Products & Equipment : Batteries

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If analysts’ projections hold true, behind-the-meter energy storage applications in general—and residential applications in particular—are poised for dramatic growth over the next 3 to 4 years.
Does this mean that stored energy costs are approaching the retail price of electricity?

In “US Energy Storage Monitor: 2015 Year in Review” (see Resources), GTM Research forecasts that the US annual energy storage market will reach 1.7 GW by 2020, a 26-fold increase from 2014. The projected growth by market sector is of particular interest to solar installers. According to data that GTM Research and the Energy Storage Association gathered for the report, customer-sited behind-the-meter energy storage deployments accounted for roughly 11% of the total market in 2014 and 16% in 2015, with utility deployments comprising the vast majority of installed energy storage capacity. However, GTM Research expects that by 2019 the energy storage deployed behind the meter in nonresidential and residential applications will eclipse the utility segment.

In this article, we consider some of the use cases and emerging markets for residential grid-interactive energy storage systems. We then present a simplified levelized cost of stored energy (LCOS) metric, useful for analyzing the economics in residential energy storage applications. In addition to exploring the sensitivity of LCOS in relation to various parameters, we consider the practical limitations of this metric. Throughout the article, we consider some of the ways in which the emerging energy storage market parallels the early days of the solar industry, and what this may tell us about its path forward.

Market and Applications

The projected growth of the residential energy storage market presents a tremendous opportunity for solar installation companies. After all, interconnecting a battery-in-a-box type of appliance is not all that different from making the grid connection for an interactive PV system. Further, adding solar to an energy storage system can improve the overall value proposition, both by leveraging tax credits and by adding another battery charging source. Finally, solar companies can offer energy storage as a retrofit solution to existing customers or as an optional upgrade to new customers, which are compelling ways to drive down customer acquisition costs and increase sales revenue.

The challenge, of course, is that the energy storage market has made less progress along the classic technology adoption and hype cycle curves, shown in Figure 1, than solar has. The California residential grid-tie solar market, for example, progressed from innovative pilot projects in the 1990s to a classic early adopter market at the beginning of the 2000s, when customer concerns about the environment or self-sufficiency drove sales more than economic self-interest. Now that residential solar has reached grid parity in California, the technology appeals more broadly to economic pragmatists, which is characteristic of an early majority market. While solar market maturity varies from state to state, GTM Research’s latest in its series of US solar market reports (see Resources) estimates that solar has reached grid parity in 19 states plus the District of Columbia, meaning that the levelized cost of energy for PV is equal to or lower than the retail price of electricity in these markets—after accounting for incentives and tax credits.

By comparison, these are very early days for the residential energy storage market in the US. The authors of the Rocky Mountain Institute (RMI) report “The Economics of Grid Defection” (see Resources) estimate that residential solar-plus-storage has the potential to achieve grid parity in Hawaii today under certain scenarios that assume improvements in demand-side load management and battery cost reductions. Under a more realistic base case scenario, the authors project the following: “Residential [solar-plus-battery] systems will reach grid parity as early as the early 2020s in Hawaii, late 2030s in Los Angeles, and late 2040s in [Westchester, New York].”

While Tesla succeeded in creating a lot of buzz about energy storage with its Powerwall announcements, it is reasonable to wonder whether current technology and business cases can meet customer expectations. If not, energy storage likely still has a hill to climb before it overcomes its own hype, as represented by the slope leading to the Peak of Inflated Expectation in Figure 1. By comparison, the leading solar markets in the US are more developed, advancing perhaps along the Slope of Enlightenment.

Part of the challenge facing residential energy storage in the US is that its use cases or applications are limited compared to those of maturing energy storage markets elsewhere in the world or even of domestic commercial deployments. The authors of a more recent RMI report, “The Economics of Battery Energy Storage” (see Resources), identify four customer services for behind-the-meter energy storage: backup power, increased PV self-consumption, time-of-use bill management and demand reduction. To put these applications in context, let us briefly review the goals and ideal economic environment for each scenario.

Backup power. The role of energy storage in backup power applications, of course, is to support loads in the event of a grid failure. Generally speaking, the installer relocates a subset of the home’s branch circuits to a new subpanel. In the event of a grid failure, loads connected to this backup- loads subpanel can operate for as long as the battery state of charge remains above its allowable depth of discharge. The duration of backup power varies based on the load profile and the battery capacity. A benefit of solar in this scenario is that it provides a battery charging source when the grid is down, which can extend backup power availability from a period of hours to days.

Demand for backup power is an important driver in residential energy storage applications, especially in the short term. However, this is also a classic early adopter market, one driven more by customer desire than by economics. It is simply not possible to develop a business case that justifies residential energy storage for backup power on a dollar per kilowatt-hour basis. Instead, customers willing to pay a premium price to have the latest technology or to ensure that they can keep lights on during an outage are the ones driving these sales.

PV self-consumption. The role of energy storage in a self-consumption or zero-export scenario is to store excess PV production and discharge this stored energy later. Self-consumption and zero-export applications always include solar. As compared to standard interactive or backup power systems, self-consumption applications require additional energy monitoring. In effect, the solar-plus-storage system needs to see the home energy consumption in real time to optimize energy inflows and outflows for maximum customer benefit. Moreover, zero-export systems need to curtail PV production whenever generation exceeds on-site loads and the battery bank’s capacity to store energy.

Markets where utilities value PV outflows at a rate that is lower than the retail price of electricity, or where they simply will not allow PV outflows, drive the demand for PV self-consumption or zero-export systems. In markets with net energy metering (NEM), customers can effectively store excess solar generation on the utility grid. Since these customers receive the full retail price for outflows, the only benefit of adding energy storage is as a hedge against the loss of NEM. In markets without NEM, however, PV customers can use a battery to shift delivery of excess PV generation in time for use later, as illustrated in Figure 2. To be economically viable, self-consumption applications need to offset the inherent efficiency losses associated with energy storage, as well as the substantial up-front costs associated with the additional hardware.

Time of use. As with PV self-consumption systems, the role of energy storage for time-of-use bill management is to store energy for use later. The primary difference between these scenarios is the logic they employ to define high-value versus low-value energy. Since NEM rules do not apply in a self-consumption scenario, customers get a retail credit only for PV generation that directly offsets household loads; they get a fraction of this value for PV outflows, which the utility might credit at the wholesale or avoided cost of electricity. In a time-of-use regime, the standard NEM logic applies; however, the retail rate structure itself values energy differently over the course of a day or year, as illustrated in Table 1. Utilities intentionally design these price differences to correspond with the relative demand for energy, as these signals can help level out electricity demand and even defer infrastructure upgrades.

In a time-of-use scenario, energy has the highest value during periods of peak demand, such as weekday afternoons or evenings in summer, and relatively lower worth at other times. The prime economic driver in these scenarios is the magnitude of the difference between on-peak and off-peak energy rates. In theory, if the spread between high-value and low-value energy is large enough, energy storage customers can achieve a return on investment by storing energy during off-peak periods and discharging it when on-peak prices are in effect. In practice, battery costs are relatively high and retail energy prices are relatively low in most of the US, which works against this business case.

Demand reduction. Demand-reduction applications use stored energy to reduce instantaneous power demand. Demand reduction is one of the most attractive business cases for behind-the-meter energy storage in commercial applications. Whereas utilities typically bill residential customers strictly based on monthly energy (kWh) consumption, they bill commercial and industrial users based on both energy consumption and peak power (kW) demand, typically as measured over a 15-minute interval. For commercial and industrial customers, peak demand charges are not only the fastest-growing part of their electric bill, but also may account for up to 50% of the total. In these applications, service providers can use advanced monitoring and control capabilities to discharge stored energy from the batteries coincident with peak loads.

Though demand reduction is an excellent use case for energy storage, very few utilities factor demand into residential rate structures. A notable exception is Arizona’s Salt River Project, which recently implemented a pilot program for a residential demand–based price plan. Unless residential demand charges apply, demand reduction is not a viable market for in-home energy storage.


The US Energy Information Administration (EIA) tracks average electricity prices by state and market sector over time. In October 2015, EIA published its recently aggregated annual energy cost data, which indicate that the average retail price of electricity in the residential sector was 12.52 cents per kWh in 2014. Drilling down on the state-level data, Washington, which gets 65% of its electricity from hydro, had the lowest residential electricity prices (8.67 cents per kWh), whereas Hawaii, which gets the lion’s share of its electricity from fuel oil, had the nation’s highest prices (37.04 cents per kWh).

So how does the cost to store energy in residential applications compare to retail electricity prices? In reality, this depends largely on the energy storage system’s use and cycling practices. However, it is possible to use the simplified formula in Equation 1 to derive a back-of-the-napkin value for the LCOS:

LCOS = Cost ÷ (Usable Capacity x Cycles x Efficiency) (1)

Cost. In the SolarPro article “Levelized Cost of Energy” (April/May 2012), Tarn Yates and Bradley Hibberd note that LCOE calculations “should include all costs that the project incurs—including construction and operation—and may incorporate any salvage or residual value at the end of the project’s lifetime.” They go on to explain how to account for project financing costs, discounted cash flow and depreciation in these calculations. As the formulas in the 2012 article evidence, detailed LCOE calculations can become quite complicated.

For the purposes of this article, we intentionally strip away many of these layers of complexity. We do not factor the time value of money into our LCOS calculations; we do not consider the residual value of the equipment at the end of its life cycle; we do not even consider O&M costs. Instead, we use the initial installed cost of the energy storage system and the associated power electronics as a proxy for the total life cycle costs.

To justify this simplified approach, we look specifically at the LCOS for a representative set of lithium-ion energy storage solutions and applications. Since vendors advertise these advanced battery appliances as maintenance-free solutions, we assume that the user does not incur any additional costs to maintain and operate the energy storage asset. Note that if you wanted to use this formula to analyze the LCOS for an energy storage system with flooded lead-acid batteries, which have lower up-front costs than lithium-ion batteries, you would have to factor in O&M costs over the life of the system. These costs vary based on labor rates and travel times.

Table 2 illustrates the sensitivity of LCOS to costs. On one hand, Green Mountain Power, Vermont’s largest electric utility, is selling turnkey Tesla Powerwall solutions—complete with a SolarEdge StorEdge inverter, autotransformer and energy meter—for an installed price of $6,500, made possible in part by a bulk purchase order for 500 units and the fact that the utility can use its own technicians to install the systems. On the other hand, TreeHouse, an Austin, Texas–based sustainable home improvement store, is the nation’s first retailer to offer Tesla’s Powerwall, which it provides through a network of licensed installation partners. According to one of these installation partners, the initial turnkey cost for a StorEdge plus Powerwall system in Austin will likely be “closer to $9,000.” This $2,500 difference in up-front costs results in a $0.16/kWh difference in the LCOS between the utility provider and the retail provider.

Usable capacity. An energy storage system’s usable capacity is primarily a function of nameplate kWh capacity, the allowable depth of discharge and battery capacity degradation over time. For example, Adara Power (formerly JuiceBox Energy) sells a residential energy storage system with a nominal 8.6 kWh lithium-ion battery. According to the company’s CEO, Neil Maguire, the maximum allowable depth of discharge for these nickel manganese cobalt oxide batteries, which Samsung manufactures, is 75%. Based on this allowable depth of discharge, the usable capacity of Adara’s energy storage system is 6.45 kWh (8.6 kWh x 0.75). However, this is  the nominal battery capacity on day 1 only. This battery capacity will invariably decline over the life of the system, based in part on aging and in part on usage.

There are challenges associated with deriving a realistic value for an energy storage system’s usable capacity. Notably, the energy storage industry lacks nameplate and datasheet reporting standards and independent third-party verification requirements. This scenario is not unlike the early days of the US solar industry, when some manufacturers batched modules according to very tight nameplate power tolerances, such as +5% to −0%, while others had a very wide window, such as +5 to −10%. It is also reminiscent of the days before the CEC established independent verification test requirements for PV modules (PTC ratings) and inverters (CEC-weighted efficiency).

Without access to standardized data verified by a third party, the battery warranty may provide the best approximation of usable capacity over the life of an energy storage system. For example, Tesla nominally rates its Powerwall at 6.4 kWh when used for daily cycling. If we assume that a Powerwall cycles to capacity 3,650 times over its 10-year warranty period, the best-case LCOS falls in the $0.31–$0.43/kWh range, depending on system cost. However, if we review the Powerwall warranty, which accounts for the stepped degradation over time shown in Figure 3, we see that Tesla guarantees “18 MWh of aggregate discharge” from the battery cells. If we calculate LCOS based on the warranted battery capacity, LCOS increases to $0.40–$0.56.

Cycles. Battery life depends strongly on usage patterns, as anyone with a cell phone or laptop computer can attest. So a manufacturer might rate a particular battery for 4,000 cycles at a 70% depth of discharge or 3,000 cycles at an 85% depth of discharge. Ideally, system integrators and customers should have access to these data, either in tabular form or in graphs that plot battery cycle life in relation to depth of discharge. In practice, these data are difficult if not impossible to find.

One of the reasons battery cycle ratings are so important is that customers get the most value out of a battery that is the right size for their application. For example, sonnen guarantees all of its sonnenBatterie eco series of energy storage systems for “10,000 cycles or 10 years.” Since daily cycling accounts for only 3,650 cycles over a 10-year period, you would need to cycle these batteries an average of 2.7 times per day to approach 10,000 cycles over the warranty period. To achieve this level of usage, you would likely need to deploy the energy storage system in an application where it provides more than one service, a practice known as application stacking. An example might be an application where you are using an energy storage system for both self-consumption and time-of-use bill management or demand reduction.

Table 3 illustrates the sensitivity of LCOS to the total number of cycles. According to Greg Smith, sonnen’s senior technical trainer, the retail price for a sonnenBatterie eco 6 is roughly $12,000, and installation costs (including relocating circuits to a protected-loads subpanel) are likely to fall in the $1,500–$3,000 range. Using conservative cost assumptions—and ignoring, for the moment, battery capacity losses over 10 years—we can see that the best-case LCOS varies dramatically depending on whether the user is full-cycling the battery once per day ($0.79/kWh at 3,650 cycles) or for maximum usage ($0.29/kWh at 10,000 cycles). While this is an extreme example of how the number of cycles relates to LCOS, this basic relationship holds for all energy storage applications. Anything less than 100% resource utilization drives up the LCOS.

It is worth noting that the best-case LCOS values in Table 3 do not take into account battery capacity losses over the life of the installation. In this case, sonnen does not publish a warranted maximum aggregate discharge value or provide any information about capacity retention over time. A simple way to account for the inevitable effects of battery degradation is to apply a capacity adjustment factor that accounts for battery aging and usage. In this case, sonnen’s warranty guarantees 70% of the original rated capacity after 10 years. If we assume that we reach 70% of capacity in the maximum cycling scenario and that capacity degrades linearly over time, then the average battery capacity over the 10-year period is 83.6%. For the daily-cycling application, we assume 0.5% of battery degradation per year due to aging and 1% due to usage, which works out to a 92.6% adjustment factor. If these assumptions seem overly optimistic or conservative, simply increase or decrease the adjustment factor accordingly.

Efficiency. Charging and discharging a battery incurs an internal cost. If you charge a battery from the grid during off-peak hours and discharge it on peak, you lose some amount of energy along the way. Conversion losses in both the battery and the inverter, as well as voltage drop losses in the conductors and electrical connections, occur during periods of active charging and discharging; the battery even has self-discharge losses when it is doing no work at all. The efficiency value in Equation 1 accounts for the fact that we do not get all of the energy out of a battery that we put into it.

These round-trip efficiency losses are significant in solar-plus-storage systems, especially in comparison to losses in an interactive PV system. Today’s non-isolated string inverters have weighted efficiencies in the 96%–98% range. By comparison, Tesla states that the “beginning of life” round-trip efficiency for its Powerwall is 92.5%. While round-trip efficiency data can be difficult to find—and third-party verified weighted data reflecting real-world scenarios do not exist—these losses depend somewhat on power processing and battery configuration.

SolarEdge and Fronius, for example, offer multiport inverters that work with high-voltage lithium-ion batteries such as Tesla’s Powerwall. In these systems, the PV array and battery both connect to the dc bus of a transformerless inverter, which is very efficient but provides modest surge capacity for motor loads. By contrast, Adara Power and sonnen have designed their energy storage systems around transformer-based inverter platforms (from Schneider Electric and Outback Power, respectively) that use a 48 V nominal battery bank. While these systems are somewhat less efficient, they offer excellent surge ratings for backup loads, which is critical to customers who need to run essential equipment—say, a well pump—during a power outage. To add solar to a sonnenBatterie, integrators must ac-couple an interactive inverter with the battery-based inverter via the ac bus in the backup-loads subpanel. The Adara Power system accommodates both ac- and dc-coupled configurations. The former is most cost-effective in retrofit applications where an existing interactive inverter can process PV power. The latter uses a 600 V Schneider charge controller to integrate the PV power source. SMA, meanwhile, is releasing a new Sunny Boy Storage inverter—designed especially with the retrofit market in mind—that will allow integrators to ac-couple solar with a high-voltage battery.

As the market matures, we will likely see increased demand for something parallel to an Energy Star rating method targeting home energy storage systems. This may be a long time coming in practice, however, based on the slow progress in the multiyear international efforts to develop comparative tests and ratings for PV modules. In the meanwhile, system integrators and developers may want to take vendors’ round-trip efficiency claims with a grain of salt. Self-reported efficiency values are suspect, if only because they likely reflect best-case scenarios. In the real world, inverter loading and battery cycling is highly variable, which could reduce round-trip system efficiency in the field.

Table 4 illustrates the sensitivity of LCOS to round-trip efficiency. In this example, we assume that Adara Power’s energy storage system, warranted for 10 years or 4,000 cycles, costs $11,500 fully installed, and that the PV system bears the cost of the charge controller or inverter processing power from the PV array. According to Adara, the round-trip efficiency of each battery charge and discharge cycle is 98%, which suggests that it has chosen to publish the efficiency value for the battery management system and battery chemistry. After all, the Schneider Electric XW+ 5548, which Adara uses in its systems, has a CEC efficiency rating of 93%. Moreover, the manufacturer-reported efficiency of Schneider Electric’s 600 V charge controller is 96% in a 48 V application. Based on these efficiency ratings, the best-case round-trip efficiency for a dc-coupled Adara Power solar-plus-storage system is roughly 87.5% (0.98 x 0.93 x 0.96). 

To estimate the round-trip efficiency for the ac-coupled configuration, we assumed that the interactive inverter is 96% efficient. We then looked at the battery-based inverter’s charging efficiency, which Schneider Electric describes in detail in its user manual for the XW+ 5548. In comparison to the inverting efficiency curve, the charging efficiency curve has a slightly lower peak value and a more pronounced downward slope. Based on a comparison of these curves, we estimate that the weighted average charging efficiency for the XW+5548 is roughly 91%. So in the ac-coupled solar-plus-storage configuration, we estimate that the round-trip efficiency is closer to 81.2% (0.96 x 0.91 x 0.93), which means the unsubsidized LCOS is about $0.04/kWh more than that for the dc-coupled configuration. While the storage component of a solar-plus-storage system does not automatically qualify for the 30% solar Investment Tax Credit (ITC), the post-ITC LCOS value in Table 4 illustrates the impact of the federal tax credit on qualifying systems.


As these case studies illustrate, you can use LCOS calculations to quickly compare energy storage solutions for a specific application or to evaluate the impact of changing certain design variables and assumptions. As useful as this may be, it is important to recognize that the LCOS metric has some limitations as a basis of comparison and a project assessment tool.

Cost vs. value. In late 2015, the financial advisory and asset management firm Lazard published a detailed cost comparison of various energy storage technologies in a wide variety of applications on both sides of the meter. “Lazard’s Levelized Cost of Storage Analysis—Version 1.0” (see Resources) not only models LCOS based on current technology prices, but also looks at how LCOS might change in the next 5 years based on projected capital cost decreases. While the authors compare the LCOS for various storage technologies, including lithium-ion batteries, to that of a gas peaker plant as a baseline, they also note that LCOS does not “purport to provide an ‘apples-to-apples’ comparison to conventional or renewable electric generation.”

This is true in part because cost tells only a piece of the story. An interactive PV system, for example, clearly has a lower levelized cost of energy than an energy storage system. However, the energy storage system can keep the customer’s lights on in the event of a power outage, which is very important to some customers. A cost-oriented metric such as LCOS does not capture that value. Similarly, some energy storage systems can support specific loads or applications that others cannot. For example, adding inverter capacity to a sonnenBatterie increases system costs and negatively impacts LCOS, but could improve the value proposition for the customer if the expanded system is able to power a deep-well pump in the event of an outage. Value-based considerations are very important when comparing energy storage systems, which residential applications often deploy as a means of improving service reliability. In many energy storage scenarios, the cheapest solution may not provide the best value.

Stacking revenue and benefits. Even if we exclude factors that are difficult to quantify in dollars and cents—such as reliability or environmental attributes—it is impossible to understand the value proposition for energy storage without considering the revenue side of the equation, which can quickly get complicated. In an ideal use case, an energy storage system provides multiple revenue-generating services via application stacking, as illustrated in Figure 4. Some of these revenue streams, including time-of-use and demand reduction savings, depend entirely on variable load profiles and utility tariffs. To model these revenues, you need access to specialized software, detailed interval meter data and a database of utility rate structures.

Perhaps the most important challenge facing residential energy storage is the need to unlock additional revenue streams, which is as much a policy problem for utility regulators as it is a technology problem for manufacturers and vendors. The authors of RMI’s report on battery economics note that when you use an energy storage system for a single application, such as self-consumption or backup power, that leaves something like 50%–99% of the battery capacity unused over the life of the system. The bad news, of course, is that resource underutilization leaves potential value on the table and increases the LCOS. The good news is that removing the regulatory barriers that prevent application and revenue stacking can tilt the economics in favor of behind-the-meter energy storage.

Green Mountain Power’s pilot program offering Tesla Powerwall batteries to its customers is a good example of how an innovative utility can leverage additional value from residential energy storage systems. According to public filings, the utility estimates that its net present value for a leased Powerwall is roughly $50 per system per month over a 10-year term. (A $37.50 per month customer fee offsets the additional monthly costs associated with the Powerwall deployments.) To create this revenue stream, the utility will discharge the Powerwall batteries during “times of high market prices to help lower its energy costs,” as well as during “times of peak load to reduce significant capacity and transmission expenses.” Green Mountain Power expects that in addition to providing backup power for end users, the Powerwall deployments will “smooth grid impacts caused by a high penetration of solar energy, potentially avoiding more expensive, traditional upgrades.” The company is also deploying 10 additional units as part of a pilot microgrid project, which will “contribute to improving the reliability of the Rutland 46 kW subtransmission network during system contingencies.”

While current business models typically leverage one or two use cases for energy storage, RMI identifies “thirteen fundamental electricity services” that can benefit “three major stakeholder groups” (system operators, utilities and end users). The report also notes that “the further downstream battery-based energy storage systems are located, the more services they can offer to the system at large.” Utilities can even aggregate a network of residential energy storage systems and operate this as a virtual power plant. At the end of the day, grid parity for energy storage is more about leveraging and monetizing these many value streams than it is about achieving a LCOS lower than the retail price of electricity.


Matthias B. Krause / Berkeley, CA / matthiasbkrause [AT]

David Brearley / SolarPro / Ashland, OR /


GTM Research and the Energy Storage Association, “US Energy Storage Monitor: 2015 Year in Review,” March 2016,

GTM Research and the Solar Energy Industries Association (SEIA), “US Solar Market Insight: 2015 Year in Review,” March 2016,

Lazard, “Lazard’s Levelized Cost of Storage Analysis—Version 1.0,” November 2015,

Rocky Mountain Institute, “The Economics of Battery Energy Storage,” October 2015,

Rocky Mountain Institute, “The Economics of Grid Defection,” February 2014,

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For decades, off-grid battery-based energy storage systems powered by PV or other renewable energy sources such as wind and small-scale hydroelectric turbines have been cost-effective for many rural and remote residences across the US. The financial case for deploying energy storage in residential grid-connected applications has been a more difficult one to make. However, technological advancements, constrained electric grids with high penetrations of PV systems and the gradual erosion of net energy metering programs across the US may usher in a new era for distributed, grid-connected energy storage systems.

Numerous manufacturers are banking on the expected proliferation of highly integrated, customer-sited energy storage systems. This article provides manufacturer and product line overviews for 14 power electronics and battery system vendors that are positioning themselves for the new energy storage market. Some of the companies, or current incarnations of them, were foundational to the US solar industry a decade before grid-tied systems began to gain popularity. Others are recent entrants to energy storage and solar energy. And a third group of established solar power electronics manufacturers are reimagining their products for modern energy storage applications.

Adara Power

Founded in 2013, Adara Power (formerly JuiceBox Energy) develops lithium-ion energy storage systems layered with monitoring and control software for peak shift, load shave and backup power applications. As of early June 2016, it has units deployed in seven US states. Adara aims to ramp up the adoption of its energy storage technology in key markets, including Hawaii, Nevada and California, via its Adara Energy Storage System Certified Installer program.

At the core of Adara’s 8.6 kWh residential Energy Storage System (ESS) are Samsung lithium nickel manganese cobalt oxide (NMC) cells, configured to operate at 50 Vdc nominal. Adara specifies a rated energy capacity of 8.6 kWh, 5.5 kW continuous power output and a round-trip battery charge and discharge cycle efficiency of 98%. Rated power at a C/2 discharge rate per the California Self-Generation Incentive Program (CA SGIP) is 4 kW. The Adara energy storage system uses a web-enabled interface that allows homeowners to monitor real-time and historical system performance. Integrators have access to 140 battery, inverter and charge controller parameters for remote system diagnostics. Safety protection includes over-voltage and over-temperature shutdown, three-level redundancy on over-voltage control, eight independent temperature measurements and autonomous operation of the product’s safety systems if web connectivity is lost. The system’s battery is certified to UL 1642, and has a specified minimum life of 10 years.

The Adara ESS is compatible with the Schneider Electric XW+ 5548 inverter/charger. Designs can dc- or ac-couple solar arrays to the Adara system. While system designers should verify available support and warranties for ac-coupling products from different manufacturers, integrators have deployed ac-coupled Adara systems with various string inverters, including products from SMA America and SolarEdge.

Adara Power • Milpitas, California • 844.223.2969 •

concept by US

Based in Pompano Beach, Florida, and founded in 2012, concept by US has developed a scalable utility-interactive energy storage system, the Powerstation 247, for residential and small business backup power and self-consumption applications. The product line is ETL listed to UL 1741. Concept by US reports that  it designs and manufactures all the product’s main components in house, with the exception of the system’s lithium iron phosphate (LiFeYPO4) batteries. This is a high degree of vertical integration for a relatively young company.

The Powerstation 247 integrates up to three 5 kW Powermodule hybrid inverters, MPP trackers, charge control, batteries and all required field wiring terminals, disconnects and overcurrent protection in a NEMA 1 enclosure intended for indoor environments. Regardless of the number of Powermodules it includes, the Powerstation 247 employs 17.28 kWh of battery storage configured for a nominal dc bus voltage of 96 Vdc (93–105 Vdc operating voltage range). The battery is ETL certified to UL 1642.

Each Powermodule includes two MPP trackers along with PV wiring terminals and disconnects integrated with the unit’s enclosure. Electrical specifications for each PV input are 500 Vdc maximum, 180–500 Vdc operational voltage range, 240–400 Vdc MPPT range and 3,000 W maximum power per PV input channel. The Powerstation 247 is available with one, two or three Powermodules for ac power outputs of 5 kW, 10 kW and 15 kW, respectively. AC output in both grid-tie and stand-alone modes is 120/240 Vac. The Powerstation 247 has a 5-year warranty.

concept by US • Pompano Beach, Florida •

Eguana Technologies

Eguana Technologies designs and manufactures power electronics for distributed smart grid and microgrid applications. Founded in 1999, Eguana initially focused on developing low-voltage inverters for utility-interactive fuel cell systems. It launched its first-generation Sunergy inverter in 2010 and second-generation Paralex inverter for thin-film PV applications in 2012. In 2014, Eguana introduced its Bi-Direx inverter for grid-tied energy storage systems. The inverter’s initial target was the European energy storage market, where it shipped more than 4,000 units in 2014–2015. In 2015, Equana launched the AC Battery, an integrated battery-ready power electronics platform for solar self-consumption and backup power applications, in the North American market.

The flexibility of Eguana’s AC Battery system allows for integration with diverse storage technologies that include LG Chem’s lithium-ion batteries, Aquion Energy’s saltwater electrolyte Aqueous Hybrid Ion products and Primus Power’s flow batteries, as well as VRLA lead-acid battery models from various manufacturers. Eguana manufactures five Bi-Direx inverter models. Developed for the US market and certified to UL 1741, the B5048US model is designed to integrate with 120/240 Vac 60 Hz electrical services. On the dc side, the B5048US has a nominal voltage of 48 Vdc and an operating range of 40–66 Vdc.

The standard AC Battery configuration couples Eguana’s Bi-Direx inverter with LG Chem M4860P2S2 lithium-ion batteries configured at 48 Vdc nominal (42–58 Vdc operating range) for use with the AC Battery product. Five battery storage system capacities are available with ratings at C/1 of 6 kWh, 9 kWh, 12 kWh, 15 kWh and 18 kWh. The batteries are rated for 4,000 cycles at 90% depth of discharge (DOD), 25°C and C/1. Users can ac-couple solar arrays to the system via third-party string or microinverters, which perform system MPP tracking and array dc-to-ac conversion. The system's SunSpec-compliant Modbus communications interface integrates with third-party energy management systems and gateways that enable self-consumption functionality. Eguana Technologies’ AC Battery carries a standard 10-year warranty.

Eguana Technologies • Calgary, Alberta, Canada • 403.508.7177 •

Enphase Energy

Founded in 2006, Enphase Energy is largely responsible for creating the modern microinverter product class. With an eye toward current and projected changes in net energy metering programs and policies that limit exporting solar energy to the grid in the US and beyond, Enphase developed its AC Battery for global markets that benefit from or require self-consumption functionality or energy time-of-use optimization. After announcing the product in October 2015, Enphase began marketing the current design in February 2016 and expects US availability in late 2016.

The AC Battery is a scalable, modular energy storage system. Designs can ac couple it with Enphase’s microinverters and module-level online monitoring platform. Enphase also designed the AC Battery for compatibility with any grid-tied system, regardless of the brand and model of a given system’s inverter or modules, with the addition of its Envoy-S Metered gateway and Enlighten monitoring products.

The Enphase AC Battery uses lithium iron phosphate cells configured to provide 1.2 kWh of capacity. It can discharge to greater than 95% of rated capacity and has a round-trip cell efficiency specification of 96%. Weighing only 55 pounds, the AC Battery is designed for single-person installation and interconnection with standard household wiring. Its enclosure is NEMA 2 rated for indoor installation in an unoccupied space. Certifications to UL 1741, UL 1973 and UL 9540 are pending. The AC Battery carries a 10-year or 7,300 cycle warranty for greater than 80% of its initial rated capacity.

Enphase Energy • Petaluma, California • 877.797.4743 •

Fronius USA

Founded in 1945 in Pettenbach, Austria, as a welding equipment manufacturer, Fronius today focuses on products and systems for welding, battery charging and solar energy applications. Fronius USA is headquartered in Portage, Indiana, where it develops and manufactures string inverters and related equipment for the US solar market. In 2014, Fronius began rolling out its SnapINverter generation of single and 3-phase string inverters for solar projects in North America.

Fronius gained its early experience with power electronics for energy storage applications in the European self-consumption market, where the company combined its long history in battery charging– equipment design and manufacturing with its solar product development efforts. With established availability in Europe, the Fronius Energy Package includes a Fronius Symo Hybrid multiport inverter, a lithium iron phosphate Fronius Solar Battery and a Fronius Smart Meter to monitor system energy flow.

In 2015, Fronius shared the headlines with Tesla as one of two inverter manufacturers developing a high–dc-voltage multiport inverter for integration with Tesla’s Powerwall Home Battery. Fronius’ initial relationship with Tesla stems from the welding systems it supplies for manufacturing Tesla electric vehicles. Scheduled for a Q4 2016 release, Fronius’ first dc-coupled storage system for the US market is its multiport Primo Hybrid. The Tesla-compatible inverter will be available in power classes ranging from 5 kWac to 11.4 kWac and will feature three dc inputs: two solar MPP trackers and one battery input. The MPP trackers’ input voltage range is 80–600 Vdc. For seamless integration with Tesla’s Powerwall battery, the inverter’s dc bus operates at 350–450 Vdc. Both the Fronius Primo Hybrid inverter and the Tesla Powerwall battery are rated for outdoor installations.

Fronius has also partnered with JLM Energy to integrate Fronius inverters with JLM’s lithium iron phosphate battery systems, as well as its products that monitor and control self-consumption and energy time-of-use optimization. JLM’s battery products and the Fronius inverters communicate via the SunSpec-compliant Modbus RTU interface. JLM’s residential solutions couple Fronius’ standard Primo inverter with JLM’s Energizr 200 storage system to create an integrated system for self-consumption, peak shaving and load shifting applications.

Fronius USA • Portage, Indiana • 219.734.5500 •

JLM Energy

Based in Rocklin, California, JLM Energy designs and manufactures products for energy storage, management and control. It specializes in proprietary software developed in-house for automation and component integration. Founded in 2011, JLM Energy has two core products for residential applications—the Energizr 100 and the Energizr 200. Both use specific configurations of the JLM Battery Pack. Each lithium iron phosphate (LiFePO4) battery pack has a nominal voltage of 52 Vdc, a nominal capacity of 50 Ah, and an operating voltage range of 40–57.6 Vdc. JLM specifies a cycle life of 3,000 cycles at 80% DOD and discharge under 25°C, and a cycle life of 5,000 cycles at 50% DOD and discharge under 25°C. The Energizr 100 uses four Battery Packs configured in parallel for a nominal operating voltage of 52 Vdc and a capacity of 10.4 kWh. The higher-capacity Energizr 200 accommodates up to eight Battery Packs in series for a nominal voltage of 416 Vdc and a storage capacity of 20.8 kWh.

JLM developed the Energizr 100 primarily as a grid-independent system for backup power applications. Its design allows installers to integrate the battery system with a residence’s grid-direct PV system string inverter, electrical loads, the utility grid and even a backup ac generator. During a utility outage, the product creates a local microgrid that allows the grid-tied inverter to continue to generate energy for battery charging. If the grid is unavailable and the battery is at a full state of charge, the Energizr 100 regulates battery charging. In backup mode, the product has a continuous output power rating of 4,400 W and a 5-second surge of 8,500 W. The Energizr 100 is also compatible with AGM, gel and flooded lead-acid battery types. Measurz, JLM Energy’s cloud-based monitoring platform, monitors the system in real time.

The more feature-rich Energizr 200 offers peak load shaving and integrated support for smart thermostats, real-time whole-house power measurement and load control. JLM’s Measurz software analyzes user habits and provides efficiency recommendations for homeowners. The mobile app enables remote control of appliances, including HVAC systems and smart thermostats.

JLM Energy • Rocklin, California • 916.304.1603 •

Magnum Energy

Magnum Energy, founded in 2006, designs and manufactures inverter/chargers for mobile, marine, off-grid and backup power applications, as well as PV charge controllers, component integration panels and system monitoring equipment. The company’s DNA goes back to the formation of Trace Engineering in Arlington, Washington, in 1984. In 2014, Sensata Technologies, a supplier of sensing, electrical protection, control and power management solutions, acquired Magnum.

Magnum was the first manufacturer to offer inverter/charger models with split-phase 120/240 Vac output in the US. Magnum designed its MS-PAE series of inverter/chargers to connect to the grid for ac battery charging, but never chose to develop utility-interactive models that export power to the utility grid without the integration of an ac-coupled third-party string or microinverter system. In hindsight, this was an interesting choice given the current shift to non-exporting PV systems in some US markets.

The MS-PAE 120/240 Vac series inverter/chargers are available in 24 Vdc and 48 Vdc nominal versions. The 48 Vdc MS4448PAE model has a continuous power rating of 4,400 W and surge capability to power larger inductive loads such as well pumps. The MS4448PAE has a 5-second surge rating of 8,500 W, a 30-second surge rating of 6,000 W, a 5-minute surge rating of 5,400 W and a 100-millisecond surge current rating of 40 Aac line-to-line. In 2015, Magnum launched its PT-100 solar charge controller, which is compatible with 12, 24 and 48 Vdc nominal battery systems and has a maximum output power rating of 6,600 W. Its maximum input voltage is the lower value of either 200 Vdc plus battery voltage or 240 Vdc. The PT-100 controller also provides GFDI and AFCI circuit protection. Magnum offers an extensive line of prewired Magnum Panels and accessories for component integration.

In 2016, Magnum announced its MicroGT 500 microinverter. Designed for integration with the company’s battery-based inverter/charger systems, as well as for use in grid-direct power export applications, the MicroGT 500 communicates seamlessly with Magnum Energy battery-based inverters in ac-coupled mode to taper charging based on temperature-compensated battery state of charge (SOC) parameters. Each dual-MPPT microinverter supports two PV modules. Magnum’s ECU communication interface allows system owners and integrators to monitor system PV production via a web-based dashboard.

Magnum Energy • Everett, Washington • 425.353.8833 •

OutBack Power

OutBack Power is a manufacturer of power electronics for battery-based renewable energy applications including solar, wind, microhydro and utility-interactive systems. Engineers integral to the early success of Trace Engineering—and the company’s SW series inverter/charger that became an early staple for battery-based renewable energy, backup and utility-interactive systems-—launched OutBack in 2001. In 2010, the Alpha Group acquired OutBack Power.

OutBack’s flagship power conversion products, the FX series inverter/charger and MX series solar charge controllers, have evolved over the years. The current FXR/VXFR series of grid/hybrid inverter/chargers offer stand-alone, backup and utility-interactive solar export functionality. The FXR/VXFR line features seven operational modes, including GridZero, which prioritizes the use of battery or renewable sources to power loads and uses renewable energy sources such as PV only to recharge a system’s battery pack. An Advanced Battery Charging profile option supports lithium-ion battery technologies. The 60 A and 80 A FLEXmax models, the successors to OutBack’s original MX60 MPPT solar charge controllers, operate at dc voltages up to 150 Vdc.

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. The 8,000 W GS8048A and the 4,000 W GS4048A have a 100-millisecond maximum output current rating of 70.7 Aac and 35.4 Aac, respectively. These models also include OutBack’s GridZero mode and Advanced Battery Charging option.

Since its launch, OutBack has focused development efforts on system integration packages that allow prewiring and testing at certified facilities to reduce installation time and complexity in the field. OutBack’s current SystemEdge prebundled equipment packages build on this early component integration focus. With the introduction of four VRLA storage batteries optimized for specific applications such as float service or regular deep cycling, as well as integration with its power conversion equipment, OutBack now offers an extensive product family for energy storage applications listed to the relevant UL standards from end to end.

OutBack Power • Arlington, Washington • 360.435.6030 •

Pika Energy

Headquartered in Westbrook, Maine, and founded in 2010, Pika Energy manufactures bidirectional inverters, solar charge controllers, substring solar optimizers and small wind turbines. Pika’s patented bidirectional REbus DC nanogrid, a 380 Vdc (360–440 Vdc operating range) dc bus, enables power transmission, control and data functions to share the same conductors via powerline carrier communication (PLC). Pika Energy developed its Pika Energy Island system to provide residences and small businesses with a single inverter solution for backup power, self-consumption and demand charge reduction functionality. The Energy Island uses two Pika products, its X7601 Islanding Inverter and Pika’s PV Link dc optimizer, as building blocks for the system.

The Pika Energy X7601 is a 7.6 kW bidirectional inverter that connects PV, energy storage, electrical loads and the grid, and supports 120/240 Vac critical loads without requiring an autoformer. Pika designed its inverter to leverage the efficiency advantages provided by a high-voltage 380 Vdc bus used in conjunction with lithium-ion batteries. However, the inverter can also integrate with 48 Vdc nominal lead acid batteries as well as Aquion Energy’s AHI energy storage products. The X7601 inverter has a power rating of 7,600 W in grid-export mode and an 8,000 W continuous power rating with a 12 kW 10-second surge in stand-alone mode. It is certified to UL 1741, meets Rule 21 requirements and carries a 10-year standard warranty extendable to 20 years.

Pika Energy’s PV Link S2501 subarray PV optimizer supports the creation of 380 Vdc nominal arrays compatible with its 7.6 kW bidirectional inverter and 380 Vdc system bus. The PV Link can interconnect two to nine modules to create subarrays of up to 2,500 W. The product is rapid-shutdown compliant and provides MPP tracking (60–360 Vmp range), shade mitigation, ground-fault protection, arc-fault protection and substring monitoring via PLC. Pika Energy backs its PV Link subarray optimizers with a 25-year limited warranty.

Pika Energy • Westbrook, Maine • 207.887.9105 •

Schneider Electric

Schneider Electric’s roots date back to 1836 when two brothers, Adolphe and Eugene Schneider, acquired mines, forges and foundries and became part of the Industrial Revolution. At the time, the company’s main markets were heavy industry, railroads and shipbuilding. Today, Schneider Electric is a global manufacturer of power distribution and automation systems. Headquartered in Rueil-Malmaison, France, Schneider entered the solar industry with its 2008 acquisition of Xantrex Technologies (Xantrex acquired Trace Engineering in 2000).

Schneider offers two inverter/charger lines suitable for residential energy storage applications. For nonexport systems, its Conext SW-NA hybrid inverter/charger line offers models with nominal dc input voltage of 24 Vdc or 48 Vdc and continuous output power classes of 2,400 W and 3,400 W at 24 Vdc and 3,800 W at 48 Vdc. The inverter/chargers have split-phase 120/240 Vac output and are compatible with flooded and VRLA lead-acid battery types. The Conext SW-NA supports ac- and dc-coupled configurations and enables grid backup, self-consumption with solar prioritization, peak shaving and ac engine generator assist.

The more feature-rich utility-interactive Schneider Conext XW+ NA inverter/charger line was one of the first to support integration of lithium-ion battery types. As such, complete energy storage hardware and software solutions from other vendors commonly integrate with this equipment. Like Schneider’s Conext SW-NA inverter/chargers, the Conext XW+ NA supports ac- and dc-coupled configurations and enables grid backup, self-consumption with solar prioritization, peak shaving and ac engine generator assist. It can also export power to the utility grid.

Schneider offers system integration panels for its inverter/chargers, as well as two MPPT solar charge controllers that customers can network with the overall power electronics system. The MPPT 60 150 controller has a maximum PV array open-circuit voltage rating of 150 Voc and a maximum output power rating of 3,500 W. The MPPT 80 600 model has a maximum PV array open-circuit voltage rating of 600 Voc and a maximum output power rating of 4,800 W at 48 Vdc nominal. Schneider Electric’s MPPT charge controllers carry a standard 5-year warranty. Its Conext SW-NA and XW+ inverter/chargers carry a 2- to 5-year warranty, depending on the country of installation.

Schneider Electric • Andover, Massachusetts •

SMA America

Founded in 1981, SMA Solar Technology has its global headquarters in Niestetal, Germany, and its US division is headquartered in Rocklin, California, with a US production facility in Denver. SMA was the first manufacturer to offer high-voltage string inverter models in the US market. It also pioneered the use of ac-coupling grid-direct string inverters with battery-based inverters and energy storage, a configuration common to many of the systems highlighted in this article. SMA has significant experience with self-consumption and energy storage systems in Europe and plans to offer additional equipment, such as its Energy Meter, in the US as markets develop.

SMA America offers single-phase Sunny Boy string inverter models, in power classes from 3,000 W to 11,000 W, that are suitable for ac-coupled residential PV applications. It also offers two models of its Sunny Island battery-based inverter/chargers—the 4548-US and 6048-US, with rated power outputs of 4,500 W and 5,750 W, respectively. SMA designed both models for operation with 48 Vdc nominal battery banks. They are compatible with lead-acid, nickel-cadmium and lithium-ion battery types as well as external battery management systems. Sunny Island inverter/chargers have single-phase 120 Vac output. Split-phase 120/240 Vac applications require two Sunny Island inverters or an autoformer.

In ac-coupled utility-interactive systems where one or more Sunny Boy inverters are connected to the ac side of a battery-based Sunny Island system, the Sunny Island limits string inverter output power via frequency shift if the batteries are at a full state of charge and the grid is unvailable. The Sunny Boy string inverter identifies and analyzes the frequency adjustment. When the power frequency increases and exceeds a defined value, the Sunny Boy limits its power accordingly. The result is well-regulated and optimized battery charging.

SMA plans to release a high-voltage Tesla-compatible battery-based inverter for the US market in early 2017. Coupled with SMA’s energy-management platform, the power electronics and storage energy solution will enable streamlined integration with existing PV systems as well as cost-effective new solar-plus-storage projects.

SMA America • Rocklin, California • 916.625.0870 •

SolarEdge Technologies

Founded in 2006, SolarEdge Technologies began commercial shipments of its string inverter, module-level dc optimizer and monitoring systems in 2010. The company’s global headquarters are in Herzliya, Israel, and its US division is headquartered in Fremont, California. SolarEdge was one of two inverter manufacturers participating in the PR wave that announced Tesla’s lithium-ion Powerwall Home Battery and is the first inverter manufacturer to have fielded Powerwall systems in the US.

SolarEdge’s single-inverter StorEdge system has four primary components. The system’s single-phase StorEdge dual-port inverter and Connection Unit functions as an optimized PV inverter that also provides power conversion and management for battery charging. Tesla’s 6.4 kWh lithium-ion Powerwall Home Battery provides energy storage. A 120/240 Vac split-phase autoformer performs phase load balancing in StorEdge systems configured for backup power during grid interruptions. Finally, the addition of SolarEdge’s Electricity Meter enables smart energy management functionality that includes export power control, time-of-use shifting, maximized self-consumption, demand response and peak shaving capabilities.

The StorEdge inverter for the US market, model SE7600A-USS, has a rated ac power output of 7,600 W and a maximum ac power output of 8,350 W when feeding electrical loads or exporting to the grid. In backup mode, it has a rated power output of 5,000 W and a maximum 10-second ac surge rating of 7,600 W. The inverter’s nominal dc bus voltage is 400 Vdc. SolarEdge’s StorEdge inverter and module-level dc optimizers provide NEC 2014 Section 690.12 rapid-shutdown functionality for the PV array and battery. StorEdge system’s Electricity Meter carries a 5-year warranty. Its autoformer and inverter carry a 12-year warranty, with an option to extend that to 25 years on the StorEdge inverter.

SolarEdge Technologies • Fremont, California • 510.498.3200 •


With corporate headquarters in Bavaria, Germany, and US headquarters in Los Angeles, sonnen has deployed more than 10,000 of its sonnenBatterie–integrated energy storage systems, primarily in European self-consumption markets. Founded in 2008, sonnen announced availability of its sonnenBatterie eco and sonnenBatterie pro models for the US market in December 2015. One element of sonnen’s long-term vision for its business is a virtual power plant model, the sonnenCommunity, that aggregates customer-sited sonnen energy storage systems and monetizes the pooled stored energy capacity and associated grid resources.

The sonnenBatterie eco energy storage solution, designed for residential self-consumption and grid backup applications, integrates power electronics, Sony Fortelion lithium iron phosphate (LiFePO4) cells, and proprietary management and monitoring software. The eco comes in seven energy storage capacity options, ranging from 4 kWh (eco 4 model) to 16 kWh (eco 16 model) in 2 kWh increments, with a usable capacity based on a 100% cell DOD. sonnen has configured the lithium iron phosphate cells for a low-voltage dc bus with an operational range of 48–56 Vdc. The company warranties the eco system’s batteries for 10 years or 10,000 cycles.

The eco system has a split-phase 120/240 Vac output and can be ac coupled with existing or new PV installations. In stand-alone mode, the eco 4 through eco 8 models have a 100-millisecond maximum power rating of 8,500 W and a 5-second maximum power rating of 6,000 W. The higher-capacity models, the eco 10 through eco 16, have a 100-millisecond maximum power rating of 17,000 W and a 5-second maximum power rating of 12,000 W. Non–revenue grade PV and load metering is standard. The sonnenBatterie eco system’s power electronics are certified to UL 1741 and carry a 10-year standard warranty.

sonnen • Los Angeles • 310.853.2404 •


Headquartered in San Francisco, Sunverge was founded in 2009. In February 2016, it announced its second-generation Solar Integration System (SIS) energy storage platform, with a streamlined design, more battery options and greater system intelligence than the original SIS. While other vendors offer fully integrated system packages for residential and small business storage systems that couple power electronics with lithium-ion batteries and are certified to the relevant UL standards, Sunverge has a forward-looking vision for its SIS product, with the goal of aggregating reserve energy from every SIS system under management and pooling it in the cloud. The resulting virtual power plants of cloud-aggregated SIS units would provide utilities and third parties a pooled resource they could monetize and use to balance grid demands.

Sunverge’s current SIS product integrates lithium-ion batteries, power electronics and cloud-based management software in a single enclosure with options for indoor or outdoor installation. It supports multiple lithium-ion battery chemistries and storage capacities from 6 kWh to 25 kWh. For residential installations, its power electronics package interconnects with split-phase 120/240 Vac services. It is designed to ac-couple existing or new PV systems of up to 8 kWdc, with options to support larger secondary systems.  Operational modes include backup, self-consumption, self-consumption with grid leveling, time-of-use optimization and peak shifting. The Sunverge SIS is certified to UL 1741 and UL 1778 and carries a 10-year standard warranty.

Sunverge • San Francisco • 415.795.3660 •


Joe Schwartz / SolarPro / Ashland, OR /

Primary Category: 

According to conference organizers the Solar Energy Industries Association and the Solar Electric Power Association, more than 1,100 exhibitors are expected to showcase their goods and services at Solar Power International 2012 in Orlando, Florida. This presents a familiar challenge for the 20,000-plus conference attendees. In 2009, the number of exhibitors at SPI more than doubled over the previous year’s total—increasing from 425 to 929—and that number has exceeded 1,100 each year since then. This means it is impossible to visit every booth and very difficult to canvass every aisle in the exhibit halls.

With this in mind, SolarPro technical editors have compiled a short-list of exhibitors with particularly interesting products and services that will be on display in Orlando. This list includes some equipment that was showcased at Intersolar North America in July, as well as products that will be launched at SPI 2012. The list is by no means comprehensive, as many announcements and releases scheduled for Orlando are under embargo until the conference starts. However, some companies were willing to share embargoed news items with us before the conference, in part because of some fortuitous scheduling: SPI 2012 coincides with the advanced ship date for the October/November issue of SolarPro magazine.

So for those of you reading this article at the conference, we have included booth numbers for each of the companies profiled. If the product or service described here looks like it could solve problems for you, you can walk on over to the company’s booth and learn more about it. For those of you reading the article after the conference, this article can serve as a recap of equipment highlights.

In either case, look for additional post-conference coverage in “The Wire,” our department featuring new and noteworthy items, in the December/January 2013 issue of SolarPro magazine. In fact, if you attend the conference and see something that you think is a game changer or a time-saver, email us at If you are excited about a product or service, chances are other readers will be as well.


Advanced Energy has added a new central inverter and four non-isolated (transformerless) string inverter models to its product lineup. The AE 500, a 500 kW inverter developed for utility-scale solar plants, features an integrated dc circuit breaker subcombiner, a CEC-weighted efficiency of 97%, and a full power rating up to 55°C. The inverter includes an integrated gateway compatible with monitoring software from providers including AlsoEnergy, ArgusON, DECK Monitoring, Draker, ESA Renewables, Locus Energy, meteocontrol and Noveda Technologies. Advanced Energy’s recently released non-isolated string inverter line includes 3.8–7.0 kW models with field-configurable output voltages of 208, 240 or 277 Vac.

Advanced Energy / 800.446.9167 /

DPW SOLAR  Booth 1133

DPW Solar has added a new ground-mount racking solution to its product suite and has made significant improvements to its CRS ballasted system. The Power Peak ground mount is designed to reduce installation time and allow the racking system to conform to site-specific requirements. The structures are specified to match string layouts, and the module rails include wire channels to protect source-circuit conductors and speed the overall installation. The new CRS G2 ballasted racking system improves on the previous design with integrated grounding that meets the UL 467 standard, a reduced parts count to cut down on installation time, and a modular design that simplifies the roof layout.

DPW Solar / 505.889.3585 /

EATON  Booth 3701

As the new fuse-servicing disconnect requirements in Section 690.16(B) of NEC 2011 take effect, combiner and inverter manufacturers are more likely to utilize circuit breakers in place of fuses in products designed for commercial and utility applications. With the introduction of the PVGard line of circuit breakers, Eaton is the first manufacturer to meet the requirements contained in UL 489B, a new product standard developed specifically for molded-case circuit breakers and switches intended for use in PV systems. Products in the PVGard family are rated for 100% continuous current at 50°C and for use at up to 1,000 Vdc. The product line will include current ratings from 30 A to 600 A.

Eaton / 800.386.1911 /


Ecolibrium Solar has launched a fully redesigned polymer-based mounting solution for ballasted and hybrid ballasted and mechanically attached arrays deployed on commercial low-slope rooftops. The Ecofoot2 product utilizes an acrylonitrile styrene acrylate (ASA) Luran material manufactured by Styrolution, a BASF company. The total installed system weight ranges from 3 to 5 psf. Array tilt angle is 5° when modules are installed in portrait configuration and 10° with modules in landscape format. The product includes integrated module grounding and wire management. Interior wind deflectors minimize uplift forces and reduce overall ballast requirements. The product carries a 25-year warranty and is suitable for roofs with pitches of 0°–5°.

Ecolibrium Solar / 740.249.1877 /

FRONIUS USA  Booth 1957

In addition to its 3.0–11.4 kW single-phase string inverters, Fronius USA offers several solutions for small and large commercial-scale projects. Its 3-phase string inverter line includes three models. The 10.0-3 and 11.4-3 units have ac output voltages of 208/240 delta and are rated at 10 kW and 11.4 kW, respectively. The 12 kW 12.0-3 product is configured for 277 Vac wye output. Fronius’ 3-phase CL inverter line is based on the company’s MIX Concept, which offers a modular design based on up to 15 identical power stages. Models include 33.3, 44.4 and 55.5 kW units with 208/240 Vac delta output and 36, 48 and 60 kW units with 277 Vac wye ac output configurations.

Fronius USA / 810.220.4414 /


The newest addition to the KACO blueplanet inverter line is the 10 kW non-isolated (transformerless) XP10U-H4. The inverter’s non-isolated design results in a lightweight product that weighs in at 88 pounds. The CEC-weighted efficiency of the XP10U-H4 is 97%, and ac and dc surge protection is standard. Dual MPPT channels that operate between 200 and 600 Vdc allow integrators to maximize available roof space by utilizing asymmetrical string lengths or by installing modules with varying tilt and orientation values. The inverter’s integrated web server includes multiple data-interface options for access to the easyLINK monitoring services offered by KACO. A graphical user interface facilitates inverter commissioning and provides user-friendly access to inverter data.

KACO new energy / 415.931.2046 /


Drawing on the company’s experience as a manufacturer and distributor of specialty fasteners for the commercial roofing industry, OMG Roofing Products has developed the PowerGrip roofmount system for solar mounting on low-slope roofs. The PowerGrip solution is compatible with thermoplastic roofing membranes, such as TPO and PVC, and supports many membrane types, thicknesses and brands. Mechanical connection to the roof deck or structure is accomplished using an appropriate fastener. The PowerGrip assembly then slides over the head of the fastener. Afterward, the integrated manufacturer-specific flange is heat-welded to the roof membrane. These mechanical connections are rated for 305 pounds each and reduce ballast material needs.

OMG Roofing Products / 800.633.3800 /


The Radian Series GS8048 inverter/charger from OutBack Power provides system integrators with a powerful and scalable platform for off-grid and utility-interactive battery backup systems. Each Radian GS8048 supplies 120/240 Vac and is capable of providing 8,000 watts of continuous power and supporting high surge loads for shorter durations. For larger systems, up to 80 kW continuous, the ac inputs and outputs of up to 10 GS8048 inverter/ chargers can be connected in parallel using standard ac distribution panels. Each unit supports dual ac inputs—for the utility grid and a backup generator— and will accommodate an integrated BOS load center. Prewired options are available.

OutBack Power / 360.435.6030 /

PANELCLAW  Booth 3331

PanelClaw has added the Kodiak Bear mounting system to its portfolio of ballasted racking products. The new system is available in 10° and 15° tilt angles and utilizes proprietary, hydraulically compressed ballast that integrates with the racking system. The total array platform load, including racking, ballast and modules, ranges from approximately 3.5 to 9 psf. Modules are installed in landscape format. The Kodiak Bear product includes wind deflectors, rubber roof-membrane protection pads and integrated wire management. The solution is suitable for low-slope roof applications with a maximum pitch of 5° and is covered by a 10-year standard warranty.

PanelClaw / 978.688.4900 /

POWER-ONE  Booth 1749

Power-One is releasing two microinverters targeted for the US market rated at 250 W and 300 W. Both models are designed to connect to 240 Vac or 208 Vac electrical circuits. The inverters’ high-frequency transformer allows installations with modules that require grounding of either pole on the dc input side. Power-One offers a wireless communication hub, the Aurora CDD, which can support up to 30 microinverters. New string inverters from Power-One include the Aurora Uno, designed for residential and small commercial installations, and the Trio line, with 3-phase ac output for connection to commercial services. Both string inverter lines include models with or without isolation transformers.

Power-One / 805.987.8741 /

QUICK MOUNT PV  Booth 3062

Roof-mount manufacturer Quick Mount PV has launched two products for tile roof applications. The Quick Hook Curved Tile Mount and Quick Hook Flat Tile Mount are the first fully flashed tile-hook mounts on the market. Engineered for code-compliant, watertight mounting, both the curved and flat tile models use the same tile hook, which mates with the product’s base. The Quick Hook Curved Tile Mount has an extrawide base, allowing the installer to choose from multiple clearance holes to attach two lag screws to the rafter. A slot in the base enables the hook to slide into position to match the curve of the tile.

Quick Mount PV / 925.478.8269 /

REFUSOL  Booth 1721

REFUsol offers four UL-listed and CEC-eligible nonisolated 3-phase string inverters developed for small and large commercial projects and designed for 480 Vac grid interconnection. The inverters are manufactured in Greenville, South Carolina, and are Buy American Act compliant. The 12, 16, 20 and 23.2 kW units feature a wide MPPT range of 125 to 450 Vdc, CEC-weighted efficiencies of up to 98% and weigh in at 108 pounds. REFUsol partnered with Obvius to develop a Modbus monitoring solution that allows integration with third-party software provided by Also-Energy, ArgusON, DECK Monitoring, Draker, Locus Energy and Noveda Technologies, in addition to the company’s standard REFUlog monitoring platform.

REFUsol / 866.774.6643 /


Renusol America has added to the CS60 product line with the introduction of the 10° mounting system. The CS60 ballasted rack is a one-piece mounting solution where each module is mounted directly to a single CS60 base. The universal base is compatible with all common module dimensions. The system is made of nonconductive high-molecular-weight polyethylene, eliminating the need for equipment grounding associated with the racking system. The new 10° tilt angle allows integrators to achieve a greater power density on commercial rooftops. Other new features for the CS60 10° tilt include integral wire management, multiple east and west settings to better accommodate different module string lengths, and improved access for module installation.

Renusol America / 877.847.8919 /

S-5!  Booth 1277

Well known for its nonpenetrating metal roof-attachment solutions, S-5! recently introduced the VarioBracket, an adjustable attachment solution for trapezoidal metal roof systems. In addition to accommodating any trapezoidal ridge profile, the mounting bracket is also adjustable in height. Self-drilling bi-metal screws attach the stainless steel VarioBracket to the trapezoidal ridges of the roofing system; factory-applied sealant at the connection points ensures seal integrity. The company offers an ever-expanding line of S-5! clamps and brackets for different standing-seam metal roof profiles, as well as a new version of its S-5-PV Kit.

S-5! / 888.825.3432 /

SCHLETTER  Booth 1323

Perhaps best known for its utility-scale groundmounting systems, Schletter also offers the Park@Sol, a modular PV carport solution. The Park@Sol is available in three standard options: single row, double row, and a north-south configuration. It will accommodate residential arrays of just a few kilowatts or can be scaled up to accommodate multimegawatt parking structures. The Park@Sol is engineered for IBC compliance and can attach to a variety of foundation types. If desired, the system can include an optional waterproof covering below the modules. Schletter is also showcasing FS ECO, an affordable all-steel ground-mounting solution, as well as AluGrid, a low-slope commercial roof-mounting system.

Schletter / 520.289.8700 /

SMA AMERICA  Booth 2010

SMA is expanding the Sunny Boy line with the SB 240-US microinverter. The communication protocol for the SB 240 allows for hybrid installations that utilize micro and string inverters. SMA is also updating the Sunny Island line with a new 6 kW SI 6048 inverter and Smartformer. The Smartformer features a 120/240 V autoformer, ac distribution board and prewired bypass switch, and includes a load-shedding relay. Other new SMA products include the nonisolated Sunny Boy string inverter line and the mediumvoltage products for utility-scale installations.

SMA America / 888.476.2872 /

SNAPNRACK  Booth 2737

Both the commercial Series 350 ground mount and the Series 450 flat-roof mount from SnapNrack are now available with a new steel rail that lowers mounting structure costs by as much as 20%. The steel rail is designed to match the strength of the existing aluminum rail, but is stiffer and costs less. Like the aluminum rail, the roll-formed steel rail allows for the use of proprietary snap-in channel nuts for improved installation efficiency. Additional features on the bottom of the steel rail profile allow for a faster connection to a ground-mount substructure. The solution is field tested, supporting more than 10 MW of installed PV capacity. A video that details the steel rail is on display at the SnapNrack booth.

SnapNrack / 877.732.2860 /


SolarBridge Technologies has released the next generation of its ac module solutions, along with an enhanced communication and control system. SolarBridge partners with module manufacturers and integrates the Pantheon II microinverter to deliver listed ac modules. The Pantheon II is a higher-poweroutput version of its predecessor, with a higher efficiency and a smaller footprint. The updated SolarBridge Management System enables integrators to remotely access and control their PV systems. SolarBridge has announced new partnerships with ET Solar, MAGE Solar, NESL and Talesun Solar to add to the manufacturers that already offer the SolarBridge solution: BenQ Solar, Solartec and SunPower.

SolarBridge Technologies / 877.848.0708 /


The Solar-Log family of products from Solar Data Systems offers monitoring, data logging and plant visualization solutions for PV systems of all sizes. The Solar-Log200 is designed for residential PV systems with a single inverter under 15 kW in capacity; the Solar-Log500 accommodates up to 10 inverters and a total plant capacity of 50 kW; the Solar-Log1000 can monitor up to 100 inverters and a total inverter capacity of 1 MW. All models support local PC and Internet viewing, as well as remote viewing via the Solar-Log WEB interface. Solar-Log inverterdirect monitoring complies with CSI requirements for performance monitoring and reporting. The system also supports optional revenue-grade energy reporting.

Solar Data Systems / 203.702.7189 /

SOLAREDGE  Booth 3901

The newest generation of SolarEdge power optimizers does not require additional interface hardware and has the ability to operate directly with any grid-direct inverter. The new power optimizers offer the same benefits as the previous SolarEdge products—module-level MPPT and monitoring, and enhanced safety features— as well as improved design flexibility. The addition of the IndOP technology allows installation of the power optimizer in new installations regardless of the inverter technology, as well as integration with existing installations to increase energy yields.

SolarEdge / 530.273.3096 /

SOLARWORLD  Booth 1301

SolarWorld has diversified the scope of its manufacturing with the addition of fixed- and tracked-racking products. The Suntrac single-axis tracker can drive 250 kW to 1,000 kW of PV per motor. SolarWorld provides custom Suntrac configurations based on individual sites to accommodate grade variations and nonrectangular array boundaries. The Sunfix ground mount is designed to support arrays that range from 3.4 kW to multi MW and is compatible with driven pile, earth screws and ballast foundations. For residential-scale applications, the Sunfix plus pitchedroof racking system features preassembled top and end clamps, precut rail lengths and single-tool installation.

SolarWorld / 855.467.6527 /


Solectria Renewables recently released the newest Smart Grid 500 kW inverter, the SGI500XT, as an addition to its line of utility-scale inverters. The SGI line, including the new 500XT, is designed to work with the utility by offering real power curtailment, reactive power control, low voltage and frequency ride-through, and remote power control. The 98% CEC-efficient inverter offers integrators a number of features to aid installation and O&M. The non-isolated (transformerless) inverter has a 208 Vac output for direct to medium voltage system configurations. A Modbus communications platform allows for data collection with Solectria’s SolrenView or with third-party options.

Solectria Renewables / 978.683.9700 /


Stiebel Eltron offers a range of water-heating products that includes flat-plate solar collectors, pump stations and storage tanks; tankless electric water heaters; and heat-pump water heaters. The company’s 30-year background in heat-pump technology has led to the introduction of the Accelera 300 heat-pump water heater to the North American market. The Accelera 300 has an 80-gallon storage capacity and is backed by a 10-year warranty. The unit’s maximum rated power draw is 2,200 W (500 W for the compressor and fan, and 1,700 W for the backup electric heating element).

Stiebel Eltron / 800.582.8423 /

SUNLINK  Booth 2435

Precision RMS is the latest roof-mounting system from SunLink. Preassembled long-beam units run northsouth atop recycled rubber feet that may eliminate the need for slip sheets. For improved workflow, groups of two to four modules can be prepanelized, off-site or off-roof. The south edge of the panelized assemblies connects to the long beam using a pivot block, which allows for tilt access to the rear of the modules or the roof system underneath; the north edge is tilted up on strut brackets, allowing for tilt angles of 5°, 10°, 15°, 20°, 25° or 30°. The aluminum extrusions and stainless hardware are designed to provide integrated grounding per UL 2703, and the system includes wire-management trays and clips.

SunLink / 415.925.9650 /

TIGO ENERGY  Booth 3133

The newest offering from Tigo Energy is the MM-2ES, a dual Module Maximizer that can be used with one or two PV modules, reducing optimizer part count and increasing design flexibility. The endgame for Tigo Energy, of course, is to facilitate “smart module” solutions by providing optimized junction boxes to module manufacturers. Certification testing for the company’s junction-box– integrated Module Maximizer is under way, and completion may be announced at SPI 2012. The company will definitely announce that BEW Engineering—an independent, bank-approved engineering firm—has completed a positive bankability report regarding Tigo Energy’s products, practices and processes.

Tigo Energy / 408.402.0802 /

TMEIC  Booth 4025

The industrial systems departments of Toshiba and Mitsubishi Electric merged in 2003 to form TMEIC. The manufacturer’s line of utility-scale PV inverters for the North American market currently includes three models. The SOLAR WARE 630, SOLAR WARE 500 and SOLAR WARE 250 have rated power outputs of 630, 500 and 250 kW, respectively. TMEIC also offers the prepackaged SOLAR WARE station, available in 1.0 and 2.5 MW power blocks that include inverters, dc recombiners and pad-mounted transformers. The 1,000 Vdc inverters feature a 540–950 Vdc MPPT operating range and grid assistance modes that include reactive and active power control, fault ridethrough and power factor control.

TMEIC / 540.283.2000 /


Trojan Battery Company’s new 2-volt deep-cycle, highcapacity battery additions to its Industrial Line are engineered to offer increased design flexibility for solar applications. The recently released IND27-2V battery has a capacity of 1,457 amp-hours at the C20 rate, and the IND33-2V battery has a capacity of 1,794 amp-hours at the C20 rate. Trojan’s Industrial Line is designed to support large daily loads where the batteries are cycled regularly in standalone PV applications such as off-grid homes, micro-grids and telecom applications. The company also released a new “Made in the USA” 12-volt AGM battery with a capacity of 140 amphours at the C20 rate.

Trojan Battery / 800.423.6569 /


The Instant Connect product line from Westinghouse Solar integrates racking, equipment grounding and electrical connections into the design of the PV module in an effort to reduce installation time and improve installation quality. The grooved frame accommodates mounting systems deployed on pitched residential roofs and low-slope commercial buildings. The mechanical splice integrated into each module electrically bonds the modules together and provides mechanical support. During installation, the splice also aligns the modules’ integrated electrical connections, engaging the module-to-module plug. The Instant Connect modules are available in dc versions , as well as ac versions that employ Enphase microinverters.

Westinghouse Solar / 888.395.2248 /


Primary Category: 

Storms, wildfires, and overloaded or faulty electrical grid transmission and distribution networks result in power outages that impact tens of millions of US residences each year. Hurricane Sandy, the nation’s most recent large-scale storm, resulted in utility outages that affected 8.5 million customers across 21 states at its peak, according to the US Department of Energy.

Large-scale grid failures inevitably lead to surges in demand for PV systems with battery-backup capabilities. However, many solar design and installation firms have determined that battery-based systems are too expensive to sell effectively or too complex to design, install and service. As a result, many firms have little, if any, experience with these systems. Offering battery-backup options to residential customers is profitable for integrators who invest the time, resources and training to come up to speed with, and stay current on, battery-based system equipment selection, design and installation. The falling costs of PV modules, and ongoing advancements in battery-based inverter and BOS technologies, can make PV with battery backup an attractive offering for integrators who serve the residential market.

The owner of a grid-tied PV system with battery backup gets the best of both worlds: a reduced electric bill and the ability to live comfortably and safely without the grid when necessary. Installers of backup systems can access a market with fewer competitors, better margins and higher equipment and installation values than installers who offer grid-direct systems only. In this article, we introduce electricians and integrators who are new to battery-based grid-tied PV installations to basic system topologies and the power-conditioning equipment used to build these systems. While the learning curve may seem steep, experienced installers will need very few additional skills or tools to design and install battery-backup PV systems, particularly if they employ a preconfigured and prewired powerconditioning system.

Primary System Configurations

Integrators can configure a battery-backup PV system as either dc coupled or ac coupled. Each of these primary system configurations has benefits and drawbacks to consider, and each influences equipment selection as well.

DC coupling. Traditionally, the majority of battery-backup PV systems have been dc coupled. In dc-coupled systems, PV array source circuits are typically configured at relatively low dc voltages of less than 150 Vdc maximum. Individual source circuits are routed to a combiner box that provides overcurrent protection for each string and combines the individual dc inputs, allowing a single pair of larger transmission conductors to be run from the combiner box to the system’s dc charge controller. Because the charge controller is usually installed in close proximity to the system’s inverter/charger and battery bank, the wire run distance between the array combiner and the system’s charge controller can be significant, especially if the array is ground mounted rather than on the roof. With a groundmount system, the conductor cost may be significant due to the transmission distance and the dc-coupled array’s relatively low-voltage and high-current characteristics.

In dc-coupled systems, the output of the charge controller is connected to the system’s main low-voltage (typically 48 Vdc nominal) dc bus via overcurrent protection and disconnect equipment. When the utility grid is functional, the system’s utility-interactive battery-based inverter converts the dc energy generated by the PV array to alternating current, synchronizes the ac waveform with the utility grid and exports any surplus energy to the utility. During power outages, the battery-based inverter disconnects from the utility grid and energizes select household electrical circuits using energy stored in the batteries or provided by the PV array. To prevent battery overcharging, the charge controller regulates the dc current that the PV array generates during daylight hours.

AC coupling. In ac-coupled systems, a grid-direct string inverter effectively replaces the PV charge controller that is used in dc-coupled systems, and typically the source-circuit combiner box as well. In these systems, the PV array is configured at relatively high voltages of up to 600 Vdc, and the string inverter converts the array output to 240 Vac. In accoupled systems, the string inverter’s ac output is connected to the battery-based system’s ac bus. When the utility grid is functional, ac electricity provided by the string inverter supplies energy to household loads, and excess energy is exported to the utility grid. In the event of a grid failure, the battery-based inverter disconnects from the utility grid and energizes select household electrical circuits using energy stored in the batteries or provided by the PV array via the string inverter.

Because ac-coupled systems do not use charge controllers to regulate battery charging during a utility outage, alternate means of array charge control are required. In accoupled systems that utilize battery-based inverters and string inverters from the same manufacturer, battery charge regulation can be seamless. When components from multiple manufacturers are used, battery charge regulation can become considerably more complicated in these systems. (See “AC Coupling in Utility-Interactive and Stand-Alone Applications,” SolarPro magazine, August/September 2012.) In addition, while most battery-based inverters are capable of ac coupling, some string inverter manufacturers do not permit, support or offer a warranty on the use of their string inverters in ac-coupled systems.

Compared to dc-coupled systems, accoupled platforms have the advantages of higher array voltages, streamlined array wiring and lower transmission conductor size and cost. While the string inverter used in ac-coupled systems is more expensive than the charge controller it replaces, the elimination of the source-circuit combiner box and lower array wiring labor and equipment costs can make the overall installed outlay for these systems roughly equivalent. In retrofit installations that are adding battery backup to an existing grid-direct system, ac coupling is often the preferred approach because the array wiring does not need reworking to operate at the lower voltages that most dc charge controllers require.

Power-Conditioning Equipment

Four companies manufacture the majority of the power-conditioning and system-integration equipment employed in battery-backup PV systems in North America. Magnum Energy and OutBack Power Technologies offer power electronics and integration equipment that is primarily intended for use in dc-coupled systems but that can be utilized in ac-coupled systems as well. Schneider Electric manufactures utility-interactive battery-based inverters and string inverters, dc charge controllers and system integration hardware for both ac- and dc-coupled systems. SMA America offers utilityinteractive battery-based inverters, string inverters and additional components that can be used to develop highly integrated ac-coupled systems. A fifth company, MidNite Solar, offers charge controllers, system integration hardware and battery enclosures that can be utilized in battery-backup systems.

OutBack Power released its current generation of utility-interactive battery-based inverter/chargers in 2012 with the goal of simplifying the design and installation of batterybackup systems. The Radian Series GS8048 has a rated ac power output of 8,000 W at 25°C, a nominal input voltage of 48 Vdc and an ac output voltage of 120/240 Vac. The product has a dual power module design that provides a degree of redundancy and improves overall conversion efficiency during both low-power and high-power operation. Up to 10 Radian GS8048 inverter/chargers can be configured in parallel for a 120/240 Vac system with a rated power output of 80 kW. A second Radian model, the GS7048E, is offered for international and developing world markets. This product has a 7,000 W rated output at 230 Vac/50 Hz and a nominal input voltage of 48 Vdc.

OutBack’s Radian GS8048 inverter can be factory integrated with one of the manufacturer’s five GS Load Center models to reduce installation time in the field. For example, the GSLC175-PV-120/240-GS Load Center can be factory prepared with dual 175 Adc inverter/ battery circuit breakers, dual ac inputs to integrate grid and generator charging, a 120/240 Vac maintenance bypass assembly, a PV ground-fault–detector interrupter (GFDI), two PV array inputs, OutBack’s FLEXnet dc battery monitor and three shunts for system charge and discharge monitoring. This particular assembly is intended for systems using a single Radian inverter and two OutBack FLEXmax dc charge controllers.

OutBack Power is continuing to manufacture its previous generation of utilityinteractive inverter models. Two environmentally sealed units are available: the GTFX2524 and GTFX3048, with output ratings at 25°C of 2,500 W and 3,000 W and input voltages of 24 Vdc and 48 Vdc nominal, respectively. Two vented models are also available. The GVFX3524 has a rated output of 3,500 W at 25°C and an input voltage of 24 Vdc nominal, and the GVFX3648 has a rated output of 3,600 W at 25°C and an input voltage of 48 Vdc nominal. OutBack Power also manufactures an international series of six GTFX and GVFX inverters with 230 Vac/50 Hz output. The company offers a wide range of integration enclosures and hardware for its GTFX and GVFX inverter products, including complete preassembled powerconditioning systems.

OutBack Power currently manufactures two PV charge controllers that can be fully networked with either the Radian or the GTFX and GVFX inverter/charger systems. The FLEXmax series includes the FM80-150VDC, which has a maximum output current rating of 80 A at 40°C and an absolute maximum PV open-circuit voltage of 150 Vdc. The FM60-150VDC has a maximum output-current rating of 60 A at 40°C and an absolute maximum PV open-circuit voltage of 150 Vdc. The controllers are designed with the functionality to step down a higher array voltage to a lower nominal battery-charging voltage. For example, a 72 Vdc nominal array voltage can be stepped down to charge a 48 Vdc nominal battery. While 48 Vdc nominal battery banks are recommended for most battery-backup systems, the FM80 and FM60 controllers are field programmable for integration with 12, 24, 36, 48 or 60 Vdc nominal battery banks. An environmentally sealed version of the FM-80 controller— the FLEXmax Extreme—is scheduled for release in Q1 2013.

OutBack Power released two additional product lines for battery-backup applications in 2012. The company is currently offering two valve-regulated lead-acid (VRLA) absorbed glass mat (AGM) battery models, as well as an integrated battery rack. The EnergyCell batteries are 12 Vdc nominal and available with capacity ratings of 153.8 Ah or 178 Ah at the 20-hour discharge rate. OutBack’s Integrated Battery Rack (model IBR-3-48-175) is designed to house three 48 V strings of batteries for up to 28.8 kWh of total energy storage in a single enclosure. The product also includes integrated high-current dc breakers that provide battery string overcurrent protection and disconnecting means for system maintenance.

Schneider Electric manufactures power-conditioning equipment for both dc- and ac-coupled battery-backup systems. The company is the only North American manufacturer that offers utility-interactive battery-based inverters, string inverters and high-voltage dc-array charge controllers. Schneider’s Conext XW utility-interactive battery-based inverter line includes three models, each with 120/240 Vac output. The inverter with the highest power rating is the XW6048-120/240-60. This inverter has a 6,000 W continuous power rating at 120 Vac output, a 5,752 W continuous power rating at 240 Vac output and a nominal dc input voltage of 48 Vdc. Schneider offers a second 48 Vdc nominal batterybased inverter, the XW4548-120/240-60, with a continuous output power rating of 4,500 Vac at both 120 and 240 Vac. The third model in the Conext XW inverter line is the XW4024-120/240-60, with a 4,000 W continuous output rating at 120 and 240 Vac, and a nominal dc input voltage of 24 V.

Up to four XW inverters can be configured in parallel for a total system power capacity of 24 kW at 120/240 Vac. In addition, up to six XW inverters can be used in a 3-phase configuration for a 36 kW system with an output voltage of 120/208 Vac. Three XW models are available with 230 Vac/50 Hz outputs for international and developing world projects. Dual ac inputs allow for backup generator input and grid interaction. An optional automatic generator-start unit is also available. The Conext XW Power Distribution Panel includes a conduit box and all ac and dc disconnects and integration wiring to support a single inverter.

For ac-coupled systems, Schneider Electric offers four Conext TX string inverter models with field-selectable output voltage options of 240 and 208 Vac. The Conext TX 2800, TX 3300, TX 3800 and TX 5000 are rated for 2,800, 3,300, 3,800 and 5,000 W, respectively, when configured for 240 Vac output. When TX string inverters are deployed in accoupled systems in conjunction with the Conext XW battery-based inverter, battery charging is regulated during utility grid failures by frequency phase–shift functionality that is integrated into the battery-based inverter. This degree of product integration provides installers with a fail-safe string/battery-based inverter configuration for accoupled systems.

Schneider Electric also offers two dc array chargecontroller models that can be used to build fully networked dc-coupled systems. The XW-MPPT60-150 has a power rating of 60 A with a PV array maximum open-circuit voltage rating of 150 Vdc. The unit has voltage step-down functionality and can be configured to charge 12, 24, 36, 48 and 60 Vdc nominal battery banks from a higher-voltage PV array. Schneider has also released the only 600 V charge controller currently available in the North American market. The XW-MPPT80-600 allows integrators to configure arrays at open-circuit voltages that are similar to those utilized by string inverters to drive down costs of array wiring and BOS equipment requirements.

Training Opportunities

Advancements in inverter and integration hardware for battery-based systems are making them more straightforward to design and install, but they are still relatively complex compared to residential grid-direct systems. Working with batteries presents additional design, installation, Code and safety requirements. Programming battery-based inverters correctly can present a relatively difficult learning curve. Several training resources are available to integrators.

Product-specific training. Battery-backup equipment configuration, installation and programming vary greatly from manufacturer to manufacturer. If batterybackup PV systems represent a new application for your business, we recommend participating in product-specific training from the manufacturer of the equipment you are considering. Battery-based inverter and charge controller manufacturers frequently offer classroom training in conjunction with industry conferences or training events hosted by equipment distributors such as AEE Solar, as well as online via live or archived webinars. Additionally, all of the manufacturers discussed in this article have extensive product installation manuals available online.

Third-party training. Training in battery-backup PV systems is also available from several third-party training providers. Notably, Solar Energy International ( offers extensive training in ac- and dc-coupled battery-based systems via online courses, as well as a 5-day hands-on workshop at the company’s PV Lab training facility in Paonia, Colorado.

SMA pioneered the development of ac-coupled system platforms in the 1990s, using its battery-based and string inverters. Today, the company offers a range of products for utility-interactive battery-backup systems. While SMA’s battery-based Sunny Island inverter models can be deployed in dc-coupled systems that incorporate PV charge controllers from other manufacturers, this approach limits the overall level of component networking integration that can be achieved.

SMA has developed an extremely high level of integration between its Sunny Island inverters and Sunny Boy string inverters in ac-coupled systems. This functionality includes frequencyshift battery charge regulation that is sophisticated enough to ramp up and down PV array charge current produced by the system’s string inverter based on battery state of charge, a feature that is not available in ac-coupled systems using components from other manufacturers.

SMA manufactures a wide range of string inverters that can be used in ac-coupled applications. With rated power outputs of 700 W to 10 kW, these inverters can be fully integrated with and controlled by SMA Sunny Island inverters. The company revised its battery-based Sunny Island product line in 2012 with the addition of two new inverter models—the Sunny Island 4548-US and 6048-US—and plans to phase out its existing Sunny Island 5048-US model. The two new products have rated power outputs of 4,500 W and 6,000 W at 25°C, respectively, a nominal dc input voltage of 48 Vdc and an ac output voltage of 120 Vac. Up to nine Sunny Island inverters can be combined for a 72 kW, 120/208 Vac 3-phase system.

One previous limitation with SMA’s component offerings for ac-coupled systems related to inverter ac-voltage compatibility. Sunny Island inverters have a 120 Vac input/ output voltage. However, Sunny Boy inverters have a 240 Vac output voltage. To ac-couple the battery-based and string inverters, systems required two Sunny Island inverters configured to provide 120/240 Vac output. To solve this technical limitation, in 2012 SMA released its UL-listed Smartformer. The product is a 120/240 Vac autoformer designed for systems that ac-couple a single Sunny Island battery-based inverter with a single Sunny Boy string inverter. The Smartformer provides step-up and step-down options to supply backed-up loads with 120 Vac and 240 Vac, and it allows the ac coupling of a Sunny Boy inverter with a single Sunny Island inverter.

Battery-Backup System Considerations

If your company is new to battery-backup PV systems, we recommend sourcing preconfigured and prewired inverter and integration products from an equipment wholesaler who is experienced in the design and installation of these systems. You should be aware of the following high-level system design considerations and specific details that relate to battery-backup systems.

Determining critical loads. In residential applications, it is not practical to design backup systems that will support every electrical load found in a typical residence, and managing customer expectations up front is important. The salesperson and the customer should agree on the specific loads and circuits that require backup during utility failures. In small systems, these loads typically include communications equipment such as televisions, phone chargers, computers and Internet routers, as well as select lighting circuits. Larger systems may be designed to support critical loads including refrigerators, freezers, well pumps, and blowers and controls for natural gas– or propane-fueled heating systems. Installers often use colored outlets and switches to identify backed-up circuits.

Establishing a load profile. The total capacity of the backup system is based on the power, energy and surge requirements of the backed-up loads in relation to the duration of the grid failure for which the system is designed. These values serve as a baseline to specify inverter and battery-capacity requirements.

Single manufacturer. In most cases, it is advantageous to specify power-conditioning equipment that includes inverters, PV charge controllers (if used) and integration hardware from a single manufacturer. This strategy enables full networking integration between components and streamlines system design and installation. If a specific project requires equipment from multiple manufacturers, be sure to consult one of your distributor’s system engineering or technical support specialists before finalizing the design. Some products work together better than others.

Battery selection. Batteries and related selection and system design criteria are covered in detail in “High-Capacity Battery Banks,” SolarPro magazine, February/March 2012. In utility-interactive battery-backup systems, valve-regulated lead-acid (VRLA) absorbed glass mat (AGM) batteries are recommended for most applications. This type of battery functions well in battery-backup PV applications—and, unlike flooded-battery types, VRLA AGM batteries do not need to have distilled water added periodically.

Battery enclosures. For small systems, integrators often fabricate an enclosure for battery containment. Manufactured enclosures are readily available that protect homeowners from live electrical battery interconnections and present a professional-looking finished system. In either case, it is important to verify that the enclosure is designed to support the combined weight of the batteries and provides adequate ventilation for the battery type used.

Battery temperature sensing. All battery-based inverter and charge controller manufacturers offer battery temperature sensors and enable these sensors to communicate with the system’s power-conditioning equipment over a network. This functionality should always be employed to ensure optimal battery charging and to prevent damage to the batteries due to overcharging.

AC bypass switch. Power-conditioning integration hardware should include an ac bypass switch. This makes it possible to manually bypass the inverters and connect the critical-loads panel to grid power during any required system maintenance.

Dual ac inputs. If the backup system design includes an engine generator, the design needs to specify inverters that have provisions for dual ac inputs (grid and generator).

Financing. Battery-based systems can be more difficult to finance than grid-direct systems. Battery-backup systems are eligible for federal tax incentives, but they may not be eligible for specific state or utility financial incentive programs. Currently, most third-party lease programs specifically exclude battery-backup systems. The Admirals Bank Title I and Title I Plus I home improvement loan programs can finance up to $40,000 for a PV system with battery backup. Traditional home improvement loans may also be a good option, provided the homeowner has sufficient equity. You should conduct up-front research regarding incentive and financing programs in your service region to determine eligibility.

Magnum Energy’s MS-PAE series of inverter/chargers are not designed for utility-interactive operation, meaning the units cannot export power to the grid. However, Magnum’s products can be used in ac-coupled systems where a string inverter provides ac power to household loads and to the utility grid. In this configuration, string inverters from manufacturers that permit the use of their products in ac-coupled systems are utilized to export PV-generated energy to the grid when utility power is present, and also to maintain the batteries at a full state of charge. During a grid failure, the string inverter synchronizes its output with the ac waveform generated by the MS-PAE inverter to provide power to critical loads and to charge the battery bank. Magnum Energy has integrated frequency-shift functionality into its MS-PAE inverter/charger models to provide battery charge regulation in ac-coupled systems during power outages. This feature is typically used in conjunction with an additional diversion load to ensure optimal battery charge regulation.

Magnum Energy offers two MS-PAE inverter/charger models. The MS4024PAE has a rated power output of 4,000 W at 25°C and an input voltage of 24 Vdc nominal. The MS4448PAE product has a rated power output of 4,400 W at 25°C and an input voltage of 48 Vdc nominal. Both models feature 120/240 Vac output, and up to four inverters can be configured in parallel for a system power rating of up to 17.6 kWac. Magnum Energy integration panels and router are required for parallel stacking of the MS-PAE series inverter chargers.

MidNite Solar does not manufacture inverters for battery-based systems, but the company does offer a number of products for battery-backup projects that integrators should be aware of. MidNite manufactures a line of PV charge controllers: the Classic 150 (150 Vdc maximum input voltage rated for 96 A), the Classic 200 (200 Vdc maximum input voltage rated for 79 A) and the Classic 250 (250 Vdc maximum input voltage rated for 63 A). New, lower-cost “light” versions of these controllers that do not include the programmable display are also available. Additionally, MidNite offers eight battery enclosure models designed to house a range of battery numbers, models and sizes that are typically used in battery-backup systems. Inverter integration enclosures (E-panels) and hardware, as well as dc-rated circuit breakers, are available as individual components or as part of complete preassembled systems that incorporate inverters from Magnum Energy, OutBack Power, Schneider Electric or SMA America.

Battery-Backup Opportunities

Battery-backup systems present a great opportunity for integrators to develop a new, high-margin market for their products and services. They also offer ongoing O&M opportunities since batteries have a limited operational life expectancy. Considering the recent and ongoing advances in batterybackup inverter technologies and system integration equipment, the technical and cost barriers are lower than ever. As these technologies continue to mature, battery-based backup may become a common feature in many residential PV systems that are designed to provide a host of smart-grid tasks such as load shifting and EV charging to best manage time-ofuse rates. Installers and integrators who understand the components, design and installation of utility-interactive battery systems will have a leg up as these new products and applications hit the market. Courtesy Namasté Solar


Paul Dailey / AEE Solar / San Luis Obispo, CA /

Joe Schwartz / SolarPro magazine / Ashland, OR /


Magnum Energy / 425.353.8833 /

MidNite Solar / 360.403.7207 /

OutBack Power Technologies / 360.435.6030 /

Schneider Electric / 847.397.2600 /

SMA America / 916.625.0870 /

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Many photovoltaic system designers and installers have considerable training and experience with utility-interactive, grid-direct (UIGD) systems. Comparatively few have training or experience with utilityinteractive, battery backup (UIBB) systems and their nuances. This technical introduction is intended for the latter audience and highlights the differences between the two system architectures, components, design details and NEC requirements. Incorporating battery backup increases a system’s parts count, complexity and cost per installed watt, but it may prove to be a desirable - if not an essential - feature to some customers.

As with gird-direct systems, some jurisdictions, like California, require minimum performance specifications for UIBB inverters. The list of eligible inverters published by the California Energy Commission includes UIBB inverters manufactured by OutBack Power Systems and Xantrex Technology. Accordingly, the generally similar UIBB system architecture employed by these two companies is the only one addressed in this article. In this architecture, UIBB systems include an array combiner, charge controller and a battery bank, along with other balance-of-system components.


Like grid-direct systems, UIBB systems reduce energy consumption from the utility grid, export excess energy back to the grid and utilize inverters that meet UL 1741 anti-islanding requirements. As with grid-direct systems, UIBB systems harvest energy from the sun during the day, and the grid powers all loads at night. The battery bank is maintained at or near float voltage and is primarily charged by the PV subsystem and, as necessary, from the grid via the inverter’s built-in charger. This architecture results in a fairly efficient system that avoids most of the inefficiencies associated with daily battery cycling (discharging and recharging).

When the grid fails, the UIBB system’s inverter immediately disconnects from the grid, just as with a grid-direct PV system. But instead of the home or office going dark and quiet, the system transfers to battery power select loads previously assigned to a subpanel. This is the UIBB system’s key advantage.

The batteries can power the backup loads for a few hours or days, depending upon several variables: the power demands of the combined loads being backed up, the size of the array, the available insolation and the size and health of the battery bank. In residential applications, backed-up loads often include lighting, refrigeration, home electronics, cell phone chargers, computer equipment and the like. In business applications, lighting, data and computer equipment are often deemed critical loads that require an uninterruptable power source. Once grid power is restored, all loads are transferred back to the grid, and the inverter’s built-in charger and the PV array recharge the battery bank. Once the bank is recharged, the system returns to normal operation.


PV array. In almost all cases, PV arrays in UIGD systems are configured for higher dc output voltage than in UIBB systems. In grid-direct systems, modules are configured in series strings to achieve temperature-corrected open-circuit voltages as high as 600 Vdc. The maximum power voltages of these strings may be as high as 550 Vdc, depending on the operating characteristics of the specified inverter. However, the operational input voltage limit for OutBack and Xantrex charge controllers is in the 140 to 145 Vdc range, with absolute maximum limits of 150 Vdc. The 150 V hard stop limit of these controllers requires that UIBB arrays be configured using shorter, lower voltage strings with several strings wired in parallel. Apollo Solar manufactures controller models with an absolute maximum voltage of 200 Vdc. Note that these controllers cannot be networked on a communications level with OutBack and Xantrex UIBB inverter systems.

To illustrate configuration differences between typical UIGD and UIBB arrays, consider the following examples. In a grid-direct application, a 4 kW array of 20 Evergreen ES-A 200 modules (11.05 Imp, 18.1 Vmp, 12.0 Isc, 22.5 Voc) might consist of a single 4,000 W series string. In some locations, it is possible to connect 20 of these modules in series and still have headroom for the low temperature voltage correction factor covered in NEC 690.7. In a UIBB application, the same 4 kW array might be configured with five 200 W modules per series string with four 1,000 W strings in parallel. Similarly, a 2.76 kW array consisting of 12 REC SCM-230 modules (7.8 Imp, 29.4 Vmp, 8.3 Isc, 37.1 Voc) could be wired with three 230 W modules per series string and four 690 W strings in parallel. Either of these array configurations will satisfy NEC 690.7 and practical voltage calculation requirements for arrays exposed to both cold and hot environments. (For additional details on optimizing array, charge controller and battery matching in UIBB systems, see sidebar.)

PV Array Matching to Charge Controller and Battery Bank

Seasoned designers and installers are familiar with the maximum voltage calculations and temperature correction factors (TCFs) described in NEC Article 690.7. These temperature correction factors must be applied for both grid-direct and battery-based systems. This section of the Code was revised in 2008. One change is that it now includes instructions for applying the Voc temperature coefficient as provided by the module manufacturer. Table 690.7 is also now more finely granulated, but this table is intended for use only when manufacturer published temperature coefficients are unavailable.

At first glance, the voltage window between a 150 Vdc rated charge controller or circuit breaker and a nominal 48 Vdc battery bank may seem to be wide. However, a delicate design exercise is often required. An extreme, but common, example is found in areas where ambient temperatures range between -40ºC and 40ºC (-40ºF and 104ºF). This includes many locations in the southwest and Rocky Mountain states. Winter temperatures lead to early morning module output voltages substantially above Voc specifications at STC. Similarly, high ambient temperatures in summer can significantly reduce an array’s midday operational voltage. For systems with 48 V battery banks, the challenge is twofold. Allowing for NEC Article 690.7 calculations, the array voltage must not exceed 150 Vdc in cold temperatures. Ideally, to maintain uninterrupted operation, the array voltage should not exceed the controller’s operational input voltage limit.

Using the 125% temperature correction factor (TCF) for -40ºC environment specified in NEC 690.7 (backup 2008, default 2005), an array’s STC Voc should be no higher than 116 V in order for the array to remain below 145 V. Since STC Vmp is typically about 80% of STC Voc, the array STC Vmp upper limit is about 93 V. Conversely, the array’s high temperature operational voltage should be high enough to meet the battery bank’s target voltages for the absorption and equalization cycles, and there has to be enough headroom to overcome voltage drop in the wiring and inside the controller.

Assuming a target voltage of 62 V and a 4 V drop in the array wiring and controller, a hot array must be able to deliver 66 V. If a very hot array’s operational voltage of 66 V is 25% below STC specification, then the array’s STC Vmp should be about 88 V. Combining the two limits, the sweet spot for the array’s STC Vmp lies between 88 V and 93 V. This would appear to be a fairly narrow target, and, in fact, it once was difficult to achieve. Fortunately, there are currently many PV modules available with output specifications other than the traditional 12 V or 24 V nominal values. Table 1 contains examples of many modules with specifications that indicate they will operate satisfactorily over a wide range of ambient temperatures. For UIBB applications, many additional PV models are available for applications involving lesser extremes in ambient temperatures and target charge voltages.

Because arrays in UIBB applications operate at lower voltages, the required series/parallel configurations result in higher total array currents. That current must still be considered continuous per Code, and 690.8 applies when calculating the array’s output circuit current and determining compatibility with a charge controller. For this reason, the size of an array coupled with a controller rated at 60 A is typically limited to a maximum Isc of 48 A at STC.

Combiner boxes and series string OCPDs. The higher voltage PV arrays used in residential grid-direct PV systems are generally composed of one or two series strings connected in parallel at the inverter. Combiner boxes with an overcurrent protection device (OCPD) per series string are usually not required for these systems per NEC 690.9. In some cases, three series strings may be connected in parallel in grid-direct systems without requiring an OCPD for each string.

Typical residential PV arrays for UIBB systems often require four or more series strings wired in parallel with provisions for a dc-rated OCPD—circuit breaker or fuse—in-line with each series string. OCPD ampacity values are selected based on module Isc specifications at STC and calculations from NEC 690.8. Also, every PV module has a maximum OCPD rating specified by the manufacturer. Combiner boxes provide both overcurrent protection and a means to combine the grounded and ungrounded circuits at dedicated busbars.

DC disconnect. PV systems require a dc disconnect where the array’s dc circuits enter the building per NEC 690.13 and 690.14. For UIBB systems, the dc disconnect is usually between the array combiner box and the charge controller. This disconnect is typically mounted outside at an accessible location, with the system’s electronics mounted inside.

Ground fault protection. Article 690.5 of the 2008 NEC generally requires ground fault protection (GFP) for PV systems, in part to reduce fire hazards. UIBB systems commonly include a GFP device at the input to the charge controller. A GFP device is typically a distinct system component, although it is a standard feature on the Xantrex XW controller.

Charge controller. UIBB systems require a charge controller between the PV array and the battery bank. Today’s high power PV charge controllers are technological marvels compared to equipment that was available a handful of years ago. Most modern controllers can be user programmed to meet a wide variety of battery manufacturers’ charging specifications. High power controllers typically include maximum power point tracking (MPPT), temperature compensation functions for adjusting target charge voltages, and dc-to-dc voltage step-down that allows a high voltage array configuration to be used in conjunction with a lower voltage battery bank. Customers and batteries both benefit from these features through greater energy harvest, higher system efficiency and more accurate charging.

In a UIBB system, the charge controller has two primary functions. First, the controller optimizes PV output by tracking the array’s maximum power point throughout the day as temperature and irradiance levels fluctuate, maximizing energy harvest. Second, in the event of a utility outage, the controller will prevent battery overcharging if the building’s loads are not sufficient to consume the energy being generated by the array. When utility power is restored, the controller again delivers the maximum output of the array to loads and the grid.

Charge controllers operate differently in UIBB systems than they do in stand-alone systems. Rather than limit charge current in the absorption and float stages, they deliver all current available at the system’s sell setting. Accordingly, the controllers are typically networked with and controlled by the system’s inverter. For optimal system performance, the controller and inverter should be from the same manufacturer and networked.

One key specification to consider is the charge controller’s continuous output current rating. This specification, along with a system’s nominal battery voltage, generally defines the maximum array size the controller can manage. For example, a controller rated at 60 A dc continuous output current and used in a system with a 48 V nominal battery bank can effectively manage an array rated at about 3 kW at STC. An 80 A controller can effectively manage an array rated at about 4 kW at STC. It is important to check the manufacturers’ product specifications, user manuals and online tools for guidance on array sizing. Extreme environmental conditions or array configurations may affect these values. NEC Articles 690.7 and 690.8 cover calculating array design voltage and currents. (See Resources for manufacturers’ Web sites with detailed equipment specifications.)

Battery bank. Batteries are the key distinction between UIGD and UIBB system architectures. Batteries add components, complexity and cost to a utility-interactive PV system, but these concerns can be mitigated through careful requirements analysis and system design. NEC Articles 480 and 690 address requirements for battery-based PV system installations, such as disconnects, ventilation and location.

The rechargeable lead acid battery has been around for almost 150 years. Options today include flooded-cell lead acid (FLA) and valve-regulated lead acid (VRLA). The latter is available in absorbent glass mat (AGM) and gel variants. Quality deep-cycle FLA batteries are readily available. These batteries are robust, and their cost is relatively low. However, they require regular cell watering and equalization. This maintenance can be significantly reduced with the use of automatic battery watering systems. High capacity VRLA batteries are also readily available. This sealed battery type is spill proof and eliminates the need for cell watering, but VRLA batteries are more sensitive to overcharging than FLAs. Outgassed electrolyte cannot be replaced if the batteries are inadvertently overcharged. For optimal operation and longevity, banks should be made up of identical batteries of the same manufacturer, model and date of manufacture.

Battery performance is directly linked to ambient temperature, so batteries should be protected from extremes. Except in very mild climates, batteries are typically housed in unoccupied indoor spaces such as garages or dedicated outbuildings. Manufacturers’ specifications are typically based on a 25ºC (77ºF) reference temperature, and temperatures above or below this reference point will temporarily affect battery capacity. For example, the usable capacity of a battery bank at 0ºC (32ºF) is about 80% of the rated capacity. Conversely, batteries operating at temperatures above 25ºC will deliver a bit more capacity, but their longevity will be reduced if they are repeatedly exposed to extreme high temperatures.

FLA batteries emit hydrogen gas when they are being charged. In sufficient concentration, hydrogen gas can be flammable and even explosive. NEC 480.9(A) requires provisions for sufficient diffusion and ventilation of the gases. Outgassing and ventilation is more of a concern for FLA batteries than for VRLA types, but VRLA batteries can also outgas significantly if they are overcharged. This can easily be avoided by configuring the charge controller set points properly during installation. Both battery types should be placed in a protective enclosure to guard against inadvertent contact per NEC 690.71(B)(2).

NEC 690.74 allows for flexible, fine-stranded cables sized 2/0 AWG and larger for battery interconnections and connection to nearby equipment. This Code section should be read thoroughly to ensure compatibility between cabling, terminals and lugs. Cables should be sized in accordance with NEC 310.16 and other adjustment factors based on conditions of use.

In UIBB systems, the battery bank must be sized to power the assigned backup loads for a certain minimum period of time. A home’s entire load is rarely backed up. Rather, specific loads determined to be critical or simply requested for convenience by the customer must be scaled to realistic expectations. For example, a healthy 48 V x 250 Ah battery bank can store 12 kWh of energy if discharged 100%. Assuming 90% inverter efficiency and limiting battery depth of discharge to 50%, this bank could supply 12 kWh x 90% x (100% – 50%) = 5.4 kWh, or 2.7 kWh per day for two days. This amount of stored energy could typically power an Energy Star refrigerator for two days, for example, along with intermittent use of compact fluorescent lighting, a small TV, a computer and a cell phone charger. Wiring batteries in series increases bank voltage.

Wiring batteries in parallel increases amp-hour capacity at the nominal battery voltage. Configuring multiple strings in parallel can lead to performance problems due to differing voltage drops in interconnection cabling and differences in the internal resistance of individual batteries. This usually results in unequal charge/discharge rates between strings and decreased operational life. Therefore, a single series string of batteries or a maximum of two series strings in parallel is recommended. Specifying higher capacity, lower voltage battery models will help limit the number of parallel strings required.

Deep-cycle batteries are best served with multi-stage smart chargers. The charging algorithm typically includes bulk, absorb, float and equalization modes. Smart chargers automatically switch from one mode to the next depending on a combination of battery voltage, charge current, battery temperature or time. Multi-stage charging algorithms are included in charge controllers and inverter/chargers from OutBack, Xantrex and other manufacturers. Charging batteries at their correct target voltages for the absorption, float and, if needed, equalization stages is critical to their performance and longevity. Carefully review battery manufacturer’s instructions for set points and conditions of use. FLA batteries require periodic equalization to desulfate their plates and destratify the electrolyte. VRLA batteries are sealed, and many do not require equalization or special conditioning charges.

The reference temperature for battery charger set points is typically 25ºC. Many battery manufacturers use this temperature reference for their charging set points, but several use other temperatures, such as 20ºC (68ºF) or 27ºC (80ºF). These charging set points must be corrected for the charger’s reference temperature before the charger is programmed. A common temperature compensation specification is -0.005 V/2V cell/ºC. For example, if a 48 V (24 cell) battery bank’s absorption set point at 20ºC is 58.0 V, its 25ºC set point will be: 58.0 V + (-0.005 V/cell x 24 cells x (25ºC – 20ºC)) = 58.0 V – 0.6 V = 57.4 V.

Battery charging and discharging are chemical reactions, and all chemical reactions are affected by temperature. Charger voltage set points must be increased for cold batteries and decreased for hot batteries. A remote battery temperature sensor attached to the bank will send temperature data back to a smart charger, and the charger will automatically adjust target voltages.

Finally, battery safety is paramount, as batteries are typically large and heavy, and they contain diluted sulfuric acid. Personnel should always wear protective clothing, including gloves and goggles, when handling batteries. A container of baking soda should be kept handy to neutralize any acid spills. Personally, I believe people should use the buddy system when working with large batteries.

Battery/inverter disconnect. Battery banks are capable of discharging thousands of amperes if short-circuited. This condition creates a serious hazard to personnel and to equipment. Accordingly, battery-based PV energy systems require an appropriate dc rated OCPD between the battery bank and inverter’s dc inputs, which also serves as a means of disconnect to satisfy NEC 480.5. Battery OCPDs are covered in NEC 690.8 and 690.9. The Carlingswitch F-series is an excellent example of an UL-listed, high-count switching operation, high current dc circuit breaker with a high Amperes Interrupt Rating (AIR). Circuit breakers like these are available from MidNite Solar, OutBack and Xantrex, as well as from some electrical supply distributors.

Inverter/charger. Two primary differences between UIGD and UIBB inverters are that the latter have built-in battery charging functionality and a lower dc bus voltage. As in UIGD systems, UIBB inverters convert dc energy from the PV array to ac to power loads and feed the grid when excess energy is generated. During a utility outage, both inverter types disconnect from the grid to meet UL 1741 anti-islanding requirements, but UIBB inverters continue to operate and invert dc energy from the array or the batteries to power assigned backup loads. When utility power is present, the UIBB inverter’s built-in charger occasionally helps keep the batteries charged. Under normal circumstances, the charger may intermittently operate for brief periods at night if the battery voltage falls below a minimum value.

The inverter or inverters in UIBB systems have three main wiring terminal locations. The wiring assignments correlate to the inverter’s three main functions. The battery terminals are the dc connections from the batteries. These large, heavyduty terminals are designed to handle the relatively high dc current from the charge controller and batteries. The ac-in terminals provide for a bi-directional connection between the inverter and the main power panel. When the inverter is producing more energy than is required for the assigned backup loads, excess is exported from the ac-in terminals to the main power panel. When the PV system is producing less energy than is required by the assigned backup loads, or when the charger is operating, then grid supplied power is imported via the same ac-in terminals. The ac-out terminals connect to the subpanel to supply ac power to the assigned backup loads.

AC disconnect. Many utilities require a lockable ac disconnect for PV generation systems. This disconnect is usually Additionally, NEC 690.15 requires an ac disconnect for maintenance purposes. This disconnect typically consists of one or more circuit breakers located near the system’s other ac and dc breakers for grouping purposes. Multiple breakers can be mechanically interlocked to allow for normal operation, bypass operation or total disconnect. In the event of an inverter failure, this bypass operation allows for backup loads to run directly from the utility grid while the inverter is removed for service.

Integration products. Products to integrate UIBB system hardware are available from MidNite Solar, OutBack Power Systems and Xantrex Technology. These products speed integration and installation, and they provide for attractive and NEC-compliant installations. Examples include mounting plates; dc enclosures for terminals, shunts, breakers and wiring; and ac enclosures for terminals, breakers and wiring. In some cases, the ac enclosure can be used as the subpanel for the assigned backup loads.

Service entrance and subpanel connections. The inverters’ ac-in terminals are connected to the main power panel via dedicated ac circuit breakers. For UI systems, the sum of the current ratings for the inverter breakers plus the main breakers must not exceed 120% of the busbar ratings per NEC 690.64. This is a fairly straightforward exercise for UIGD inverters, as their backfed breakers are sized based on their rated output current.

The circuit breaker sizing exercise for UIBB systems is more complex, as the battery-based inverter/charger’s input current rating can be as high as 60 A, which may require an 80 A breaker. Since the NEC requires that the load center rating be based on the size of the breakers, the addition of such a large breaker could violate the 120% rule. Accordingly, it is vital that this breaker-and-busbar calculation be made early in the design process. If an existing distribution panel’s rating is too small, the inverter’s maximum ac input current setting may have to be reduced. Alternately, a larger panel may be required.

The inverters' ac-out terminals are connected to a subpanel dedicated to backed-up circuits. The subpanel and its breakers should be sized for the inverters' output current specifications along with the branch circuit requirements. Note that UIBB inverters typically have 60 A transfer switches. The transfer switch ampacity rating will also dictate the total combined load that the subpanel can service.


James Goodnight / OutBack Power Systems / Arlington, WA /


Apollo Solar / 203.790.6400 /

Carling Technologies / 860.793.9281 /

Concorde Battery / 626.813.1234 /

East Penn Manufacturing (Deka) / 610.682.6361 /

Evergreen Solar / 508.357.2221 /

MidNite Solar / 425.374.9060 /

MK Battery / 800.372.9253 /

OutBack Power Systems / 360.435.6030 /

REC / 509.765.2106 /

Rolls Battery Engineering (Surrette) / 800.681.9914 /

Trojan Battery Company / 800.423.6569 /

Xantrex Technology / 408.987.6030 /

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Most PV designers and installers who work with battery based systems know that temperature compensation is important. Without it, battery banks are not optimally charged, resulting in poor performance and decreased operational life. However, many installers are not familiar with some of the technical subtleties related to temperature compensation, appropriate charger setpoints and the importance of verifying temperature compensated voltages.

Battery Temperature and Charging Voltages

Battery charging voltages should be corrected based on battery temperature. This adjustment is referred to as temperature compensation, a charging feature that helps ensure that a battery is neither undercharged nor overcharged regardless of battery temperature. All chemical reactions are affected by temperature. Battery charging is an electrochemical reaction, so it too is affected by temperature. Specifically, cold batteries require a higher charge voltage in order to push current into the battery plates and electrolyte, and warmer batteries require a lower charge voltage to eliminate potential damage to valve regulated lead acid (VRLA) cells and reduce unnecessary gassing if flooded cells are used.

Using normal target voltages to charge a battery that is colder than approximately 25ºC (77ºF) will result in an undercharged battery, which will deliver lower performance, reduced life and a higher life cycle cost. Applying normal target voltages to a battery that is hotter than 25ºC may result in an overcharged battery. This condition could lead to the drying out of VRLA battery cells. With flooded cells, the result will be excessive outgassing, increased battery maintenance in the form of more frequent watering and reduced battery life due to thermal stress. In fact, some battery manufacturers and charger manufacturers recommend not charging a battery that is 50ºC (122ºF) or hotter.

In the past, it was common to manually increase a charger’s target voltages to charge a cold battery during the winter or to manually decrease the target voltages to charge a warm battery during the summer. Some early chargers included switches to adjust target voltages over coarse temperature ranges. However, target voltages in many chargers, such as automotive chargers and those built into generators, usually cannot be adjusted. Today, the prevalent solution featured in most photovoltaic charge controllers and inverter/ chargers is automatic temperature compensation. A remote battery temperature sensor (RTS) is attached to one battery in the bank, and the charger uses electrical data from the RTS to determine battery temperature and automatically adjust the target charge voltages accordingly.

Since charging efficiency is less than 100%, batteries typically warm up as they are charged. Fluctuations in ambient temperature also cause battery temperature to change. Automatic temperature compensation allows chargers to dynamically adjust target voltages during the charging process as battery temperature changes and ensures optimal charging. For example, the target absorption and float voltages for a set of cold batteries on a cool morning might be relatively high. However, in response to changing RTS data, the charger will automatically decrease the target voltages as the batteries and ambient environment warm up.

Temperature Compensation Formulas

The most widely used temperature compensation formula is:

-0.005 V per ºC per 2 V cell.

An equivalent variation is:

-0.028 V per 10ºF per 2 V cell.

Some batteries, such as those manufactured by Concorde, have more complicated temperature compensation formulas. The formulas listed here work well enough over the temperature range that batteries are subjected to in most photovoltaic applications. Because each formula includes a negative multiplier, the slope is negative— as battery temperature decreases, charging voltage is increased and vice versa. Since each formula takes battery voltage into consideration (more 2 V cells in series equals higher voltage), the slope is steeper for a 24 Vdc nominal battery bank than for a 12 Vdc nominal bank, and steeper still for a 48 Vdc nominal battery bank.

To understand and apply these formulas, you need to know three parameters specific to a given system or equipment: charger reference temperature, battery temperature and nominal battery voltage. The typical reference temperature for most chargers is 25ºC. If the RTS value indicates the battery is below 25ºC, the charger increases the target voltages, subject of course, to system capability. If the RTS value indicates the battery is above 25ºC, the charger decreases the target voltages. Why 25ºC? Batteries generally exhibit their optimal combination of energy storage (amp-hours: AH) and life cycles at about this temperature.

Nominal battery voltage is determined by how many cells make up a given battery bank. Virtually all lead acid battery cells are 2 Vdc nominal. Therefore, individual batteries or strings of batteries will have the following nominal voltages based on the number of cells:

6 cells = 12 Vdc
12 cells = 24 Vdc
24 cells = 48 Vdc

Using the above formula, the correct temperature compensation for a charger with a 25ºC reference temperature and a 48 V, 24-cell battery bank operating at 10ºC (-15ºC from the charger’s 25ºC reference) is:

-0.005 V x -15 x 24 = 1.8 V

If a manufacturer’s recommended absorption voltage for a nominal 48 V battery bank at 25ºC is 59 V, then the temperature compensated absorption voltage for that battery bank at 10ºC would be:

59 V + 1.8 V = 60.8 V

Temperature compensation applies to float mode target voltage as well. For example, if a manufacturer’s recommended float voltage for a nominal 48 V battery bank at 25ºC is 54.8 V, then the temperature compensated target float voltage for that battery bank at 10ºC would be:

54.8 V + 1.8 V = 56.6 V

The application of temperature compensation to a charger’s equalization (EQ) mode varies among charger and battery manufacturers. Check if your battery manufacturer recommends EQ at all, since most VRLA battery manufacturers do not recommend regular EQ cycles. If EQ temperature compensation is recommended, and if the charger includes a temperature compensated EQ mode, system specific settings may be required, which are beyond the scope of this article.

Normalizing Target Voltages

There are important exceptions to the guidance given earlier. Specifically, some battery manufacturers specify target charging voltages at temperatures other than 25ºC, which may require target voltages to be normalized. Some manufacturers also set limits on how much temperature compensation to apply. Trojan Battery, for example, uses the temperature compensation formulas listed earlier, but its online charging instructions specify target charging voltages based on a battery temperature of approximately 27ºC. Setting charging voltage setpoints for a charger with a 25ºC temperature compensation reference requires that the Trojan settings be normalized for the charger.

For example, the 27ºC target voltages for absorption and float modes for a 48 V Trojan Battery bank are 59.2 V and 52.8 V respectively. In this case, the temperature compensation offset for a charger with a 25ºC reference is:

-0.005 V x (25 – 27) x 24 = 0.24 V

Accordingly, the normalized voltage settings for charging these batteries from a charger with a 25ºC reference are:

59.2 V + 0.24 V = 59.44 V for absorb mode
52.8 V + 0.24 V = 53.04 V for float mode

In contrast, MK Battery’s online instructions specify target charging voltages based on a battery temperature of 20ºC. Programming voltage setpoints for a charger with a 25ºC temperature compensation reference requires that the MK Battery settings be normalized for the charger. For example, the 20ºC target voltages for absorption and float modes for a 48 V battery bank are 57.6 V–58.3 V and 54.0 V respectively. In this example, the temperature compensation offset for a charger with a 25ºC reference is:

-0.005 V x (25 – 20) x 24 = -0.6 V

Accordingly, the normalized voltage settings for charging these batteries from a charger with a 25ºC reference are:

(57.6 V–58.3 V) – 0.6 V = 57.0 V – 57.7 V for absorb mode
52.0 V – 0.6 V = 51.4 V for float mode

Finally, some battery manufacturers establish limits on how much temperature compensation to apply. They set one limit on how much additional voltage to apply to very cold batteries or a second limit on how much to reduce the voltage applied to hot batteries, or they may specify both. To accommodate these limits, some chargers include a temperature compensation limit feature. This allows users to set temperature compensation limits in accordance with their battery manufacturer’s recommendations.

Verifying Temperature Compensation Setpoints

Verifying battery temperature compensation functionality and settings is recommended during the commissioning of battery based photovoltaic systems. Ensuring proper charging will optimize battery performance and increase the operational life of the bank. For systems with VRLA batteries, verification is especially important. Overcharging of VRLA batteries can dry out the cells by causing unwanted outgassing. Verification will ensure that the RTS is functioning properly, and that charge controllers and inverter/chargers have been programmed correctly. The tools required include a digital multimeter, an infrared (IR) thermometer and a calculator.

Battery temperature can be determined using a variety of methods. With an RTS connected, some chargers can display battery temperature. If battery temperature information is not available from the charger directly, use an IR thermometer to measure battery temperature. IR thermometers are inexpensive tools and handy for a variety of uses beyond measuring battery temperature. These include measuring the temperature of system components such as PV modules, breakers, busbars, conduits and the like during system performance verification or troubleshooting. Radio Shack sells an inexpensive IR thermometer, and companies such as Fluke sell industrial grade models. Once the battery temperature has been measured, temperature compensation can be quickly verified in the field.

The following verification example assumes:

  • a normalized system;
  • a 48 V nominal Trojan Battery bank (24 each 2 V cells);
  • a programmed target absorption mode voltage of 59.2 V;
  • the system is in absorption mode;
  • measured battery temperature of 12ºC.

In this case, the correct temperature compensated absorption voltage indicated on your voltmeter should be:

59.2 V + (-0.005 V x (12 – 27) x 24) = 59.2 V + 1.8 V = 61.0 V

Jim Goodnight / PV system design consultant / Vienna, VA

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[Santa Fe Springs, CA] Since October 2010, Trojan Battery Company has been testing its deep-cycle, flooded industrial batteries to the IEC 61427 testing protocol. IEC designed the accelerated-cycle endurance testing parameters to replicate conditions that batteries deployed in PV applications are subjected to. The testing parameters include heavily discharging the batteries and exposing them to a number of shallow cycles at different states of charge. The results compiled demonstrate that Trojan Battery’s industrial line has surpassed the equivalent of a 15-year cycle-life test, outperforming the products’ ten-year, 1,500-cycle design life.

Trojan Battery / 800.423.6569 /

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Before the advent of modern maximum power point tracking (MPPT) photovoltaic controllers, configuring a PV array for a given battery bank’s nominal voltage was a fairly simple exercise. Older series-type pulse-width-modulation charge controllers had a simple 1:1 relationship with the battery bank. For example, a 12 Vdc-nominal module operating at approximately 17 Vmp could be used to charge a 12 Vdc-nominal flooded-cell lead acid (FLA) battery, which typically requires about 14.4 V during the absorption cycle and about 15 V for equalization charging. Because of this simple relationship, array voltage received minimal concern during the design stage, other than correctly sizing the PV-to-controller wiring to minimize voltage drop. Similarly, calculating maximum circuit current to specify the PV controller and overcurrent protection devices was fairly straightforward.

With today’s more advanced charge controller technology, MPPT controllers are the industry standard. They offer significant advantages over non-MPPT controllers, including optimized energy harvest and the option to configure the array at higher voltages than the nominal battery voltage. Most MPPT controllers have dc-to-dc voltage stepdown functionality, which allows you to use a high-voltage array for lowvoltage battery charging. The benefits of higher array voltages include lower array currents, reduced power loss in the homerun wiring, reduced conduit size and cost, and the option to locate the array farther from the battery pack to minimize any potential shading issues. Installers always prefer smaller-gauge conductors, because they are easier to work with.

By nature of their operation, MPPT controllers deliver improved system performance and can reduce copper costs when compared to non-MPPT controllers. However, for optimal performance, they also present greater system design complexity. Factors that must be considered during the design phase include battery charging voltage requirements, the use of high-voltage arrays, the evolving requirements of the National Electrical Code, the impact of a site’s annual ambient temperature range on array voltage and the characteristics of the modules specified.

At a battery reference temperature of 25°C (77°F), a 48 Vdc-nominal FLA battery bank typically requires net charging voltages of approximately 59 Vdc for the absorption stage and 62 Vdc for the equalization stage. MPPT controllers typically have temperature-adjusted operational limits between 140 Vdc and 145 Vdc, with absolute voltage limits of 150 V. In addition, most readily available circuit breakers used in dc applications carry a 150 Vdc rating. At first glance, the 91-volt span between 59 Vdc and 150 Vdc may seem fairly large, but operational and NEC considerations shrink that range into a fairly narrow “sweet spot” in short order. Consider, for instance, a relatively extreme example where the array will be operating in an environment that is very hot in the summer and very cold in the winter.

A key operational trait of the dc-todc buck-type converter used in many MPPT controllers is that the output voltage is always lower than the input voltage—a 2 Vdc drop is common. Combine this loss with another 2 Vdc drop in the conductors between the array and the battery, and the array’s operational maximum power point voltage must always be about 4 V higher than a battery bank’s target charging voltages.

In addition, a module’s maximum power voltage (Vmp) at STC is based on an illuminated cell temperature of 25°C in a laboratory environment. Because PV cells and modules frequently operate at approximately 25°C to 35°C above ambient temperature, a PV module really cannot be expected to produce fullrated power unless the ambient temperature is approximately -10°C. A module’s temperature-related power variance is manifested primarily as a change in output voltage. For crystalline modules, a typical open-circuit voltage temperature coefficient is -0.35%/°C. The module’s voltage drops as the cell temperature increases. In many locations, it is not uncommon for cell temperature to reach 65°C or higher at mid-day in the summer (30°C to 35°C ambient plus 30°C to 35°C cell temperature rise above ambient). In this case, the actual cell temperature will be about 40°C above the 25°C STC temperature. With these assumptions, the resulting voltage drop percentage due to elevated cell temperature is: 40°C x -0.35%/°C = -14%.

In this example, the array’s operational voltage is about 86% of the STC specifications (100% – 14%). Put another way, the array’s STC Vmp specification needs to be 116% of the estimated minimum operational voltage required. With this percentage in hand, you can now specify the array’s minimum voltage at STC: (59 V (minimum target battery voltage) + 4 V (loss in CC and wiring)) x 116% = 73 V.

While a module’s voltage drops when the cell temperature rises, the voltage will increase as the temperature falls, so a second calculation is required. NEC Article 690.7 provides correction factors for calculating maximum voltage based on STC open-circuit voltage and lowest expected ambient temperature. The 2008 NEC requires you to use the PV module’s voltage temperature coefficient in this calculation, if it is available. Using the record low temperature for the array’s location is common practice during system design.

Record low temperatures approaching -40°C are not uncommon in some US locations. For example, according to, the record low temperature is -27°C for Santa Fe, New Mexico, -31°C for Denver, Colorado, and -38°C for Lander, Wyoming, while average summer high temperatures are typically near 30°C.

Modules at -40°C are 65°C colder than their STC specification parameter. Continuing to use the -0.35%/°C temperature coefficient, the cold temperature voltage multiplier is: 1 + (-65°C x -0.35%/°C) = 122.75%.

In order to remain compliant with NEC 690.7 and keep the temperaturecorrected maximum voltage below the controller’s absolute 150 Vdc limit, the array’s Voc at STC is calculated as: 150 Voc (absolute limit) ÷ 122.75% (cold ambient temperature multiplier) = 122.2 Voc.

Vmp is typically about 80% of Voc. Therefore, the array’s Vmp limit for this exercise is: 122.2 V x 80% = 98 V.

Accordingly, the suitable array Vmp at STC range has narrowed considerably to a minimum of 73 V and a maximum of 98 V.

Finding modules with the right STC voltage specifications for the site temperature range in the above example used to be a daunting challenge. Two 72-cell modules in series (about 68 Vmp at STC) results in an array voltage that is below the minimum 73 Vmp at STC value. Three 72-cell modules in series (about 102 Vmp at STC) results in an array voltage that is greater than the maximum 98 Vmp at STC value. One popular solution was to configure five 36-cell modules in series, for an array voltage of approximately 85 Vmp at STC that fit comfortably between the 73 V and 98 V limits. However, 36-cell modules have low power ratings and a high cost per watt compared to 72-cell modules. The combination of higher specific-power and labor costs resulted in a relatively expensive array.

Fortunately, the marketplace has addressed and solved these issues of module specifications and cost. Wiring five 36-cell modules in series creates strings with 180 cells in series operating at about 85 Vmp at STC. Several manufacturers now offer large-format 60-cell modules. Configuring three of these modules in series results in an equivalent 180-cell string. These manufacturers include BP, Canadian Solar, REC, Sharp and SolarWorld. Other solutions are also available. Canadian Solar, Day4Energy, Kyocera and Sharp produce 48-cell modules, which create 192-cell strings when wired four in series. This approach works quite satisfactorily over broad temperature ranges as well.

Jim Goodnight / Schneider Electric / Vienna, VA /

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While ac-coupling system architecture has been in development for about two decades and has been maturing in recent years, in some ways ac coupling is still the Wild West of renewable energy applications. The majority of the solar industry understands the design and installation of grid-direct inverter systems well. In ac-coupled applications, these grid-direct systems are integrated with battery-based inverter systems. The effective design and deployment of these combined systems quickly becomes complicated on several fronts.

First, ac coupling can be utilized in both utility-interactive and off-grid projects. These two system types have both fundamental and subtle differences in design requirements and operation when ac coupling is employed. Second, the majority of system designers and installers do not have much, if any, experience with battery-based systems, and even fewer have experience with ac-coupled systems. This results in a steep learning curve for many. Third, and perhaps most important, while fully integrated equipment platforms are available, many ac-coupled systems currently utilize equipment from different manufacturers. This mix of equipment adds complexity to ac-coupled system designs and presents challenges related to the amount of experience a given inverter manufacturer has with the use of its products in ac-coupled systems and the level of support it is able or willing to provide. For example, several grid-direct string inverter manufacturers, and most microinverter manufacturers, do not offer a warranty or provide support for their products if they are installed in ac-coupled systems.

An Introduction to AC Coupling

SMA Solar Technology began developing ac-coupling system platforms using its inverter products in the 1990s. I was first introduced to the concept while editing an article, “AC Mini-Grids,” for the October/November 2005 issue of Home Power magazine authored by Dana Brandt. The article reported on one of the first commercially deployed ac-coupled systems, which formed a microgrid in a remote village in Uganda. In the years that followed, SMA continued to develop and refine its products and integrated approach to ac coupling. In addition, inverter manufacturers Magnum Energy and Schneider Electric modified some of their battery-based inverter models for more seamless integration with ac-coupled systems by adding frequency-shift functionality to regulate battery charging. Currently, SMA and Schneider Electric manufacture both grid-direct and battery-based inverters that can be utilized to develop a complete ac-coupled system using equipment from a single manufacturer.

On a basic level, ac-coupled systems differ from their more conventional dc-coupled counterparts in one primary way—power generated by renewable resources, including PV arrays and wind or hydro turbines, is processed by grid-direct string inverters connected to the ac-output bus of a batterybased inverter system. Such systems can also integrate ac backup generators, with limitations in some cases, into the generation mix. In ac-coupled systems, grid-direct inverters essentially replace dc-charge controllers and frequently PV source-circuit combiner boxes as well. The absence of the dc-charge control in the system requires different and often combined approaches to battery-charge regulation. In ac-coupled systems, battery regulation is accomplished using several methods, including frequency-phase shift, blackout relays, and diversion controllers and loads that regulate the ac output of the grid-direct inverters. These approaches can range from seamless phase-shift approaches that modulate PV array generation based on ac-load demand and battery state of charge, to potentially complex networks of diversion loads driven by multiple voltagesense relays.

This article compiles information from several sources to present an industry-wide perspective on equipment selection and best practices for ac-coupling system design and installation in stand-alone and utilityinteractive systems. Four manufacturers of battery-based inverter/chargers provide technical insights related to the use of their products in ac-coupled system architectures. We also reached out to industry colleagues to share their direct experiences—both positive and negative—with deploying ac-coupled systems in the field. This issue of SolarPro also includes a comprehensive grid-direct inverter product specifications table (click here) that identifies which string inverter manufacturers offer a warranty on and support their products in ac-coupled applications.

Magnum Energy Battery-Based Inverters

By Gary Baxter and Brian Faley, Magnum Energy

Magnum Energy designs and manufactures battery-based inverters for use in stand-alone applications and gridconnected systems that require battery storage to provide uninterrupted power during utility-grid failures. In both applications, Magnum Energy permits and supports ac-coupled system designs that synchronize the ac output of utilityinteractive string inverters from various manufacturers with its battery-based inverter/chargers. We have made specific software upgrades to some of our inverter models to better support ac-coupled systems, and we have additional related products in development.

Recommending the addition of a battery-based inverter system to your clients with grid-direct string inverter systems can be a profitable up-sell. Even when customers have been clearly informed that their grid-direct PV system will not produce power during utility outages, they may have an after-thefact realization that they do want a backup system after they experience frequent or extended utility-grid failures.

With the addition of a battery bank, a critical-loads subpanel and a diversion control and load, Magnum battery-based inverter/chargers can be ac-coupled with existing grid-direct inverter systems. The dc side of the existing string inverter system does not need to be rewired. The ac input and output circuits of Magnum MS-PAE inverter/chargers can be connected in parallel with a home’s ac wiring without damage to the inverter. These models can operate as a stand-alone inverter/ charger in Standby mode, which allows battery charging from the grid with ac transfer to connected loads. Magnum MS-PAE inverters are listed to UL 1741 as stand-alone inverters, not as utility-interactive inverters. These products are not designed to export power to the utility grid. Therefore, the ac output of the inverter should not be connected directly to the utility power-distribution circuits. These inverters can operate in parallel with the ac-wiring circuits only when the utility power is connected to the ac input of the inverter and the inverter is operating in Standby mode.


When working with ac-coupled systems, it is beneficial to understand how a battery-based inverter operates before and during a power outage. During normal operation (see Figure 1), the utility grid provides the ac voltage and frequency reference required for the synchronization and operation of the string inverter. When the Magnum battery-based inverter/ charger operates in Standby mode, the inverter utilizes the utility grid and the ac output of the string inverter to maintain the battery bank’s state of charge and passes power through to the circuits in the critical-loads subpanel. In such a system, the Magnum inverter/charger is connected as a backup inverter and supplies inverted ac power from the battery to the critical loads only when the grid is down. The grid-direct string inverters are connected on the load side of the Magnum inverter, in parallel with the reference grid power when available or with the inverter power during a grid failure.

During a utility-power interruption (see Figure 2), both the battery-based inverter/charger and the utility-interactive inverter automatically disconnect from the grid. Once this occurs, the battery-based inverter begins inverting and initially uses energy stored in the battery to power the critical loads connected to the ac subpanel. Because the ac output of the battery-based inverter is connected to the same circuit as the utility-interactive string inverter, the string inverter synchronizes with the battery-based inverter’s ac-output voltage and frequency. After a required 5-minute disconnect, the string inverter reconnects and starts processing the power from the PV array, charging the battery and supplying power to the critical loads.

With the string inverter synchronized to the output waveform of the Magnum inverter/charger, the string inverter processes all the energy the PV array generates. When the grid is present, household loads normally consume this energy, with any excess exported to the utility grid. During a power outage, however, noncritical loads terminated in the main service panel are not connected to the system, and the utility grid is no longer present. As a result, any excess power that the loads connected to the system’s subpanel do not consume is pushed back through the ac output of the battery-based inverter and into the battery bank.

Since this is not the normal path for incoming current, the battery-based inverter/charger cannot regulate the current or control the battery voltage. This brings up two important points. First, the Magnum battery-based inverter must be rated to handle the full power output of the PV array. The maximum ac-output power of the PV/string inverter system must be no greater than 90% of the continuous power rating of the Magnum inverter system. Second, the system must include a means to regulate the battery voltage to prevent an overcharge condition. You can best accomplish this with a two-step regulation approach that combines frequency shift with diversion control.

Some Magnum battery-based inverters include a feature that allows the ac-output frequency to shift when the battery voltage rises to a predetermined level. Magnum’s MS-PAE Series inverter/chargers (revision 4.1 and higher) include an AC-Coupled Support mode. When activated, this causes the inverter-output frequency to shift to 60.6 Hz. This mode is enabled using an optional Magnum remote that allows the battery type setting to be set to custom. It activates when the battery voltage increases by 2 V ( for 24 Vdc nominal inverters) or 4 V ( for 48 Vdc nominal inverters) above the absorb voltage setting. The frequency returns to 60.0 Hz when the battery voltage falls 2 V or 4 V below the absorb voltage setting for 24 Vdc and 48 Vdc nominal inverters, respectively. This frequency shift protects the battery against overcharging by dropping the ac-coupled grid-direct inverter off-line. Activating the AC-Coupled Support mode is one method of regulating ac-coupled string inverters. However, this battery-protection approach does not enable three-stage battery charging. We therefore recommend that frequency shift be viewed as a secondary approach to a primary diversionbased battery-management system that provides more advanced battery-charging functionality.

In most systems, dc or ac diversion loads should be added in parallel with the battery to reduce the on/off cycling of the grid-direct string inverter that frequency shift would otherwise control. Relying solely on the frequency-shift method is rather crude because it is essentially a bang-bang controller— off or on—and once the frequency-shift happens, the string inverter attempts to reconnect every 5 minutes. While this approach is technically sufficient to prevent battery overcharging, is it optimal to have the battery voltage repeatedly swinging around by several volts? A more sophisticated option is to employ a diversion-based battery-management system. These regulation systems can utilize a dc diversion controller with dc resistive loads and/or ac resistive loads driven by dc-controlled relays. In a dc or ac diversion system, three-stage battery charging is maintained and the surplus energy from the string inverters can be put to work rather than just taking the PV system off-line.

To better support ac-coupled systems, Magnum is developing the AC Diversion Controller, which is optimized for use with Magnum MS-PAE Series inverter/chargers. This controller maximizes the use of on-site–generated PV power by diverting excess energy to ac loads such as domestic waterheater tanks. It includes complete three-stage battery charging functionality and also supports inverter frequency shift as a fail-safe protection against battery overcharging. The AC Diversion Controller communicates with Magnum MS-PAE Series inverter/chargers and automatically diverts excess current into specified diversion loads. When a diversion load such as an electric water heater reaches its regulation setpoint, excess current is diverted to a resistor bank. Alpha versions of the system are currently operating very well with SMA and Solectria Renewables string inverters, and additional testing is under way. Magnum Energy has started the listing process for the AC Diversion Controller system with ETL. The product is currently scheduled for release in Q4 2012.

OutBack Power Technologies Battery-Based Inverters

By Phil Undercuffler, OutBack Power Technologies

For many PV system designers, a watershed moment comes when they realize that they can connect a grid-direct inverter to the output of a battery-based inverter. The flexibility and scalability of these ac-coupled system architectures provide benefits over dc-coupled systems in some cases. In the retrofit market, ac coupling may be a good solution when customers with existing grid-direct systems suddenly realize that their substantial investment in solar power is unusable during a power outage. Off-grid projects with large daytime ac loads and sites with multiple buildings or significant array-to-battery distances may also be good candidates for an ac-coupled design approach. However, today’s higher voltage dc-charge controllers have offset some of the commonly perceived advantages of ac coupling. In many applications, dc coupling can provide more reliable and stable operation than can ac coupling and ultimately makes more sense.

OutBack Power Technologies designs and manufactures a full range of products, including stand-alone and utilityinteractive battery-based inverter/chargers that can be utilized in both dc- and ac-coupled systems, and high-efficiency MPPT dc-charge controllers. While ac coupling seems like a simple concept, ac-coupled systems have nearly endless ramifications, implications and subtleties. The following insights and guidelines, based on my experience supporting the integration of OutBack products in ac-coupled systems, will assist you in the development of optimized and reliable ac-coupled installations and help you make informed and accurate choices when deciding between ac-coupled and dc-coupled system designs.

Grid-direct inverters are current-source inverters. They convert power generated by a PV array from dc to ac, but rely upon an external ac source to operate because they cannot create an independent ac-voltage waveform. In contrast, multi-mode battery-based inverter/chargers are voltagesource inverters. In Stand-Alone mode, they generate an ac voltage and frequency supply independent of any external ac power source. Some models can also operate in a Utility- Interactive mode that exports excess PV array generation to the utility in a similar fashion to grid-direct inverter systems.

Battery-based voltage-source inverters can provide a stable ac voltage and frequency reference that allows griddirect current-source inverters to operate when the grid is not present. In this operational mode, ac PV generation from the string inverters is synchronized with the batterybased inverter output via a critical-loads subpanel and is consumed first by local loads, including battery charging. If loads exceed PV production, the system meets the deficit with energy pulled from the batteries.

In most ac-coupled systems, the battery-based inverter must reliably process the entire output of the connected ac PV generation from the string inverters under all conditions. My experience indicates that the battery-based inverter must be sized to more than 125% of the power rating of the connected ac-coupled array. Multiple OutBack Radian inverters can be stacked in parallel at 120/240 Vac. Our standard FX and VFX inverter models can be stacked in both series and parallel configurations to increase capacity as well. If a single FX inverter is ac-coupled with a 240 Vac grid-direct inverter, an OutBack autotransformer can be used to step down the grid-direct inverter’s output voltage to 120 Vac (see Figure 3 , p. 80). If multiple OutBack inverters are stacked to increase capacity in ac-coupled systems, the Power Save function must be defeated by setting the master-power save level to 1 on the master inverter and the slave-power save levels to 1 on all slave inverters. In addition, there should be at least 100 Ah of battery capacity at 48 Vdc nominal per 1 kW of array power to ensure that the battery capacity is sufficient to absorb the PV output without excessive heating, which can damage batteries or shorten their service life.

One aspect of ac-coupled systems you should consider is that the battery-based inverter must be able to provide a stable ac supply to meet the default IEEE regulatory limits of the grid-direct inverter. Battery-based inverters used in ac-coupled systems must have good voltage regulation and must be sized to support the largest expected motor-starting surge without allowing voltage to sag or spike. Any instability in the ac supply due to poor regulation during power surges caused by local loads or excessive voltage drop in the ac wiring results in unstable operation and reduced PV output due to the grid-direct inverter dropping off-line. In addition, integrators have learned—sometimes the hard way—that some grid-direct inverters are more sensitive to changes in ac supply than others and that several string inverter manufacturers do not support the use of their equipment in ac-coupled applications.

Another complicating factor is the integration of motordriven ac generators with ac-coupled systems. For backupgenerator– based system charging, the battery-based inverter must shift its frequency to synchronize with the new ac input source when the generator is running. Once connected, the generator becomes the new ac voltage and frequency supply for the system, including the ac-coupled string inverter. The initial inverter/generator synchronization often results in the grid-direct inverter disconnecting from the system. Few motor-driven generators can provide sufficient voltage and frequency regulation to meet the IEEE regulatory requirements for grid-direct inverters to ensure stable operation. More important, generator electronics can be damaged if they are subjected to back-fed current from the string inverters. Therefore, ac-coupled systems are often designed to prevent input from ac-coupled string inverters and generators at the same time. If this is the case, the generator must be sized to not only charge the batteries, but also power all ac loads to make up for the PV generation that is lost because the string inverters are off-line. Frequently, this scenario ends up requiring a larger generator than would be necessary if the PV array was simply dc coupled.

Microinverters and AC Coupling

Microinverters, and more recently ac modules, have redefined the industry’s notion of modularity over the past few years. The modular and expandable platform ac coupling provides makes it seem like a natural fit with the growing number of microinverters and ac modules entering the market. However, these products are almost entirely absent from the ac-coupled application landscape. SolarPro editors asked several microinverter and ac module manufacturers, as well as two companies that have microinverter products scheduled for release in 2012, about the use of their products in ac-coupled systems. While the responses were not always definitive, they do serve to clarify the manufacturers’ positions.

Enphase Energy is the leading microinverter manufacturer in the US and is currently expanding its presence in the European market. As such, questions from integrators who are interested in developing microinverter-based ac-coupled solutions often revolve around using Enphase products. While Enphase does informally permit the use of its microinverters in ac-coupled systems, it has not devoted internal resources to testing or developing support services for its products in ac-coupled applications. Considering the comparable sizes of the grid-direct and ac-coupled markets, Enphase understandably has a deep focus on other priorities. As a result, while this is not explicitly stated, its warranty terms currently exclude the use of its products in ac-coupled systems.

Enecsys, a European microinverter manufacturer with listed and CEC-eligible products for North America, has a similar position to Enphase. The company does not have any immediate concerns about using its products in ac-coupled systems that operate within normal grid specifications, but its warranty coverage does not currently include this use.

Exeltech recently released one of the first fully integrated ac modules in the US market. The company does not have any warranty restrictions regarding the use of its AC Module product in ac-coupled systems, provided that those systems meet several conditions. Its position could change in the future if Exeltech finds that the ac-coupled system topology is detrimental to its product. General prerequisites it currently notes include the following: A means must exist to disconnect the system from the utility in the event of grid failure, allowing the battery-based inverter to continue providing power to selected loads; the battery-based inverter must be designed to work with grid-direct inverters in a manner that is not detrimental to either device; and the battery-based inverter must employ a universal, nondestructive method such as momentary frequency shift to disconnect the ac modules when the batteries are fully charged and power production exceeds the requirements of the system’s critical loads.

Both Power-One and SMA America have microinverter launches scheduled for 2012. Power-One’s AURORA Micro 250 and 300 products (250 W and 300 W, respectively) are in final evaluation and beta-site implementation. The expected production ship date of these products is July 2012. At this point, Power-One’s microinverters have not been tested with battery-based inverters in ac-coupled applications. SMA has scheduled its Sunny Boy 240 (240 W) microinverter for release in early fall. Deploying the Sunny Boy 240 in ac-coupled systems will not void the warranty. The product is designed to be compatible with SMA’s Sunny Island system with special considerations, but the details of these are not yet available.

Integrators would undoubtedly welcome microinverters with full warranties and support for use in ac-coupled systems. However, the reality is that the potential market for these products in ac-coupled systems pales in comparison to the size of the grid-direct market that microinverter and ac-module manufacturers are focused on. While only a few of these manufacturers have devoted resources toward the testing and support of their products in ac-coupled systems, it is likely that additional manufacturers will follow suit as ac-coupled systems become more common.

Determining the best approach for regulating excess PV generation is a primary challenge when designing an ac-coupled system for stand-alone or utility-interactive applications. This is further complicated when systems utilize equipment from different manufacturers. In dc-coupled systems, traditional methods of controlling PV power involve some variation of pulse-width modulation (PWM) to regulate the output of the PV array and optimize battery charging. However, PWM regulation approaches do not apply to ac-output regulation for a grid-direct inverter. Therefore, the typical methods available for regulating the energy balance in ac-coupled systems are to either knock the grid-direct inverter off-line using a blackout relay or frequency-phase shift, or absorb excess generation using diversion loads.

The ideal regulation strategy for a specific application varies based on the amount of time the system is expected to operate in Off-Grid mode. In grid-tied, ac-coupled systems, the string inverter spends most of its time in Grid-Direct mode, where it is synchronized to the grid’s voltage and frequency reference. Assuming a relatively stable utility supply, the string inverters are ac coupled with the battery-based inverter’s output during infrequent, short-term outages only. In this case, it is acceptable to rely on a simple control method such as blackout relays or the frequency-shift functionality provided by some batterybased inverters to drop the string inverters off-line. If the system is off-grid or the utility-power source to the site is unstable, a more sophisticated regulation approach is recommended.

Knocking the PV generation off-line using frequency shift is perhaps the easiest, least expensive way to control excess generation. However, when the system is operating within IEEE regulatory limits, this approach is an all-or-nothing solution. Once the frequency exceeds a window of 59.3 Hz to 60.5 Hz, the grid-direct inverter disconnects and ceases to export power. In addition, once the inverter is dropped off-line, it remains off-line for 5 minutes, and the battery must be able to support the full ac load for the duration of the string inverter’s waiting period. This is often referred to as the 5-minute sledgehammer. Using a blackout relay to drop the string inverter off-line results in a similar system operation.

If an ac-coupled system includes multiple string inverters, a more sophisticated approach is to utilize multiple staged voltage-controlled relays to regulate each inverter’s output. This method provides more granular regulation by shedding PV generation in smaller increments. In this configuration, as the batteries approach full charge, a portion of the PV array can be knocked off-line, leaving the remainder operating to support the ac load.

Compared to frequency-shift or relay-based regulation approaches, using diversion loads to control excess generation provides more stable and reliable operation, as well as more sophisticated battery-charging functionality. A diversion controller regulates in seconds or milliseconds and provides much finer resolution than a 5-minute array/string inverter disconnect. PWM diversion controllers shunt excess power to a dc load and provide a tapered, temperature-compensated charge to the battery. Depending on the size of the array, one possible limitation is that large dc-diversion loads may not be common or readily available. However, ac-diversion loads such as space heaters and water heaters are inexpensive and commonly available, and can put excess PV generation to good use. When using dc- or ac-diversion loads, remember that they must always remain available and should be sized to absorb the maximum PV generation expected. To protect against battery overcharging, you should build some redundancy into diversion-load systems.

All OutBack FX and VFX inverter models include a 12 Vdc programmable auxiliary output with adjustable standard algorithms that can drive an external relay or contactor to control excess generation. OutBack’s Radian inverter includes a 12 Vdc auxiliary output as well as a 10 A 250 Vac/30 Vdc dry-contact relay that can independently control diversion loads or supplemental relays. One counterintuitive aspect of the OutBack inverter auxiliary programming is that the DC Divert function is preferred when systems are ac coupled.

A general lack of standardization is an issue throughout various segments of the PV industry, including ac-coupled applications. Successful ac coupling requires a delicate balance between energy production, battery charging and total load demand, and, ideally, communicating that balance across multiple brands of equipment. Ultimately, industry stakeholders need to develop a universal, interoperable method for ac coupling by adopting a standardized control structure to ramp up PV production as required.

One way to achieve this standardization is to use the structure codified in the newly adopted German standard VDE-AR-N 4105, which lays out a method of frequencydependent active power control. Designed for stabilizing the European utility grid during periods of excessive renewable generation, it outlines a structure whereby PV inverters decrease output at a defined rate as the grid’s frequency rises, ramp up production upon return to normal and soften the transition upon reconnect. Battery-based inverters could use this method to control the output of any number of VDE-AR-N 4105–compliant grid-direct inverters as required, providing designers with freedom of choice when selecting components for ac-coupled systems.

Schneider Electric Battery-Based ​​​and Grid-Direct Inverters

By James Goodnight, Schneider Electric

As interest in and deployment of ac-coupled PV systems has grown, Schneider Electric has directed product development and support resources toward these applications. Currently, many ac-coupled systems utilize equipment from multiple inverter manufacturers. This mix of products can create issues with system design, installation and operation and lead to warranty issues in some cases. Schneider Electric is one of two companies that designs and manufactures both utilityinteractive grid-direct inverters and battery-based inverter/ chargers for the North American solar market. Schneider Electric’s solar inverters now feature the Conext product range name, followed by letter designations for the various models. The Conext TX is our newest generation of residential griddirect inverters and replaces the GT inverter models. The Conext TX integrates with the Conext XW battery-based inverter/ charger to create an ac-coupled system.

In residential or light commercial utility-interactive ac-coupled PV systems, all energy sources and loads are connected directly to the ac bus. This system design topology has benefits over dc-coupled systems in some applications. In ac-coupled systems, the dc infrastructure is kept to a minimum by enabling higher voltage PV arrays (up to 600 Vdc). Higher voltage arrays minimize system material costs because smaller, lower-cost conductors, conduits and BOS components can be specified. These components are also more easily handled and installed in the field, which drives down installation labor cost.

Array-to-grid efficiency is improved in ac-coupled batterybased systems as well. In a utility-interactive ac-coupled system with battery backup, the array is connected directly to the utility grid through a grid-direct inverter. In a dc-coupled utility-interactive battery-based system, the array output is connected to the battery bank through a charge controller, which is then connected to the grid through an inverter/ charger. The ac-coupled design approach increases system efficiency by removing a conversion step when the utility grid is present.

Grid-present operation. On Schneider Electric’s Conext XW battery-based inverter/chargers, each of the two ac inputs is equipped with an input relay that closes only when the ac source is qualified and is within the parameters of the customer-adjustable voltage and frequency ranges. Closing the input relay connects the ac source directly to the inverter’s ac-output terminals. In this Pass-Through mode, the XW essentially behaves like any other load as it charges the battery bank using its multi-stage algorithm. This charging feature helps deliver good battery performance and operational life. In ac-coupled systems, if the grid ac voltage and frequency are within limits per UL 1741 and CSA C22.2 No. 107.1, Schneider Electric’s Conext TX grid-direct inverters synchronize with the utility-power reference and process power from the PV array. Local loads consume the energy from the PV array, including the XW charger as it charges the battery bank, and any excess is exported directly to the grid.

No-grid–present operation. The battery-based Conext XW inverter/charger continuously monitors the utility-input voltage and frequency. If the voltage or frequency moves outside the acceptable ranges—for example, during a power surge or outage—the XW opens its input relay, disconnecting all the inverters from the grid. As soon as the relay opens, the XW transfers from Charge mode to Invert mode to provide power to the critical loads terminated in the ac subpanel using energy stored in the battery. The grid-direct Conext TX inverter may detect the temporary loss of ac during this transfer and go off-line until it detects a stable ac output from the XW for a minimum of 5 minutes.

During utility failures, the XW serves as a voltage source for the grid-direct TX inverter, providing tightly controlled voltage and frequency on its ac output. The TX inverter qualifies and synchronizes with the ac-voltage reference provided by the XW just as it would if the utility grid was present. The XW’s anti-islanding feature prevents the export of power from its AC1 connection during a utility outage, and the XW and the TX inverter continue to power backup loads. Any excess power from the TX inverter charges the battery bank in a Bulk Only mode.

When the Conext XW inverter/charger is in Invert mode, electrical current flows through it in either direction. If the Conext TX inverter is providing more power to the ac bus than the loads can consume, current flows back through the XW to charge the battery bank. Unlike in Charge mode, in Invert mode the XW does not regulate charging when power is flowing from its ac output to the battery. During brief grid failures, this is not a problem if the battery is sufficiently discharged. However, if the battery is fully charged and there is not enough load on the ac system, and if the TX inverter continues feeding power to the ac bus, the battery voltage could potentially rise until an overvoltage fault condition (high batt cut out setting) is reached. This causes the XW and the entire system to shut down, including the ac loads terminated at the subpanel, and could result in damage to the battery if high batt cut out is not set appropriately for the installed battery type.

To avoid this mishap, the Conext XW inverter/charger features integrated frequency-phase–shift protection for ac-coupled applications. This strategy varies the line frequency according to a predetermined pattern to prevent the grid-direct Conext TX inverter from overcharging the battery. The XW executes a pattern-generator algorithm that varies the line frequency in a linear manner to avoid overload. The frequency-generation function of the XW changes the ac-coupled grid frequency with a linear rate of change of 0.4 Hz/s. When the charge-bulk voltage is exceeded, the frequency decreases in a linear progression until the TX inverter drops off-line. While the XW and TX inverters are in AC-Coupling mode, the XW changes the frequency only when the charge-bulk voltage setting is exceeded. You can adjust this setting in the custom battery menu.

Once the battery voltage reaches its charge-bulk voltage, the Conext XW shifts its output frequency, causing the TX to disconnect and begin its 5-minute anti-islanding waiting period. No separate control wiring is required. During this period, the ac loads are powered from batteries via the XW only. When the 5-minute waiting period is complete, the TX reconnects to the XW’s ac output and provides power for ac loads and recharging the battery. If the battery is fully charged and the ac critical loads are insufficient to absorb the PV array’s ac output, the TX on-off cycle continues until the grid is restored and the system returns to normal operation.

Schneider Electric’s Conext XW inverter/chargers and TX inverters have been developed to provide a fully integrated ac-coupled system. However, in some applications, ac-coupled systems can be more complex than their dc-coupled counterparts, and integrators tend to have less experience with ac-coupled systems. Here I address specific equipment specifications and use of Conext inverters in ac-coupled systems, as well as general design details that you should consider related to ac-coupled system architectures.

Grid-direct inverter compatibility. Schneider Electric has developed and tested the integration of its Conext XW and TX products in ac-coupled systems. Although this architecture may work with UL 1741/CSA 107.1-01–compliant inverters from other manufacturers, Schneider Electric has not tested these products in ac-coupled systems, so support for systems that integrate other vendors’ products with Conext inverters may be limited.

Stand-alone, off-grid systems. To maximize battery performance and life, the Conext XW– and TX–based ac-coupling architecture is intended for utility-interactive systems connected to a dependable utility grid. Schneider Electric does not recommend or support its ac-coupled system architecture for use in stand-alone, off-grid applications.

Power ratings for single Conext XW installations. The batterybased XW inverter power rating should match or exceed the grid-direct TX inverter power rating. Accordingly, the XW 6048 (6.0 kW/48 Vdc) is compatible with a single TX 5.0 (5.0 kW) or TX 3.8 (3.8 kW) inverter, or with one or two TX 2.8 inverters (2.8 kW each, 5.6 kW total). The XW 4548 (4.5 kW/48 Vdc) and XW 4024 (4.0 kW/24 Vdc) are compatible with a single TX 3.8 or TX 2.8 inverter.

Power ratings for parallel Conext XW installations. In applications that utilize multiple XW inverter/chargers configured in parallel, the total TX inverter power rating should not exceed the power rating of a single XW inverter deployed in the system. For example, while two TX 2.8 inverters can be connected to a single XW 6048, a stacked pair of XW 6048s would also be limited to two TX 2.8 inverters.

Conext XW firmware. To prevent battery damage in ac-coupled applications, XW inverter/chargers should be updated to the latest firmware that includes the ac-coupling feature. At present, XW-specific firmware (version 1.07) is available for each North American XW model and can be downloaded at

Conext XW ac qualification period. The XW and TX products are fully compliant with UL and CSA anti-islanding standards. However, for ac-coupled applications, the XW inverter/charger’s ac-qualification period default setting of 10 seconds must be adjusted to 300 seconds.

Backup generators. Schneider Electric’s ac-coupled system has not been tested with a generator providing the ac reference for TX inverters. If the system includes a backup generator, I recommend installing an “either-or” interlock switch to prevent unintended back-feeding of current from the TX inverter to the generator (see Figure 4, above).

System metering. In ac-coupled applications, the power metering on the Conext XW may not work reliably when the inverter/charger is in Voltage-Source Invert mode and power is flowing back into the batteries.

Terminating ac circuits. The designated Conext XW and TX ac outputs are typically connected in the critical-loads subpanel. Each TX inverter requires its own ac breaker in the subpanel, which is connected to the output of the XW inverter/charger. Although there is space to add breakers for the TX inverters directly into the XW power distribution panel, it is more straightforward to install the TX inverter breakers in the ac subpanel.

Critical load and battery-bank sizing. Critical loads that are terminated in the ac subpanel should be selected based on the customer’s essential safety and lifestyle requirements during utility failures. It is not practical to back up all of a home’s loads. The battery bank should be sized to power the critical loads for a specific time period and to avoid completely discharging the battery bank during utility outages. An occasional 50%–60% maximum discharge may be appropriate. When specifying battery bank Ah capacity for ac-coupled systems, the designer should consider potential excess current that the TX inverter produces while it is powering the critical loads in relation to the battery manufacturer’s charge-current recommendations.

Alternatives to ac coupling. If array-to-battery distance is the primary design driver for an ac-coupled system, you should weigh the potential cost and operational benefits of utilizing a dc-coupled system architecture with a higher voltage dc-charge controller. Schneider Electric manufactures charge controllers rated at 150 Vdc (XW-MPPT60-150) and 600 Vdc (XW-MPPT80-600).

SMA Battery-Based and Grid-Direct Inverters

By Greg Smith, SMA America

In both utility-interactive and stand-alone systems, ac coupling offers a scalable system platform based on grid-quality alternating current. Due to its modular design, suitable applications for ac coupling range from small off-grid or grid-tied residential systems to large stand-alone microgrids developed for village electrification projects. AC-coupled systems are more scalable than dc-coupled systems and can seamlessly integrate diverse charging sources, including PV arrays, wind and hydro turbines, and ac backup generators. In addition, ac-coupled systems can be more easily expanded than dc-coupled systems as ac load and generation capacity is added.

The components that make up an ac-coupled system are themselves another benefit of ac coupling. BOS components for an ac-coupled system are considerably less expensive and more readily available than dc-powered alternatives and simplify everything from system design to ongoing maintenance. AC coupling offers increased planning flexibility, since long distances between the power supply, batteries and loads do not pose the same limitations that they do in high-current dc systems. In ac-coupled microgrids, the connection of additional ac-power sources and loads is possible at almost any point in the system, allowing for subsequent expansion even years after the initial installation.

SMA is no stranger to ac coupling. In fact, it researched the feasibility of this approach to battery-based systems throughout the 1990s with the Institut fu¨r Solare Energieversorgungstechnik with funding from the German Ministry of Finance and Technology. By 2005 it had commercialized ac-coupling technology with the development of a fully integrated system platform that utilized grid-direct and battery-based inverters and controls. Today, SMA continues to expand its offerings for ac-coupled systems with the launch of new products like its Multicluster Box off-grid ac distribution solution.

One of the strengths of SMA’s offerings for ac-coupled applications lies in the highly integrated nature of the products. SMA Sunny Island battery-based inverters and Sunny Boy and Windy Boy grid-direct inverters can be used in conjunction with one another and with backup generators to form a highly integrated stand-alone ac power grid.

To complement the existing Sunny Island 5 kW 5048-US inverter/charger, SMA will soon add two new models to its battery-based inverter family: the 4.5 kW 4548-US and the 6 kW 6048-US. SMA Sunny Island inverters feature peak dc-toac conversion efficiencies of above 95% and offer high-surge capabilities for starting and supporting large inductive loads such as motors and water pumps. For example, the Sunny Island 5048-US model can provide 6.5 kW output for 30 minutes, 8.4 kW for 1 minute and 12 kW for 30 seconds at 25°C. US Sunny Island inverter models have single-phase 120 Vac output. Multiple-inverter systems can be configured for single, splitphase or 3-phase Vac.Sunny Island inverters. SMA’s ac-coupled solution is driven by the bidirectional Sunny Island inverter/charger, which is equipped with sophisticated ac grid-management functions and highly developed battery management that includes full system monitoring. The Sunny Island continuously tracks the batteries’ state of charge, and as system manager makes ongoing decisions based on those states. For example, during operational periods where the batteries are discharged and there is little solar generation, the Sunny Island can remotely and automatically start a backup generator, or even switch off consumer loads using a built-in load-shedding relay parameter. The Sunny Island also determines the optimum strategy for charging the batteries, and in doing so increases their service life.

Sunny Boy inverters. SMA manufactures a wide range of griddirect string inverters that can be used in ac-coupled applications. With rated power outputs of 700 W to 10 kW, these inverters can be fully integrated with and controlled by SMA Sunny Island inverters in ac-coupled systems. In addition, SMA manufactures Windy Boy grid-direct inverters that process power from wind turbines; these can also be integrated with an ac-coupled system platform.

Multicluster Box. For large ac-coupled stand-alone systems, SMA manufactures the SMA Multicluster Box (MCB), an offgrid ac-distribution hub that combines and manages a variety of ac-generation sources in large-scale Sunny Island multicluster systems. While a Sunny Island inverter cluster can be used in grid-tied battery-backup applications, the MCB was developed for standalone 3-phase 208 Vac systems only. A preconfigured ac-distribution board in the MCB allows you to easily connect all the ac components in the stand-alone grid, including batteries, ac generator and renewable energy sources, loads and Sunny Island inverters.

Smartformer. SMA will soon be releasing the recently ULlisted Smartformer, a 120/240 Vac autoformer designed for systems that utilize a single Sunny Island inverter in conjunction with a single Sunny Boy inverter. The autoformer provides stepup and step-down options to supply loads with 120 Vac and 240 Vac and allows coupling of a Sunny Boy inverter with a single Sunny Island inverter.

Developed for off-grid village electrification projects, SMA’s multicluster system platform (see Figure 5, below) integrates Sunny Island inverters in groups of three, referred to as clusters. The inverters in each cluster share a dedicated battery bank and are configured for 3-phase ac output. Two, three or four 3-phase clusters, each consisting of three Sunny Island inverter/ chargers, can be connected in parallel via the MCB for system inverter capacities of up to 110 kWac. Additional clusters can be connected to the MCB’s distribution board at any time, enabling expansion of renewable energy generation capacity. Limiting factors of the multicluster system are the number of inverter connections possible on each MCB ac-distribution board and the ampacity of their switching devices. With the exception of the master cluster, maintenance or replacement of individual inverters can take place during system operation—the only operational difference during system maintenance is that the total output of the system is correspondingly lower.

In ac-coupled multicluster systems, SMA Sunny Boy inverters communicate with Sunny Island battery-based inverters via a shielded RS485 communication cable. When the batteries are completely charged and the ac-load demand is low, the Sunny Island uses frequency-shift power control to gently throttle down the power output of the grid-direct SMA inverters. These frequency shifts prevent battery overcharging and are independent of any other communication functions between the inverters. Unlike the operation of ac-coupled solutions from other manufacturers that use frequency shift to completely drop ac-coupled grid-direct inverters off-line, SMA’s fully integrated approach allows the ac-coupled string inverters to remain online during frequency shift while operating at lower power levels (see Figure 6).

Most ac-coupled systems that utilize SMA’s battery-based and grid-direct inverter products do not require any additional components such as relays and remote disconnects to manage power production when ac production exceeds the on-site load. In addition, if the battery reaches a preset low state-of-charge threshold, a load-shedding contactor can be programmed to open to prevent an over-discharge of the battery, which could cause the individual cluster to disconnect from the system. With a portion of the loads off-line, the ac-coupled charging sources continue to charge the battery bank. When a sufficient battery state of charge is achieved, all loads are automatically reconnected to the ac-distribution system.

The MCB includes several heavy-duty contactors. Each generator contactor connects grid-forming generators, such as those used in high-power diesel generating plants. When the generator voltage and frequency parameters are within limits, the Sunny Island synchronizes with the generator voltage and frequency reference and uses both generator power and ac renewable energy sources to either supplement loads or charge the battery banks. If an inverter cluster fails or is switched off, the generator contact automatically closes and the generator is directly connected to the loads. If the generator fails, the system quickly disconnects it and maintains power to the loads via the batteries and the available renewable energy sources. This system redundancy ensures that power is still available for the ac loads, even when one component fails.

An example of an off-grid, ac-coupled multicluster power supply system is on Scotland’s Isle of Eigg. The island is part of the Scottish Inner Hebrides chain and is approximately 12 square miles with a population of 90. Due to high costs, the island has not yet been connected to the mainland’s powerdistribution grid, which is about 10 miles away. Until 2008, diesel generators supplied the island with electricity and the entire ac-distribution network had to be taken off-line when a generator required maintenance.

Since 2008, the islanders have reaped the benefits of a modern 3-phase electricity grid, 95% of which is supplied by renewable energy sources. This ac-coupled hybrid system integrates hydroelectric, wind and solar generation. Generator operation is limited to times when the combined renewable generation sources do not fully meet the load demand. Although gridquality power is now available 24 hours a day, electricity costs for the islanders have fallen by more than 60%.

The central element of the stand-alone grid is the SMA MCB-12, which serves as the distribution hub for four Sunny Island clusters. Each cluster is rated at 15 kWac. Three hydro turbines with a total generation capacity of 110 kW, four small wind turbines with a total capacity of 24 kW, and a 32 kW PV plant provide a diverse supply of electricity. Two 64 kW diesel generators serve as backup. Each cluster’s battery bank has a storage capacity of 2,242 Ah at 48 Vdc nominal and can meet the island’s load for approximately 24 hours.

During normal operation, the master cluster controls the entire grid and ensures that the distribution system’s energy balance is maintained at all times. Excess energy from the renewable sources is stored in each inverter cluster’s battery bank. When the battery is fully charged, the master cluster reduces the power output of the Sunny Boy and Windy Boy inverters using frequency-shift power control. It also activates remotely controlled diversion loads such as water-heating tanks located in public buildings.

The master cluster starts the diesel generator when the system’s battery state of charge falls below 60%. In this case, the diesel generator sets the network’s power frequency and the Sunny Island clusters are synchronized to the generator’s voltage and frequency reference. The overload capacity of the Sunny Island inverter/chargers makes an important contribution to the system’s operation. When large loads are cycled, the load on the generator does not immediately change because the Sunny Islands compensate for load fluctuations. In this application, the Sunny Island system can supply 144 kW of battery power to the grid for 3 seconds. In its role as grid manager, the master cluster weighs the alternatives of operating the diesel generator with the highest possible efficiency while delivering the appropriate charge current to the system’s battery banks. As a result, the generator runs less frequently, runs more efficiently under partial loading, and is not subjected to short start-and-stop cycles.

Integrator Perspectives on AC Coupling

On one hand, equipment manufacturers are able to provide valuable technical insights on the use of their products in ac-coupled applications. On the other hand, the diverse nature of these sometimes complex systems makes the lessons integrators have learned equally important in many instances. We surveyed several solar professionals with ac-coupled system design and installation experience who graciously devoted some time to sharing their experiences from the field.


When compared to dc-coupled PV systems, ac-coupled systems may provide a more efficient means for utilizing array output if the majority of a site’s ac loads (including energy exported to the grid in utility-interactive systems) is utilized during peak solar production hours. Assuming that losses from conductors are equal in the two systems, and that the majority of the ac-load consumption corresponds with PV production, ac- and dc-coupled system efficiencies can be compared as shown below. This simplified comparison uses sample inverter and charge controller efficiencies. More accurate comparisons can be developed using equipment-specific efficiency figures. In addition, this example does not include any losses associated with array power passing through or over the battery bank, which would result in a more favorable power output advantage for ac-coupled systems.

AC-coupled PV system. PV production x ac-coupled inverter efficiency = available ac power; 10,000 Wdc x 0.95 = 9,500 Wac

DC-coupled PV system. PV production x charge controller efficiency x battery-based inverter efficiency = available ac power; 10,000 Wdc x 0.95 x 0.95 = 9,025 Wac

When evaluating the cost of ac- versus dc-coupled system designs, account for all materials and installation-labor savings on the dc side of the system. In ac-coupled systems, the grid-direct inverter essentially replaces the dc-charge controller, but ac coupling may also eliminate the need for a source-circuit combiner box if PV source-circuit fusing is included in the ac-coupled grid-direct inverter.

Make sure to compare the power output from the ac-coupled portion of the PV system with the pass-through capability of the battery-based inverter when designing ac-coupled systems. This need applies to both grid-tied and off-grid applications. Additionally, be sure to match the grid-direct inverter voltage requirements with the battery-based inverter voltage output. For example, grid-direct inverters that have 240 Vac output cannot be ac coupled with a single battery-based inverter with 120 Vac output without the addition of a step-up/step-down transformer that lowers overall system efficiency. The SMA Sunny Island system requires an RS485 communication cable between the Sunny Boy and Sunny Island inverters. This enables full communication between the inverters and allows the battery-based Sunny Island inverters to modulate the power output of the string inverters based on ac load requirements and battery state of charge. While the communication cable can connect inverters over a distance of up to 3,937 feet if necessary, it is advantageous to group inverters as close together as possible.


Our most complex ac-coupled system integrates a 21 kW PV array and a XZERES 442 wind turbine with two SMA Sunny Island 5048-US inverters. The system utilizes a transfer-relay contactor to switch the PV output from the grid-connected main panel to the critical load panel powered by the Sunny Islands when the grid goes down. This strategy avoids an ac amperage pass-through bottleneck through the two Sunny Islands during normal system operation when the grid is up.

From my perspective, ac-coupled systems offer the following advantages:

  • The efficiency of grid-direct inverters is much higher than the efficiency of a dc-coupled battery-charging system.
  • PV array stringing options, combiners, and wiring are simpler and more flexible in ac-coupled systems than in dc-coupled systems.
  • The material and labor cost of installing an ac-coupled grid-direct inverter is comparable to the total cost of a charge controller, a dc-integration panel and the associated equipment required for dc-coupled systems.
  • Some inverter combinations, such as those used in SMA’s Sunny Island system, work in harmony to reduce griddirect– inverter output without fully disconnecting the grid-direct inverters. This allows for regulated battery charging when the system is in Off-Grid mode and generation exceeds the ac load.
  • Renewable energy production metering is simpler in ac-coupled systems because it is not necessary to account for grid and renewable energy generation that is consumed by critical loads or battery charging.

Some disadvantages of ac-coupled systems are also critical to consider:

  • When a system is in Off-Grid mode during utility outages, many ac-coupled–inverter combinations require an ac relay controlled by the battery-based inverter’s aux output to disconnect the grid-direct inverter when generation exceeds the energy consumed by the critical loads. This disconnect relay can cycle repeatedly, resulting in a loss of energy production during the 5-minute resynchronization waiting period every time the grid-direct inverter reconnects to the system.
  • The capacity of renewable generation sources is limited by the ac pass-through capacity of the battery-based inverter system. For example, the battery-based inverter capacity may need to be increased to handle the production of a large PV system even if the critical load requirements do not call for it. One work-around is a fairly complex contactor-relay setup that switches the grid-direct inverter output between the main electrical panel and the critical load subpanel.
  • While the frequency-shift regulation approach used in SMA’s Sunny Island system works well, the installation manual is not as clear or complete as it could be. That said, SMA’s documentation, experience, understanding and support for ac-coupled systems is likely better than that of other manufacturers. Expect to develop a close relationship with the inverter tech support people. Good cellphone coverage from the job site is a big advantage.
  • If the grid-direct inverter has a possibility of syncing with a backup generator, I instruct the system operator to disconnect the grid-direct inverter before running the generator. The operator can accomplish this with the installation of an either/or interlock switch.


My first experience with ac coupling was in 2003 while I was doing graduate studies in renewable energy in Germany. For my thesis project, I had the opportunity to design and install a hybrid PV-and-generator minigrid system that provided power for a rural boarding school located in Bulyansungwe, Uganda. This project included two 1.7 kW Sunny Boy 1700E inverters and a 3.3 kW Sunny Island 3300, and was one of the first deployments of SMA’s ac-coupled Sunny Island system.

One of the key advantages of ac coupling is higher systemproduction efficiency. Here in Washington state, we have a production incentive that pays an elevated rate per ac kWh produced. With an ac-coupled system, we can take advantage of the high conversion efficiencies of grid-direct string inverters— instead of the lower efficiencies of battery-based inverters. This results in a substantial increase in production incentive payments. The increased efficiency is also a benefit for off-grid systems with a high percentage of daytime loads.

The frequency control used in SMA’s Sunny Island system allows the Sunny Island battery-based inverters to incrementally decrease the Sunny Boys’ production when the batteries are approaching a full state of charge and ac loads are low. This is a very elegant solution. There is a real advantage to keeping the array generating at partial capacity instead of turning the grid-direct inverters completely off and pulling energy from the batteries. This can, of course, also be accomplished in mix-andmatch inverter systems by using a diversion controller and load.

One of the things to watch for in ac-coupled system design is that the battery-based inverters typically cannot pass through to the grid more power than their rated inverting capacity. This means that the battery-based inverter capacity has to be at least as large as your grid-direct string inverter capacity, which can present an unfortunate bottleneck when you have the typical large grid-direct system and only a small requirement for backup power. To solve this scenario, you can use an automatic transfer switch or divide the grid-direct inverter and array capacity between the main panel and the critical loads panel.


In 2008, Oasis Montana installed an off-grid ac-coupled system that integrated two Sunny Boy 3000-US inverters with a quad stack of four OutBack VFX3648 battery-based inverters. Because of tall trees around the home, the 5.6 kW polemounted PV array was located 685 feet from the inverters and battery. By going with ac coupling, we were able to configure the array at high voltage, which reduced wire costs significantly. The ac-coupled approach did require more components and increased the complexity of the system, however.

In an ac-coupled configuration, ac power produced by the Sunny Boy inverters is back-fed through the ac-out terminals of OutBack VFX inverters. When you back-feed the Outback inverters, all the charging parameters are bypassed and the charge you are applying to the batteries is unregulated. In this system, we used a series of relays to switch dump loads on and off, simulating a three-stage charging process.

A Morningstar Relay Driver monitors the battery-bank voltage and controls four different relays. The first three relays control three 1,500 Wac electric heaters. Each relay is set at a slightly higher regulation voltage. A fourth relay is set at 62 Vdc and acts as our fail-safe in case one of the three diversion loads malfunctions. This relay is configured to disconnect the combined 240 Vac output of the two Sunny Boy inverters.

In the past few years, higher voltage dc-charge controllers such as the MidNite Solar Classic and Xantrex XW-MPPT80-600 have come to market. On midrange to long wire runs, consider using a higher voltage charge controller rather than ac coupling. If you decide to go with ac coupling, I would recommend the SMA Sunny Island system because it is fully integrated. Based on our crew’s experience, we would not recommend mixing equipment from different manufacturers in residentialscale off-grid ac-coupled systems. We learned this the hard way. Some grid-direct inverter manufacturers do not support or warranty their products in ac-coupled applications.


Here in New York, I am seeing an increase in existing customers wanting to add battery backup to their grid-direct systems, as many of them experienced power outages for a week or more after Hurricane Irene last season. When the grid goes down, clients suddenly become aware that their PV system is not functional. During and after an extended power outage, that realization really starts to settle in. Because it doesn’t require any rewiring on the dc side, ac coupling is a good approach for retrofitting these systems. However, it has the disadvantage of adding system complexity and therefore cost. In New York, the financial incentives are based on kilowatts of installed solar modules, so there is no additional incentive money for ac-coupled systems.

What currently makes the SMA ac-coupled approach work well is that installers can set up all of the inverters to communicate with each other. However, in a retrofit, if the Sunny Boys and the Sunny Islands are not relatively close to each other (say the Sunny Boys are out in a field with the array and the Sunny Islands are down in the basement), then the communication part of the system can become problematic. The standard approach is running a hardwired communication cable between the inverters. However, it may not be practical or possible to connect them in retrofitted systems. In that case, the Sunny Island inverters still use frequency shift to regulate battery charging, but do not modulate the string inverter’s power output as they would with the communication cable in place. Using only frequency shift, the Sunny Boy inverters drop completely off-line and have to go through the 5-minute waiting cycle, which repeats until the combined load in the critical loads subpanel and the battery-charging power requirement is equal to or greater than the output of the Sunny Boy inverters.

We have installed ac-coupled systems only with SMA equipment and have some suggestions for how SMA could improve integration of these systems. The first is to make the Sunny Islands capable of providing 120/240 Vac output so that only one Sunny Island battery-based inverter is necessary. At present, either two Sunny Islands or a step-up/ step-down transformer is required. Two ac inputs, one for the grid and one for a generator, would be handy as well. Currently, you need to add a separate automatic or manual transfer switch if you want to include grid and backup-generator charging.


One of the more common applications for ac-coupled systems is for homeowners who decide to add battery backup to a gridtied PV system. In most cases, I suggest to these customers that a generator is a better choice for occasional backup power. Folks in hurricane areas may be able to make a better argument for using batteries to back up grid power. If the PV array is a long distance from the batteries, they should consider ac coupling. However, with higher-voltage charge controllers such as the MidNite Solar Classic 250 and Xantrex XW-MPPT80-600 available, I would consider those alternatives first.

Keep in mind that in utility-interactive systems, the griddirect string inverter that is set up for ac coupling with a battery-based inverter is not operating in AC-Coupled mode except when grid power is down. So 99% of the time, you will not experience any of the annoyances that come with a specific ac-coupled system. If the system is off-grid, ac-coupled operation is the normal routine and any problems become quite apparent. For an off-grid system where the ac-coupled inverter is normally the primary charging source, an external diversion controller and load should be used in mixed inverter systems. Additionally, making the system fail-safe is important. For example, if the diversion controller is inadvertently turned off or fails, a relay-based approach should be in place to disconnect the ac-coupled inverter.

When considering ac coupling, one important question is how much support the inverter manufacturer is willing or able to provide. At one end of the spectrum, SMA has a fully integrated product line and a training program for its Sunny Island system. Other battery-based inverter manufacturers may offer only a short white paper on using their products in ac-coupled applications, and their technical support staff may have limited experience with these systems.

Benefits and Drawbacks of AC Coupling

Depending on the application and equipment used, ac-coupled systems may offer several advantages over their dc-coupled counterparts. In large stand-alone microgrid systems, such as those found in rural electrification projects in the developing world, ac coupling provides an extremely scalable and modular platform that can integrate multiple charging sources located throughout the system’s distribution network. Large standalone projects here in the US may also benefit from an ac-coupled rather than a dc-coupled design approach. The inverter/ battery cluster platform developed by SMA that is common in these large systems allows segmentation of battery storage into manageable bank sizes that limit the number of series battery strings required to achieve sufficient storage capacity.

In residential systems, ac coupling is one approach that can be used to increase PV system voltages (up to 600 Vdc) to minimize wire costs when PV arrays are located a significant distance from the power-conditioning and -storage equipment. It can be a great solution in the retrofit market when customers want to add battery backup to existing grid-direct systems. Finally, ac-coupled systems can achieve higher dc-to-ac conversion efficiencies, especially when the generation matches periods of high-electricity demand.

In spite of the benefits ac coupling has to offer, it may also have some downsides when compared to more standard dc-coupled system designs. Again, depending on the application and equipment used, system regulation and optimized battery charging can be a challenge, especially when equipment from different manufacturers is installed. The introduction of higher voltage charge controllers has offset one of the perceived advantages of ac coupling when long-distance array-to-battery power transmission is required. In general, ac-coupled systems can be more complex in design and installation, and this is compounded by the fact that the knowledge base in the industry to support inexperienced integrators is still underdeveloped compared to what is available for the more common grid-direct and dc-coupled systems.

In spite of the benefits and drawbacks of ac-coupled system architectures, they are an important and viable approach for integrators to have in their design toolkit. AC coupling can provide solutions for systems that would otherwise have been undevelopable. As interest in ac-coupled systems continues to grow, installers will continue to learn valuable lessons from the field. Correspondingly, manufacturers will continue to develop both products and more-robust support services to aid integrators in the design and installation of this modular and scalable system platform.


Joe Schwartz / SolarPro magazine / Ashland, OR /

Inverter Manufacturers with AC-Coupled Solutions

Magnum Energy / 425.353.8833 /
OutBack Power Technologies / 360.435.6030 /
Schneider Electric / 847.397.2600 /
SMA America / 916.625.0870 /


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