IEC 62446, including open-circuit voltage, short-circuit current, maximum power point voltage, current and power, and insulation resistance. In addition, the PV210 performs I-V curve measurements in accordance with IEC 61829 to determine whether the measured curve deviates from the expected profile. For full, detailed analysis, users can transfer measured data from the test instrument to an accompanying PVMobile Android app to create high-definition color displays of the I-V and power curves for individual PV modules or strings.
Seaward Solar / 813.886.2775 /


LG Solar - Booth 1447

LG’s activity in solar module development dates back to 1985, when it (under the brand GoldStar Electronics) conducted its initial multicrystalline PV cell R&D. Since then the South Korean company, part of the global LG Group, has rebranded and become a household name in appliances and personal electronics. Another LG Group subsidiary, LG Chem, is on the front lines of designing and manufacturing lithium-ion batteries for use in stationary solar-plus-storage systems. LG Solar initiated mass production of its PV technology in 2010. It recently announced the US availability of its NeON 2 72-cell module models, developed for commercial and utility-scale installations. The three models—LG365N2W-G4, LG370N2W-G4 and LG375N2W-G4—have rated power outputs ranging from 365 W to 375 W. The new models expand LG’s high-efficiency PV lineup, which includes the 60-cell NeON 2, with rated power outputs of 305 W–320 W and module efficiencies of 18.6%–19.5%.
LG Solar /

SolarWorld - Booth 911

SolarWorld has more than 40 years of history in solar module design and manufacturing, dating back to Bill Yerkes’ founding of Solar Technology International and ARCO Solar’s development efforts in the 1970s, the assets of which SolarWorld acquired. Today, SolarWorld offers a full line of Sunmodule products, including two glass-on-glass bifacial Bisun models, as well as system packages that incorporate Quick Mount PV’s railless Quick Rack system and power electronics from vendors such as ABB, Enphase and SMA America. In July, SolarWorld announced the launch of its 1,500 Vdc–rated 72-cell SW 340–350 XL MONO module line, which is available with 340 W, 345 W and 350 W maximum power. The introduction of the high-voltage XL product positions SolarWorld to take advantage of the expanding deployment of 1,500-Vdc PV power plants in the US.
SolarWorld / 503.844.3400 /

Sunpreme - Booth 2125

Headquartered in Sunnyvale, California, and launched in 2009, Sunpreme is differentiating itself from commodity module vendors with the development of thin-film, high-efficiency, bifacial, double-glass frameless modules. The company bases its unique cell architecture on its patented Hybrid Cell Technology (HCT) platform, which utilizes four amorphous silicon thin-film depositions on surface-engineered silicon substrate. The frameless double-glass module design does not require electrical grounding. Sunpreme’s Maxima GxB module line includes five modules, two of which integrate Tigo Energy’s TS4-L (long-string) dc optimizers. The highest-power module, the GxB 370W, has a power output of 370 W STC and a module efficiency of 19.1%. Sunpreme specifies a bifacial output for the GxB 370W of 444 W, with a 20% boost in power from the module backside and a resulting module efficiency of 22.9%.
Sunpreme / 866.245.1110 /

Ten K Solar - Booth 759

Ten K Solar, founded in 2008, leverages a unique nonserial architecture with its module and integrated system design.  Its Apex module line includes the Apex 500W Mono (500 W monocrystalline) and the Apex 440W Poly (440 W polycrystalline). Both modules utilize 200 half-cells connected in a matrix (serial and parallel connections). This structure allows current to flow through multiple pathways within a module, improving partial shade performance, reducing the impact of soiling and hot spots, and eliminating a single point of potential failure within the module. Module-level power electronics convert the internal module voltage (<18 Vdc) to an operating voltage of 35 Vdc–59 Vdc. Ten K expands on this shade- and fault-tolerant low-voltage parallel architecture with its ballasted DUO PV system for low-slope roofs and ground-mounted arrays. The DUO system configuration, which integrates groups of parallel-connected microinverters on a shared dc bus, places rows of modules in tandem, back-to-back, to maximize power density and energy yield per square foot.
Ten K Solar / 952.303.7600 /

Power Electronics

Delta - Booth 2259

Delta Group is the world’s largest provider of switching power supplies and dc brushless fans, as well as power management equipment, networking products and renewable energy solutions, including solar inverters. Historically, Delta has positioned itself somewhat behind the scenes in the US solar market, as other vendors have rebranded the OEM’s inverter products. However, Delta is developing its presence in the US, introducing new solutions to the market. Two recent examples are its 7 kW RPI H7U single-phase inverter and its 80 kW M80U 3-phase string inverter. The UL-certified RPI H7U features a secure power supply for limited daytime power production when the grid is not present, and 4 MPP trackers with a full-power MPPT range of 185 V–470 V at 240 Vac and a wide operating voltage range of 30 V–500 V. Integrators continue to deploy high-power 3-phase string inverters in increasingly large multimegawatt PV plants. Delta’s 80 kW M80U inverter will support this upward capacity trend. The inverter has a maximum input voltage rating of 1,100 V, a full-power MPPT range of 600 V–800 V and an operating voltage range of 200 V–1,000 V. Options for connection on the dc side include 16 source-circuit fuseholders, two 3/0 AWG terminal blocks and 18 pairs of MC4 connectors for wire harness compatibility. With a unit weight of 180.6 pounds or less, depending on configuration, the M80U is light enough to permit a two-person installation.
Delta /

OutBack Power - Booth 2825

OutBack Power designs and manufactures inverter/chargers, charge controllers, integration equipment and monitoring solutions for stand-alone and utility-interactive battery-based renewable energy systems. Currently a member of the Alpha Group, OutBack was founded in 2001. Battery-based PV systems are inherently more complicated than grid-direct ones. The accumulated experience of established power electronics companies such as OutBack is a valuable asset for integrators when applications require advanced system configurations. In 2011, OutBack released its Radian series of hybrid, utility-interactive split-phase 120/240 Vac inverter/chargers. Available in 4,000 W and 8,000 W power classes, the Radian features two ac inputs for grid and ac generator connectivity and a high degree of component integration. With the recent introduction of four VRLA storage batteries optimized for specific applications such as float service or regular deep cycling, OutBack now offers a comprehensive product family for energy storage applications listed to the relevant UL standards.
OutBack Power / 360.435.6030 /

SMA America - Booth 959

SMA Solar Technology was founded in 1981. Its US subsidiary, SMA America, was the first inverter manufacturer to offer high-voltage string inverter models in the US market. In addition to developing single- and 3-phase string inverters, SMA has also devoted significant resources to the development of high-power central inverters for multi-megawatt medium-voltage utility-scale PV plants. As the US and global inverter markets have evolved, more manufacturers are focusing on either string inverters or central inverters. SMA is one of a shrinking group of inverter vendors that continue to create solutions in both product classes for utility-interactive applications. One example is its second-generation Medium Voltage Block for utility-scale applications deploying its Sunny Central 1850-US, 2200-US and 2500-EV central inverters. SMA’s 3-phase inverter lineup, the Sunny Tripower series, currently includes six models with rated power capacities of 12 kW–60 kW and 480 Vac output. The company has also been redesigning its single-phase inverter family. It recently launched updated Sunny Boy 3.0-US, 3.8-US, 7.0-US and 7.7-US models, which join the 5.0-US and 6.0-US models it introduced earlier this year, to provide integrators with greater design and installation flexibility. SMA plans to release a high-voltage Tesla-compatible battery inverter for the US market in early 2017. It has also made a significant investment in incorporating MLPE technology from Tigo Energy into its systems, in anticipation of module-level rapid-shutdown requirements in NEC 2017.
SMA America / 916.625.0870 /

Trackers, Racking and Mounting

Array Technologies - Booth 2805

Array Technologies (ATI) began manufacturing solar trackers in Albuquerque, New Mexico, in 1992 and has continually evolved, redesigned and scaled its solar tracking equipment, systems and services in step with the solar industry, especially in the utility-scale PV plant market. ATI launched its third-generation centralized DuraTrack HZ v3 horizontal single-axis tracker in 2015 and continues to be a strong proponent of centralized tracking systems. The DuraTrack HZ v3 has an algorithm with a GPS input tracking method and a ±52° tracking range of motion with backtracking functionality. The system’s drivetrain has sealed gearboxes designed to be maintenance-free for the life of the plant. The DuraTrack HZ v3 has a 135 mph 3-second-gust exposure-C allowable wind-load rating. A passive mechanical wind protection system that does not require power to operate safeguards the tracker during high-wind events and eliminates the maintenance requirements associated with active stow components. Configurations for c-Si modules include one-up in portrait orientation and two-up in landscape orientation, as well as four-up in landscape for thin-film modules. To speed module installation, ATI has developed an innovative single-fastener module clamp with integrated grounding.
Array Technologies / 855.872.2578 /

Beamreach Solar - Booth 2941

Beamreach Solar (formerly Solexel, founded in 2007) showed the demo installation of its Sprint PV system to big crowds of curious onlookers at July’s Intersolar North America event in San Francisco. Developed specifically for weight-constrained, low-slope commercial rooftops with TPO membranes, the system integrates a 60-cell monocrystalline 290 W, 295 W or 300 W module with a composite frame and an integrated racking system. The weight per module, including its racking components, is 38 pounds. The system is not ballasted or penetrating, but rather adheres directly to the TPO roofing membrane. Each row of modules simply snaps into the back feet of the previous row. The lack of metal components eliminates the need for equipment grounding. For shipping, Beamreach packs 26 modules with integrated racking components on a single pallet. Time will tell whether the Beamreach Sprint system will gain traction in the field; however, its design clearly exemplifies the innovation that is happening across the PV industry.
Beamreach Solar / 408.240.3800 /

SunLink - Booth 2037

SunLink launched its first racking systems for commercial rooftops in 2004 and helped pioneer the design and deployment of ballasted PV array mounting systems. More recently, the company has been expanding its product portfolio and expertise to include project development and O&M, SCADA and data monitoring services, and PV tracker systems. SunLink will launch its TechTrack Distributed single-axis tracker in Q3 2016. The self-powered tracker uses a slew drive, a 24 Vdc motor, a lithium-iron phosphate battery and an integrated PV module to drive the tracker. Its tracking range of motion is ±60°. Installers can mount modules one-high in portrait orientation, and array configurations are optimized for 90 modules per 30 kWdc row. A secure modified Zigbee mesh network provides on-site communication between the tracker controllers. The TechTrack Distributed system reacts intelligently to real-time conditions to increase generation and reduce the risk of damage to the power plant. Dynamic stabilization provides damping during critical events such as high winds. The tracker is designed for 105 mph and 5 psf standard loads and is configurable for wind loads of up to 150 mph and snow loads of up to 60 psf.
SunLink / 415.925.9650 /

Conductor Aggregation and Management

CAB Solar Booth 311

Under its CAB Solar brand, the Cambria County Association for the Blind and Handicapped manufactures a range of products that include cable rings and saddles for PV cable management, while providing rehabilitation and employment services to persons with disabilities living in Cambria County, Pennsylvania. Elevated cable systems are gaining popularity in utility-scale PV plants, and CAB was an early supplier to these projects. CAB Solar’s PVC-coated rings and saddles feature a high–dielectric grade, flame-retardant and UV-stabilized coating, applied to 100% of the product’s surface. The resulting rings and hangers are electrically insulated and durable in corrosive environments. CAB offers an extensive range of PV wire management solutions, including multicarrier hangers that provide physical separation between dc source-circuit conductors, ac cables and data transmission circuits. The company also manufactures high-visibility safety vests, bags, pouches and holders for the safe organization and transport of hand tools, cordless tool batteries, meters and communication devices in rooftop and other environments.
CAB Solar / 814.472.5077 /

HellermannTyton - Booth 625

HellermannTyton is a global manufacturer of cable management, identification and network connectivity products. Its North American headquarters are located in Milwaukee, Wisconsin. Its products for PV applications include Solar Ties and Solar E-Clips that enable flexible and secure routing of conductor and cable bundles. HellermannTyton also offers Solar Identification printers, labels and software systems that provide professional and durable PV system labeling. Its Ratchet P Clamp is an innovative solution for cable management. The adjustable ratchet clamp mechanism is available in four sizes for cable bundles or conduit ranging from 0.24 inch to 2 inches. In addition, the product is available with three lengths of mounting plates and 15°, 30°, 90° and 180° angle orientations. The Ratchet P Clamp is designed for easy opening using a small flathead screwdriver. Installers can stack the clamps for parallel cable runs and offset applications.
HellermannTyton / 800.537.1512 /

SolarBOS - Booth 935

Founded in 2004, SolarBOS focused from the start on configurability, with its first product a configurable 600 Vdc source-circuit combiner box that allowed customers to specify the number of circuits and the NEMA rating of the enclosure. This approach remains a core feature of the extensive range of combiner boxes, recombiners, disconnects, battery connection panels and cable assemblies SolarBOS offers today, including many product versions listed for 1,000 Vdc and 1,500 Vdc applications. In 2015, SolarBOS rolled out its Wire Solutions products for deployment in the growing number of commercial and utility-scale systems that use pre-engineered wire harness and cable assemblies. The company’s product family for these applications includes overmolded Y harnesses with or without inline fuses, homerun cable assemblies and combiner box whips. All wire harness assemblies are custom manufactured to client specifications. Customers can choose from various wire gauges and conductor jacket colors, industry-standard connectors and custom labels at each connection point.
SolarBOS / 925.456.7744 /

Primary Category: 

[Lawrence, MA] Adding to its existing line of 3-phase non-isolated string inverters for commercial and decentralized solar applications, Yaskawa–Solectria Solar has introduced 50 kW and 60 kW inverter models for 1,000 Vdc projects. The new PVI 50TL and PVI 60TL inverters feature 3 MPP trackers (300 Vdc–950 Vdc operating range, 540 Vdc–850 Vdc MPPT range) with five inputs per tracker, integrated ac and dc disconnects, and remote diagnostics and firmware upgrades. Options include an MC4 wiring box, shade cover and web-based monitoring. The PVI 50TL and PVI 60TL inverters employ integrated NEC 2014–compliant AFCI and rapid-shutdown functionality. The inverters are approved for mounting angles of 0°–90° (flat through vertical) and are covered by a standard 10-year warranty with optional 15- and 20-year extended service agreements.

Yaskawa–Solectria Solar / 978.683.9700 /

Primary Category: 

[Zamudio, Spain] Ingeteam has added a third model to its high-power 3-phase Ingecon Sun 3Play inverter line. The 40TL U M480 (40 kW) model joins the existing 18TL U M480 (18 kW) and 24TL U M480 (24 kW) inverters that Ingeteam developed for 1,000 Vdc large commercial, industrial and decentralized utility-scale PV installations. All three non-isolated 3-phase 480 Vac inverters feature two independent MPP trackers with 200 Vdc– 820 Vdc MPPT range, a CEC weighted efficiency of 98% and arc-fault circuit interruption functionality. Housed in a NEMA 4 enclosure, the 138-pound 40TL U M480 is approved for 0°–90° mounting. Ingeteam backs the Ingecon Sun 3Play inverter line with a 10-year warranty extendable up to 20 years.

Ingeteam / 408.524.2929 /

Primary Category: 

Updated for 2016, SolarPro’s current string-inverter dataset includes 143 string inverter models from 13 manufacturers. A Nationally Recognized Testing Laboratory (NRTL) has listed all the products in the table to the UL 1741 standard. In addition, most of the inverters are identified in the CEC list of eligible inverters per SB1 guidelines. All of the manufacturers represented maintain one or more established US sales and technical support offices.

The last edition of our string-inverter dataset was published in the August/September 2014 issue of SolarPro, where I identified some high-level trends that included an increasing shift to transformerless, non-isolated topologies, and the development of higher-power, higher-voltage 3-phase string inverters for commercial, industrial and select utility projects. These trends have continued over the past 18 months. More than 85% of the string inverters in this year’s dataset are non-isolated. As well, this year’s dataset features 55 3-phase units and 47 string inverters listed for applications over 600 Vdc. Notably, the highest-capacity inverter represented has a rated power output of 60 kW and weighs a mere 121 pounds.

On the vendor front, Advanced Energy was a significant exit from the inverter market, taking Refusol’s acquired line of 3-phase string inverters with it. SolarMax was another market exit worth mentioning. Finally, SolarEdge made a big splash at the Solar Power International conference with the announcement of its new MOSFET-based HD Wave topology. Corresponding datasheets and installation manuals were not available when I aggregated values for the 2016 edition of the SolarPro string inverter specifications dataset. I will update the Excel-based version of this dataset when these specifications are released.

From the "Inside This Article" sidebar you can download a Microsoft Excel file containing the inverter specifications compiled in this table. SolarPro permits and encourages solar design and installation companies to integrate this data with their own sales and design databases.


Joe Schwartz / SolarPro / Ashland, OR / /


ABB / 877.261.1374 /

Chint Power Systems / 855.584.7168 /

Delta Americas / 510.668.5100 /

Fronius USA / 877.376.6487 /

Ginlong / 866.438.8408 /

HiQ Solar / 408.970.9580 /

Ingeteam / 408.524.2929 /

KACO new energy / 415.931.2046 /

Schneider Electric / 888.778.2733 /

SMA America / 916.625.0870 /

SolarEdge Technologies / 877.360.5292 /

Sungrow North America / 619.397.8000 /

Yaskawa (Solectria Solar) / 978.683.9700 /


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