Next-generation solar farms are utilizing 1,500 V plant architectures to drive down BOS costs and improve system performance.
By all accounts, the PV power plant of the near future is here today and poised for widespread adoption in 2017. In this article, I provide a brief overview of the history of 1,500 Vdc PV systems. After providing an update on applicable codes and standards, I consider the state of the supply chain and detail the benefits and tradeoffs associated with 1,500 V designs. Finally, I identify some potential challenges associated with early field deployments.
BRIEF HISTORY OF 1,500 VDC SYSTEMS
EPCs in Europe pioneered 1,500 V plant architectures, just as they were first to market with 1,000 V PV systems. Belectric, for example, is an international solar project developer headquartered in Germany, with a long history of innovation and market firsts such as the construction of the first thin-film PV system in Europe (2001). According to a company press release, in June 2012 Belectric constructed and commissioned the world’s first utility-interactive 1,500 Vdc solar power plant. Power Conversion, a Berlin-based division of GE Energy, supplied the liquid-cooled inverters used to connect the 1,500 Vdc system to the utility grid.
Though the Belectric press release does not mention the manufacturer’s module technology, context and timing suggests this was likely a pilot project featuring Nanosolar’s Utility Panel, as this was the first PV module certified to 1,500 Vdc. Nanosolar famously hyped its now-defunct CIGS thin-film product as the technology of choice to dethrone First Solar. Today, Nanosolar has gone the way of Solyndra, and First Solar remains the world’s leading thin-film module manufacturer, in part due to its aggressive and successful development of 1,500 V thin-film modules and pre-engineered power plant solutions.
In conjunction with GE Power Conversion, First Solar began publicly touting the benefits of 1,500 Vdc solar arrays in early 2014. According to a technical brief published later that year in PV-Tech Power (see Resources), First Solar commissioned its first 1,500 Vdc AC Power Block at the 52 MW Macho Springs Solar Facility in Deming, New Mexico, in the spring of 2014. After monitoring and comparing the performance of this 3.6 MWdc array alongside that of 34 other 1,000 Vdc array blocks, First Solar decided to prove the efficacy of the concept further with even larger AC Power Blocks. Later the same year, First Solar deployed two additional 1,500 Vdc array blocks at the Barilla Solar Farm in Texas, pushing the power block capacity to 5 MWdc/4 MWac. Based on the results of these pilot projects, First Solar proceeded to shift the vast majority of its projects to 1,500 V plant architectures in just two years.
When you consider the broader development and deployment of 1,500 Vdc systems, the rest of the utility-scale solar industry is not far behind First Solar’s lead. At the risk of oversimplification, 2015 was most notable for the widespread release of 1,500 Vdc–rated components—modules, inverters, combiners, fuses and so forth—certified to UL standards. In 2016, a second wave of large-scale project developers, including Recurrent Energy, began selectively deploying 1,500 Vdc PV systems as a way of testing the waters and building a knowledge base for the widespread adoption of 1,500 Vdc systems in 2017.
According to 1,500-Volt PV Systems and Components 2016–2020 (see Resources), a GTM Research report, 1,500 Vdc systems will account for 4.6 GW of global utility-scale solar installations in 2016. Though GTM Research analysts estimate that the US market will account for roughly 60% of the 1,500 Vdc field deployments worldwide in 2016, they expect that demand in the rest of the world will dwarf that in North America from 2017 forward. In other words, once early adopters have proven the technology benefits in the field, analysts expect to see a steady transition from 1,000 Vdc to 1,500 Vdc.
My own informal market survey, conducted at Solar Power International (SPI) 2016 in Las Vegas, reinforces these projections. For example, Stephen Giguere, solar division engineering director at Power Electronics, notes: “The big shift is still one more buying cycle out. Customers booked a lot of the orders we are fulfilling now while there was still uncertainty about the future of the ITC [Investment Tax Credit]. Going forward, however, all of the large systems in our queue are designed around 1,500 V products.”
Brad Dore at SMA America concurs: “Currently, the overwhelming majority of new orders US customers are placing for PV plants expected to be built next year will utilize 1,500 V technology. Globally, the transition from 1,000 V to 1,500 V is happening a little slower, but we expect the same value proposition to win out elsewhere as it is here.”
Paralleling the earlier shift from 600 Vdc to 1,000 Vdc PV systems, the first 1,500 Vdc field deployments in the US utilized equipment certified to international rather than UL standards, as allowed at power generation facilities governed by the National Electrical Safety Code. Since that time, changes to product safety standards and the National Electrical Code have made it even easier for AHJs to approve and inspect 1,500 Vdc PV power plants.
Product safety standards. The International Electrotechnical Commission (IEC), the standards-making entity that has jurisdiction over Europe as well as many countries around the world, defines 1,500 Vdc as the upper limit for low-voltage electrical systems. As a result, there was no technical reason why equipment vendors could not certify PV system components at 1,500 Vdc to IEC standards. The barrier to doing so was simply market based: Did the demand justify the investment?
As a vertically integrated module manufacturer and solar project developer, First Solar was uniquely positioned to answer this question in the affirmative. By certifying its Series 4 modules to IEC standards at 1,500 Vdc, the company was able to prove its next-generation solar farm concept in the US. Because demand for utility-scale solar is particularly strong in the US, this design evolution put pressure on UL to harmonize its product safety standards with those of the IEC to allow for UL certification of modules and inverters at 1,500 Vdc.
In October 2014, the authors of the technical brief on First Solar’s next-generation PV plant noted: “The regulatory challenges in many places, particularly outside of North America, are lower due to existing IEC standards, which address 1,500 Vdc design and safety. Greater challenges are faced in the US, where the lack of established standards that address 1,500 Vdc applications often make it challenging to obtain plant construction permits from local authorities having jurisdiction.”
In practice, the barriers to deploying 1,500 Vdc systems in the US had already begun to fall. In the summer of 2014, UL adopted ANSI/UL 62109-1 as the national safety standard for PV inverters, enabling certification to 1,500 Vdc. Just a few months later, in 2015, UL published requirements for the evaluation and certification of 1,500 Vdc PV modules. According to a post on the UL newsroom: “The requirements examine the construction of the PV module, junction box, cables and connectors as per the standard UL 1703 and address potential electrical hazards associated with the increased voltage. As a result, getting approval to design and deploy 1500 V systems is now easier, enabling the pursuit of new opportunities.”
Though some efforts to harmonize UL and IEC product safety standards are ongoing, equipment vendors have successfully certified modules and inverters to UL standards at 1,500 Vdc since 2015.
National Electrical Code. Around this same time, Code-making efforts were under way to expand and clarify the PV system voltage limits in the NEC as part of the 2017 cycle of revisions. Though attempts to raise the threshold between low- and high-voltage electrical systems, as defined in Article 490, from 1,000 V to 1,500 V or 2,000 V ultimately proved unsuccessful, NEC 2017 does include additional guidance regarding maximum voltage limits for commercial roof-mounted systems and ground-mounted solar farms.
Specifically, the Code-Making Panel (CMP) revised Section 690.7 as follows (emphasis added): “PV system dc circuits on or in one- and two-family dwellings shall be permitted to have a maximum voltage of 600 volts or less. PV system dc circuits on or in other types of buildings shall be permitted to have a maximum voltage of 1,000 volts or less. Where not located on or in buildings, listed dc PV equipment, rated at a maximum voltage of 1,500 volts or less, shall not be required to comply with Parts II and III of Article 490.”
The CMP has provided 1,500 Vdc systems with a clear path to market in free-field applications, while closing the door on higher-voltage systems in commercial rooftop applications. In 2015, for example, Belectric was able to deploy the world’s first 1,500 Vdc rooftop system in Berlin, Germany. NEC 2017 specifically rules out this type of development in the US by limiting nonresidential rooftop systems to 1,000 Vdc.
Compared to the drawn-out process required to transition the US market from 600 Vdc to 1,000 Vdc system architectures, industry stakeholders effectively fast-tracked the changes to codes and standards needed to allow 1,500 Vdc UL-listed products and NEC-compliant systems. This underscores the fact that 1,500 Vdc systems have much in common with 1,000 Vdc or 600 Vdc systems. This is not a revolution in PV power plant design so much as it is a natural evolution.
Ryan LeBlanc, senior application engineer for SMA America, elaborates: “The transition from 1,000 Vdc to 1,500 Vdc systems is going to be a lot easier than getting from 600 Vdc to 1,000 Vdc was. In this case, AHJs and EPCs have a precedent to follow. All we really need is higher voltage–rated equipment, which is readily available. At the system level, the savings aren’t as significant as they are when going from 600 Vdc to 1,000 Vdc, but there are incremental savings associated with a shift to 1,500 Vdc.”
VALUE PROPOSITION AND SUPPLY CHAIN
The basic value proposition for increasing PV utilization voltages is that—all else being equal—doing so will reduce wire and BOS costs. At the string level, higher utilization voltages allow for more modules and greater power capacity per source circuit. Fewer source circuits in turn permit systems to use fewer overcurrent-protection devices and, at least on paper, fewer source-circuit combiners. Perhaps most importantly, higher voltage levels make it possible to transmit more power using the same conductor or collection system. As an added bonus, plant and inverter efficiency improve in accordance with Ohm’s law, which states in part that doubling voltage will reduce conduction losses (I2R) by one-quarter for the same power level.
The caveat, of course, is that there are standard voltage levels for electrical equipment. Generally speaking, going from 600 Vdc to 1,000 Vdc PV systems did not trigger a meaningful change at the component or subcomponent level. Prior to 2012, for example, modules intended for the US market were tested and certified at 600 Vdc because this was the standard low-voltage limit defined in the NEC. Manufacturers likely sold exactly the same module in the European market with a 1,000 Vdc certification. As a result, PV modules did not really change when the NEC started allowing 1,000 Vdc system architectures. Instead, Nationally Recognized Testing Laboratories in the US simply started to conduct tests at the same voltage levels as their counterparts in Europe and the rest of the world.
The same is not true of the shift to 1,500 Vdc. The components and subcomponents that make up a 1,500 Vdc PV power plant are often different from and more expensive than those used for a 1,000 Vdc plant. In some cases the differences are subtle; in others they are obvious.
Modules. You need look no further than the PV modules themselves for an illustration of these diminished returns. Module manufacturers invariably have to charge a small premium—on the order of $0.01 to $0.02 per watt—for 1,500 Vdc modules compared to 1,000 Vdc models. While initially low production volumes likely accounted for some portion of this price premium, the environmental packaging for the 1,500 Vdc module is inherently more expensive, precisely because it has to withstand a higher electrical potential.
Consider, as an example, the product design strategies that module manufacturers use to improve resistance to potential-induced degradation (PID) at higher operational voltages. One approach is to use a glass-on-glass package in place of the typical glass-on-plastic package. To stick with a glass-on-plastic package, manufacturers invariably need to use thicker encapsulation materials to withstand the higher voltage. Since the edge seal is particularly vulnerable to leakage currents, some module manufacturers eliminate the module frame, which means that the glass needs to provide this structural rigidity; others increase the distance between the cells and the frame, which results in a slightly larger and less efficient module. Each of these approaches results in a 1,500 Vdc module that is slightly more expensive than an equivalent 1,000 Vdc model.
The fact that First Solar is the market leader in the transition to 1,500 Vdc PV power plants is undoubtedly a function of the unique electrical characteristics of its thin-film solar modules. Compared to typical crystalline silicon (c-Si) modules, First Solar’s cadmium telluride modules have higher-voltage characteristics. As a result, designers can connect only about half as many First Solar modules in series per source circuit. In 1,000 Vdc applications, for example, 20-module source circuits of roughly 6,000 watts each are possible with c-Si technologies in some climates; the equivalent building block with First Solar Series 4 modules might be 10-module source circuits at 1,150 watts each. This means First Solar’s power plants are especially sensitive to BOS costs. As a side benefit, First Solar also discovered that the performance of its modules improved, in terms of efficiency and power level, at higher utilization voltages.
Since First Solar introduced its 1,500 Vdc–certified thin-film modules in 2014, other c-Si module manufacturers have followed suit. Today, many industry-leading manufacturers— including Canadian Solar, Hanwha Q CELLS, Jinko Solar, SolarWorld, Trina Solar and Yingli—offer 1,500 Vdc UL-certified modules. The list of companies offering IEC-certified 1,500 Vdc modules is even longer.
Inverters. Incentivized in part by its strategic partnership with First Solar, GE was the first inverter manufacturer to introduce an IEC-certified 1,500 Vdc inverter. According to a company newsletter (see Resources), GE Power Electronics initially developed its LV5 series inverter for offshore wind applications and later realized that the technology could also benefit solar farm operators. The availability of new power electronics allowed GE’s product engineering team to increase both inverter input voltage and output power by 50%, and these inverter-level improvements provide additional value at the plant level.
According to Vlatko Vlatkovic, chief engineering officer at GE Power Conversion: “The new design allows us to send much more power through the same amount of copper and get big economies of scale. You won’t need as many fans, filters, concrete pads and other components for the farm infrastructure. You can change the farm’s architecture.”
The most notable change in plant architecture is that PV plant building blocks get larger. Higher operating voltages not only improve inverter power density but also decrease wire losses within the dc collection system and allow longer transmission distances. GE estimates that its larger inverter block reduces capital expenditures on a 200 MW farm by approximately $5.8M while also decreasing operating expenditures by 30%.
The technical brief on First Solar drives this point home by comparing 20 MW plant layouts at 1,000 Vdc and 1,500 Vdc. As shown in Figure 1 (p. 40), the higher utilization voltage reduces the number of power stations by 60%, from ten 2 MWdc blocks to four 5 MWdc blocks. As a secondary benefit, the layout reduces the amount of land area dedicated to inverter pads and access roads.
In spite of these power density improvements, the inverter itself is little changed. The authors of the First Solar brief note: “By and large, 1,500 Vdc inverters have the same fundamental inverter topology as 1,000 Vdc inverters—with power semiconductors and dc power-circuit components appropriately rated for the higher dc voltage. These components are covered by the existing IEC standards and readily available as they are similar to those components used in wind converters and industrial drives. 1,500 Vdc inverters have the same ac grid interface circuits, controls, protection and grid management features as 1,000 Vdc inverters.”
Like GE, Eaton provides high-voltage inverters for wind farms that it is adapting for use in 1,500 Vdc solar applications. According to Chris Thompson, the company’s business unit manager for its global solar and storage product lines: “Eaton has been supplying high-voltage inverters for storage and wind for a long time and will likely release a 1,500 Vdc solar inverter in 2017. While the package will be similar to our 1,000 Vdc model, it’s not the same inverter. You have to upgrade all of the voltage-rated components. Though some of the internal components may cost more, you can get more power out of the inverter, so the net effect is beneficial. In general, volts are cheap whereas amps are expensive.”
LeBlanc at SMA America concurs: “Inverters are fundamentally current-limited devices, and a lot of money goes into those current-carrying components. If you drive up the voltage from 1,000 Vdc to 1,500 Vdc, the busbars get smaller and the inverter gets less expensive on a dollars-per-watt basis. In effect, you can get more watts out of the same box.”
“SMA has seen a rapid migration from 1,000 V to 1,500 V systems in US utility applications because the value is compelling,” adds SMA America’s Dore. “Developers, owners and EPCs all benefit from the resulting BOS savings. To capitalize on this market demand while mitigating the risk associated with field certification, SMA recently became the first company to certify a 1,500 Vdc inverter, the Sunny Central 2500-EV-US, to the new UL 62109 standard.”
Many other vendors are following this lead. The list of inverter manufacturers with 1,500 Vdc UL-certified central inverters includes ABB, Ingeteam, Power Electronics, Sungrow and TMEIC. Some of these companies are also developing 1,500 Vdc–rated string inverters.
At SPI 2016, for example, Sungrow unveiled a 1,500 Vdc 3-phase string inverter with a nameplate capacity of 125 kW; in terms of form factor, this new inverter is roughly the same size as the company’s 60 kW–rated 1,000 Vdc model. Though the NEC limits commercial roof-mounted PV systems to 1,000 Vdc, system designers may find 1,500 V string inverters useful in commercial ground-mount applications or for building distributed PV plants (<20 MW). On larger projects, 1,500 Vdc string inverters could also prove useful as a way to develop marginal land or property boundaries, areas not well suited for large, uniform power blocks.
Combiners. BOS vendors were relatively early to market with 1,500 Vdc UL-certified combiners. For example, Shoals Technologies Group introduced a 1,500 Vdc version of its SlimLine Combiner Box in the summer of 2015. Since then, AMtec Solar, Bentek, Eaton and SolarBOS have all announced similar product releases.
At first glance, combiners seem like a great opportunity for reducing costs. As illustrated in Table 1, increasing the voltage by 50% means that you can increase string lengths proportionally, which results in a 33% reduction in the number of source circuits. If you hold steady the number of inputs per combiner, you need only about 67% as many combiners at 1,500 Vdc as at 1,000 Vdc. Unfortunately, this type of analysis tends to oversimplify the situation.
Dustin Watson, vice president of sales at SolarBOS, explains: “At the moment, EPCs should expect to pay a 50% premium for 1,500 Vdc string combiners compared to 1,000 Vdc versions. We do expect this premium to come down over time, as we have already seen significant cost reductions on 1,500 V–rated components since the beginning of the year. We anticipate additional cost decreases in 2017 as more of our customers begin to adopt 1,500 Vdc designs and new components enter the market. This is comparable to what happened a few years ago when the markets transitioned from 600 Vdc to 1,000 Vdc.”
Though the premium for 1,500 Vdc combiners will undoubtedly come down and is offset somewhat by labor savings, Thompson at Eaton cautions: “Even with volume, these are always going to be more expensive components. Pound for pound, dc arcs are probably four times harder to break than ac arcs, because there isn’t a zero crossing. To increase the voltage rating for PV fuses by 50%, you need a different and more expensive fuse element; as a result, the physical package for the fuse and the fuseholder gets bigger and more expensive. The same is true for the dc disconnect; it gets bigger and more expensive. Now you need bigger and more expensive combiner-box enclosures, which means you can pack fewer combiners per pallet or truck. These little things ripple through the cost of the system.”
Tom Willis, director of sales at AMtec Industries, provides an example: “Whereas a typical 24-string 1,000 Vdc combiner box fits into a 24" x 24" x 8" enclosure, you need a 30" x 24" x 8" enclosure to handle the same number of circuits at 1,500 Vdc. While the cost premium is about 40%, this will come down as demand goes up.”
The alternative to using larger combiners is to aggregate fewer circuits per combiner. “To a certain extent, there is a convenience factor to dc block sizing,” elaborates Coel Schumacher, chief technical officer at SolarBOS. “If you are used to aggregating 400 or 500 modules per combiner at 1,000 Vdc, you may want to do the same thing at 1,500 Vdc, perhaps for monitoring and O&M purposes. So a customer who is accustomed to ordering 24-input 1,000 Vdc combiners might opt for 16-input combiners at 1,500 Vdc. That way the number of combiners stays about the same, as does the size of the combiner box and the number of modules aggregated per combiner.”
Collection systems. By all accounts, the real cost savings associated with 1,500 Vdc plant architectures comes from material and labor savings associated with the dc collection system and to a lesser extent the ac collection system. Though PV connector companies such as Multi-Contact had to certify their products for higher operating voltages to meet market demand, wire and cable suppliers already offered 2,000 V–rated single conductor solar cable, in both copper and aluminum. Since EPC firms can use the same cables, conduits and trenches for both 1,000 Vdc and 1,500 Vdc systems, any material and labor reductions due to the higher operating voltage are pure cost savings. GTM Research estimates that savings could be as high as $0.03 per watt within the dc collection system and $0.005 per watt within the ac collection system.
However substantial the rewards associated with increasing PV plant voltage from 1,000 Vdc to 1,500 Vdc, there is clearly no free lunch. EPC firms have to spend money to save money. Moreover, higher operating voltages carry some technology risks, most notably PID. Early adopters could also run into challenges associated with dc arc-flash hazard levels and dc arc-fault protection requirements.
PID. Industry veterans will recall that instances of voltage-driven performance degradation increased after the widespread adoption of 1,000 Vdc plant architectures. In the wake of these problems, industry stakeholders developed new performance tests and enhanced module certifications relatively quickly. Though module manufacturers and testing laboratories have extrapolated these tests to qualify module resistance to PID at 1,500 Vdc, it remains to be seen how effective these laboratory tests prove in terms of identifying actual field failure mechanisms.
Thompson, who qualified inverters for First Solar before joining Eaton in 2010, notes that even modest PID effects can offset any plant-level savings associated with higher operational voltages. He predicts: “I bet we see some companies having premature degradation and warranty issues 5 years from now; it will be vendor specific and perhaps regionally specific. Though investors are comfortable with the risks, PID is a very complex phenomenon. Installations in hot, humid climates, of course, are the most vulnerable, but grounding is also a factor. It will be years before we understand the full implications of increasing operating voltages by 50%.”
Arc-flash hazard. The goal of an arc-flash hazard analysis is to protect workers from dangerous conditions associated with electrical arcs, such as intense releases of heat and pressure. Unfortunately, the arc-flash hazard levels on the dc side of a PV system are not well understood. Traditional arc-flash hazard calculations are applicable to ac rather than dc circuits; moreover, a PV power source is inherently current limited.
In the absence of empirical data that quantify actual dc arc-flash hazards in PV systems, engineers working on large-scale solar farms often rely on conservative calculation methodologies and assumptions. Some system and application engineers believe that this approach misrepresents the dc arc-flash hazards to personnel by making them appear worse than they may be in reality.
“From time to time, we see the aftereffects of dc arcing inside a SolarBOS combiner,” notes Schumacher, “and these are clearly not explosive arc-blast events. We see damage due to molten metal, for example, but no evidence of vaporized metals, such as you would expect to see with an ac arc flash. Of course, once you increase the array operating voltage by 50%, the calculated hazard levels go up even further. This could have the effect of making it more difficult for personnel to install, commission and maintain 1,500 Vdc PV systems—perhaps unnecessarily requiring arc-flash suits.”
Arc-fault protection. The goal of dc arc-fault detection and interruption is to prevent fire damage due to arcing faults in PV systems or components. The CMP first introduced dc arc-fault protection requirements to the NEC as part of the 2011 cycle of revisions by adding a new section, 690.11, “Arc Fault Circuit Protection (Direct Current).” It has modified these requirements with each successive Code edition.
Under NEC 2011, for example, dc arc-fault protection requirements apply specifically to PV systems on buildings. As part of the 2014 cycle of revisions, the CMP revised Section 690.11 so that it applies to all PV systems operating at 80 V or greater, regardless of whether the system is on a building or ground mounted. Though these basic requirements are unchanged under NEC 2017, the CMP added a new article—691, “Large-Scale PV Electric Power Production Facility”—that potentially exempts PV power plants with a capacity of 5 MW or greater from the requirements in Article 690. For example, 691.10 states: “PV systems that do not comply with the [dc arc-fault protection] requirements of 690.11 shall include details of fire mitigation plans to address dc arc faults in the documentation required in 691.6.”
The potential challenge here is that dc arc-fault protection requirements clearly do not apply to 1,500 Vdc solar farms deployed under NEC 2011. While the requirements appear to apply under NEC 2014, no 1,500 Vdc arc-fault protection equipment exists, leaving room for interpretation. Some AHJs may decide to waive these requirements, as is their prerogative under 690.4; others could object to 1,500 Vdc plant architecture, since it is possible to meet 690.11 at 1,000 Vdc. The most recent Code edition suggests a possible middle ground, which is to have an independent engineer design an alternative method of compliance.
David Brearley / SolarPro / Ashland, OR / solarprofessional.com
GTM Research, 1,500-Volt PV Systems and Components 2016–2020: Costs, Vendors, and Forecasts, January 2016, greentechmedia.com
Kellner, Tomas, “Something New under the Sun: GE’s Industrial-Grade Inverter Takes Solar Power to a New High,” GE Reports, September 2015, gereports.com
Morjaria, Mahesh, et al., “The Next-Generation Utility-Scale PV plant,” PV-Tech Power, Feb. 2015 , pv-tech.org