Design & Installation

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While SCADA systems comprise a relatively small portion of the cost of a large-scale PV power production facility, they are critically important to project success.

To keep everyone’s lights on, grid operators must be able to balance supply and demand across long-distance networks of high-voltage power lines. Supervisory control and data acquisition (SCADA) systems are what allow grid operators to monitor and dispatch power plants—often across vast areas—in response to constantly changing loads. As the solar industry matures and expands its presence on the electric grid, PV power plants are facing increased scrutiny regarding remote monitoring and control. While developers of rooftop projects can activate PV systems and leave them to run on their own, grid operators increasingly tend to require remote monitoring and control capabilities in utility-scale PV applications. Though these requirements are similar to those that apply to conventional generation sources, they may take solar industry veterans by surprise.

In this article, we provide a high-level overview of the North American utility grid and discuss how reliability coordinators and balancing authorities work together to maintain power quality and grid reliability. We briefly look at California to better understand some of the challenges grid operators face when greening the grid. We then take a PV plant–level look at SCADA systems and conclude by sharing best practices for the successful implementation of SCADA systems in large-scale PV plants.

SCADA is deceptively simple on the surface and devilishly complex in the details. Trade-offs that seem small in early utility negotiations can present very large issues for the project team in the field during construction and commissioning. Correctly establishing SCADA implementation requirements as early as possible can ensure project completion on schedule and under budget. Leaving things until the last minute nearly always guarantees delays and gaps in the command and control network. In this arena, it is wise to involve experts sooner rather than later, as the cost of their input will more than pay for itself over the operating asset’s life.

Balancing the Large Machine

The North American Electric Reliability Corporation (NERC) is responsible for maintaining the security and reliability of the bulk power system in North America. Its area of responsibility extends from the northern portion of Baja California, Mexico, across the continental US and Canada. There are four independently operating power grids, shown in Figure 1, within NERC’s purview: the Eastern Interconnection, the Texas Interconnection, the Quebec Interconnection and the Western Interconnection.

Within these large interconnections, reliability coordinators and balancing authorities are responsible for the proper operation of the bulk electric system, in much the same way that air traffic controllers ensure quality and reliability for the aviation industry. Reliability coordinators manage a wide-area view, with the aim of ensuring that the interconnection does not operate outside permitted limits, which could lead to instability or outages. Balancing authorities, meanwhile, are responsible for maintaining the real-time electricity balance within specific regions. NERC recognizes nearly 20 reliability coordinators and more than 100 balancing authorities.

According to a July 2016 blog post (see Resources) on the US Energy Information Administration (EIA) website: “Most, but not all, balancing authorities are electric utilities that have taken on the balancing responsibilities for a specific portion of the power system.” To avoid potential conflicts of interest, however, independent third-party entities known as regional transmission operators (RTOs) or independent system operators (ISOs) operate the bulk electric system in important regions of North America, as shown in Figure 2. These regions are responsible for much of the economic activity in North America, and the RTOs and ISOs ensure fair and transparent access to market transactions and the transmission network. The EIA blog post clarifies as follows: “All of the [RTOs and ISOs] also function as balancing authorities. ERCOT [Electric Reliability Council of Texas] is unique in that the balancing authority, [the] interconnection and the regional transmission organization are all the same entity and physical system.”

As described by the authors of the NERC technical document “Balancing and Frequency Control” (see Resources): “Each interconnection is actually a large machine, as every generator within the island is pulling in tandem with others to supply electricity to all customers.” If the output of these generators does not match customer demand, speed of rotation and frequency within the interconnection changes. The authors explain: “If the total interconnection generation exceeds customer demand, frequency increases beyond the target value, typically 60 Hz, until energy balance is achieved. Conversely, if there is a temporary generation deficiency, frequency declines until balance is again restored at a point below the scheduled frequency.” While the scheduled 60 Hz frequency target allows for some variation, the acceptable range is quite small, on the order of ±0.02 Hz.

For grid operators, frequency is the fundamental measure of power system health. An imbalance between load and generation causes frequency to vary, as do grid congestion or equipment faults. Because grid reliability is critically important, and the power system, interconnections and balancing areas are so large, multiple levels of balancing and frequency control govern the system. The primary control level, for example, includes governors on generators and load-interruption capabilities, which can adjust frequency within seconds and stabilize the power grid in the event of a disturbance. Meanwhile, the secondary control level allows grid operators to maintain the generation-to-load balance over a period of minutes.

According to the NERC technical report, the most common secondary control method is automatic generation control, which monitors and adjusts the power output of multiple generators at different power plants. Grid operators’ control centers choreograph these secondary balancing and frequency control activities, dispatching generators as needed to maintain the load-generation balance. A SCADA network, such as the one shown in Figure 3, allows for centralized data monitoring along with remote control of dispersed power-generation assets. SCADA systems not only provide grid operators with real-time insight into individual plant status and performance, but also allow them to dispatch resources as needed to support grid stability.

The biggest balancing authority in the Western Interconnection is the California Independent System Operator (CAISO), a nonprofit public benefit corporation that manages the bulk power system for roughly 80% of California and a small portion of Nevada. According to a CAISO publication documenting company facts and information (see Resources):“As the only independent grid operator in the western United States, [CAISO] grants equal access to 26,000 circuit miles of transmission lines and coordinates diverse energy resources into the grid. It also operates a wholesale power market designed to capture energy from a broad range of resources at the least cost.”

CAISO operates two control centers to manage all of these transactions and dispatches. Its headquarters in Folsom (see opening photo), home to one of the most advanced control centers in the world, features a 6.5-foot-tall and 80-foot-wide visualization screen. The control center also includes the first renewables dispatch desk in the country, which allows CAISO to manage the additional layers of complexity associated with integrating large numbers of variable generation plants. Since California’s renewable portfolio goals require that its investor-owned utilities (IOUs)—including Pacific Gas and Electric Company, Southern California Edison and San Diego Gas & Electric—generate 33% of their electricity from renewable sources by 2020, CAISO is very much at the forefront of the North American effort to develop flexible capacity and implement technologies that allow for a greener, lower-carbon power grid.

As of February 2017, CAISO was monitoring nearly 72,000 MW of generation capacity, including nearly 10,000 MW of solar PV. The peak summer grid demand in California is typically in the range of 45,000 MW–46,000 MW. Because variable renewable generation makes up so much of its power generation mix, CAISO needs solar and wind power plants to respond to automatic generation control signals and other dispatches just as conventional power plants do. That is one reason why California is leading the way in the development of smart inverter standards via its Rule 21 process. The first phase of this effort mandates that inverter-connected distributed energy resources autonomously perform certain grid support functions, such as dynamic power factor or voltage regulation, power curtailment, ramp-up and ramp-down rate controls, frequency controls, and start-up and shutdown controls.

A vast SCADA network—composed of computers, communication pathways, graphical user interfaces and remote intelligent electronic devices—allows CAISO to balance its grid in real time. In addition to allowing grid operators to initiate or update autonomous inverter functions, SCADA systems at PV power plants also ensure accurate settlements. Regardless of whether a PV plant connects at the high-voltage (38 kV–500 kV) transmission or medium-voltage (4 kV–38 kV) distribution level, the interconnecting utility needs to have some communication with and control of the local plant. Power plants that do not meet the grid operator’s SCADA requirements cannot interconnect. Moreover, poorly implemented SCADA solutions and plant controls may not be taking optimal advantage of the grid operator’s price signals.

SCADA Implementation

SCADA and cloud-based monitoring systems are similar in the sense that they both measure and monitor PV system performance variables. What makes SCADA systems unique are their supervisory control capabilities. While grid operators and regulatory entities drive certain SCADA system compliance requirements, other project stakeholders also need insight into PV plant operations. For example, asset managers have a contractual obligation to report plant data to their financial partners and PPA customers. Plant operations managers need plant data to interface with utilities, conduct performance tests and schedule maintenance. O&M providers, meanwhile, must be able to see and respond to alarms and may also need plant data to comply with production or availability guarantees. A successfully implemented SCADA system accounts for the needs of all project stakeholders and eliminates unnecessary duplication where possible.

The plant-level controller is a key component of a utility SCADA system. The authors of a First Solar white paper about grid-friendly utility-scale PV plants (see Resources) explain: “[The plant-level controller] is designed to regulate real and reactive power from the PV plant, such that it behaves as a single large generator. While the plant is composed of individual small generators (or, more specifically, inverters), the function of the plant controller is to coordinate the power output to provide typical large power plant features such as active power control and voltage regulation.” In First Solar’s plant-level control system, shown in Figure 4, “The plant controller implements plant-level logic and closed-loop control schemes with real-time commands to the inverter to achieve fast and reliable regulation.”

At the plant level, much of the control equipment is housed near the point of interconnection with the utility. In some cases, that equipment is located within a dedicated substation control room; in other cases, it is enclosed in freestanding boxes, installed at ground level or on poles overhead. Depending on the system configuration, the substation has some combination of disconnects, breakers, meters, capacitor and reactor banks, energy storage systems and generator step-up transformers, as well as other components that collect and report component-level data. Typically, dedicated fiber-optic networks originate at the substation and connect to the individual equipment pads.

Components and connections can vary significantly at the pad level. In general, some combination of internet-style connections, industrial control connections and intelligent devices measure, translate, package and transmit data collected from the nearby equipment within the array. Data from across the PV power plant’s inverters, tracker controllers, weather stations and other inverter pad equipment, along with data collected at the substation, go to a real-time controller. The real-time controller runs analytical routines on that data to determine what, if any, changes operators need to make in running the plant to stay within the programmed operating limits.

Security. Because the plant controller is connected to the outside world, grid or plant operators, or other parties with secure access, can change the plant operating limits at any time via the human-machine interface (HMI). It is typical for a PV plant to have multiple outside connections to serve multiple stakeholders. Some of the plants we have worked on have as many as five separate internet connections. Regardless of the connection type—which could be fiber-optic cables, copper telephone lines, cellular modems, and microwave or other radio relays—the security of outside connections is a critical concern.

For instance, CAISO has specific security requirements for connections to its dedicated energy control network. While NERC defines many of these requirements, the Federal Energy Regulatory Commission (FERC) oversees it; one of FERC’s mandates is to approve minimum cybersecurity requirements for the bulk power system. Many utilities base their security protocols on CAISO and NERC standards, but nongovernmental parties to the project often have their own security requirements regarding authentication and encryption.

Network design. Understanding how devices within the project site will talk to one another is a significant part of SCADA implementation. As discussed in the article “Commercial PV System Data Monitoring, Part One” (SolarPro, October/November 2011), sites can rely on many different types of network architectures—such as transmission control protocol/internet protocol (TCP/IP), open data protocol, modbus and controller area network bus (CANbus)—as well as different layers of programming abstractions. For example, users interact with SCADA systems via the applications layer; data are packetized at the transport layer; message routing takes place at the internet layer; and physical components connect to one another at the link layer. At utility-scale PV power plants, multiple network types can exist simultaneously, and it is necessary to transfer data between these networks to operate the plant successfully.

In a plant with large central inverters, it is common for a TCP/IP-based network to connect directly to each inverter via fiber-optic cables. In some cases, the inverter also collects information from the inverter step-up transformer; in other cases, SCADA designers route this information to an analog input/output (I/O) device, and use a historian to record and digitize these data. A plant with string inverters more commonly has a media converter or datalogger near the transformer. One side of this device connects to the plant’s fiber-optic network, while the other collects information from the inverters and transformer based on whatever protocols are available. The pad-level controller could be receiving inverter data from one or more RS-485 networks, I/O data from the transformer, inputs from tracker-motor controllers and weather stations, plus reports from any other networked devices.

When conceptualizing a SCADA system, you must consider three major areas: communications between on-site equipment, such as inverters, weather stations and transformers; communications with off-site regulators, such as utilities and grid operators; and communications with off-site stakeholders, including lenders, asset managers and O&M providers. These three distinct areas have overlapping interests, requirements and technical options for the project. If designers do not know or understand the requirements in each area during the design stage, the resulting SCADA system may have gaps or redundancies that will affect long-term operation, diagnostics and reporting.

To better understand where gaps or pain points may exist in the project’s life cycle, we interviewed subject matter experts representing several experienced SCADA providers, including AlsoEnergy, Draker, Nor-Cal Controls and Trimark Associates (see Resources for a Trimark white paper on best practices). Here we summarize common themes from these conversations and share some of our own strategies for success.

Get experts involved early. All the subject matter experts emphasized the importance of engaging a SCADA design consultant in the earliest project stages. From a certain perspective, modules, inverters and racking are the three major pivots for a solar farm, both financially and in terms of delivery. It is common for SCADA design to take a backseat to these big three items, since monitoring and control systems carry a lower price tag and have shorter equipment lead times. Our experience has shown, however, that a fragile SCADA system can bring an otherwise perfectly built PV site to its knees. Improper handling of SCADA design and implementation can hold up important project milestones—such as substantial or final completion—for weeks or months.

Regardless of whose system ultimately gets installed at the new power plant, project developers need to engage a SCADA consultant as soon as generator interconnection agreement negotiations begin, as these will determine the project’s monitoring, control, security and data storage needs. According to Gregg Barchi, the East Coast sales director for Draker: “There needs to be an industry-wide paradigm shift with regard to monitoring. The earlier we get involved, the better. If an NDA [nondisclosure agreement] needs to be in place for this to happen, we can do that.”

Scott McKinney is the senior marketing manager at Trimark Associates, a SCADA solutions provider headquartered in Folsom, California. He notes that it is important to establish fiber-optic specifications early in the project: “Regardless of the type of inverter system, the network structure is based on the specified number of strands, fiber type and connector type. Making the wrong assumptions and failing to ensure compatibility between all components can result in extra costs and project delays.”

In addition to supporting decisions about the fiber-optic system, an early collaboration with a SCADA provider can also bring clarity to other aspects of the data collection network. Stakeholders need to discuss other communication cables and connector types, software compatibility, security protocols, encryption requirements and component selection. The sooner they finalize these decisions, the better off everyone will be in terms of managing the capital costs and the project schedule.

Gather information in advance. To commence commercial operations and generate revenue, PV resource owners must meet grid operators’ SCADA and compliance-related requirements. Understanding these requirements starts with gathering as much information as possible. You begin by reviewing applicable contracts, including the PPA, generator interconnection agreement, asset management (AM) and O&M agreements, and relevant utility studies. You are looking for information regarding SCADA control equipment specifications, weather station specifications, utility command and control software requirements, references to federal software security protocols, and synchronization and performance testing requirements.

We recommend, in addition to doing a thorough documentation review, putting in a call with the utility—or, if applicable, the grid operator (ISO/RTO)—to verify compliance details. Most performance testing standards require that you collect and average data in 1- or 5-minute intervals at the time of the test. Other requirements come into play based on generating capacity thresholds. For example, NERC has cybersecurity requirements—outlined in its critical infrastructure protection (CIP) standards—that apply to projects larger than 75 MWac. CAISO, meanwhile, requires at least two weather stations for projects with a capacity greater than 5 MWac. It is important to convey these requirements to SCADA design consultants and get their feedback on the scope of work.

Many grid operators make their SCADA requirements publicly available in advance. For example, a CAISO document, “Business Practice Manual for Direct Telemetry,” contains a list of minimum required data points and specifications for weather stations and communications. The data points or I/O list is a good tool for consolidating, reviewing and streamlining the SCADA data required by multiple project stakeholders. While ISO or utility requirements form the core of this list, it should also include data points required for performance testing and monitoring to meet the needs of the O&M and AM teams.

Several positive outcomes are likely if you draft the I/O list early in the project life cycle and use this as a working document during project development. For example, you can identify where different parties have overlapping requirements and look for opportunities to streamline these to improve efficiency. You can strategically design some redundancy into the system to improve resiliency. You can also have key SCADA component vendors review the list to ensure that their products are capable of providing the requested data points. The published specifications include information about the number of instruments, instrument accuracy, minimum polling rates and data retention requirements. It is important to consult instrument vendors to ensure that they can meet these requirements and to determine whether they must perform periodic recalibration to maintain measurement accuracy.

Trimark’s McKinney emphasizes: “The I/O list is the foundation for communications, automation logic, historization and reports. If you understand the I/O list, you can establish effective control logic, key performance indicator metrics, alerts and alarms, and analytical reports. The I/O list is the starting point for the entire SCADA system, so it’s critical to get it right, right from the start.”

Get everyone on the same page. Implementing a successful SCADA system is a team effort, which means that you need to have all team members at the table. As soon as you know the AM and O&M providers for the project, you should engage them in the SCADA design and development process. This helps avoid SCADA commissioning delays and last-minute change orders to meet specialized reporting or system integration requirements.

It is important to remember that utilities are actively learning about PV power plants, just as the solar industry is learning about grid integration. As a result, the utility may have a different understanding of its own PV power plant control needs at the end of the project development life cycle than at the beginning. For example, it is not uncommon for project developers to find out toward the end of construction that a PV power plant needs to provide VAR support through the inverters, through a capacitor bank or both. It is important to maintain clear and open communications with the utility as projects move through their milestones, as periodic communication with the utility can help you avoid this type of scenario.

Unless utilities are large enough to have their own SCADA department, they often consult with SCADA providers to translate their control needs into project-specific requirements. According to Mesa Scharf, utility solutions manager at AlsoEnergy: “To facilitate informed conversations with utilities, EPCs or project developers should have a well-defined scope for SCADA controls and communications. Any entity that owns or operates a large number of sites will also benefit from having its own standard set of SCADA requirements.”

Utility command and control requirements can be highly variable. While California’s Rule 21 includes smart inverter requirements, grid operators implement some of the dynamic grid support functions only on a case-by-case basis. Additional interconnection agreement requirements may also apply; we have seen requirements for direct transfer trip, curtailment, breaker and plant operations status, availability and energy production forecasts. If the utility requests controls such as curtailment, voltage regulation or volt-VAR support, you need clearly defined response times, ramp rates, acceptable third-party commands and security protocols.

McKinney notes that it is increasingly common for PV resources to have to respond to curtailment orders: “We see many sites that are curtailed every day. There are two important issues with curtailment. First, the ‘requests’ can be issued as frequently as every 5 minutes. So the only practical way to execute these orders is through system automation. Second, it’s important to manage power at the point of interconnection, which means resources must be able to coordinate all their inverters to maximize power delivery at the interconnection point and not dip below the allowable maximum if a cloud reduces generation in part of the array.”

Meeting utility command and control orders requires a combination of SCADA hardware, inverter hardware, communications protocols and software programing. As in any industry, communications standards vary among different manufacturers. As a result, you need to discuss inverter technology decisions with your SCADA providers to confirm that you can meet stakeholder requirements for remote site access, control capabilities and interfaces.

McKinney recommends that project stakeholders establish an up-front agreement regarding cybersecurity requirements: “Handling this correctly avoids unnecessary changes due to misunderstandings or differing interpretations. If the NERC-CIP compliance scheme isn’t defined early on, the project can suffer from last-minute hardware changes, rack-space issues and remote access restrictions.”

Establish a SCADA project lead. It is essential to clearly designate a leader for the SCADA design process. Potential candidates include the SCADA provider, a developer’s representative, the design engineering project manager or a team leader from the EPC firm. Once you have designated the SCADA team leader, you can establish a SCADA working group, which should hold regular meetings with key stakeholders in attendance. This working group might include representatives from the EPC, resource owner, AM and O&M teams, SCADA provider, inverter and tracker suppliers, and utility.

Multiple parties are involved in the process of supplying SCADA system components, installing them, terminating communications cables and commissioning the system. To coordinate all these efforts, it is extremely helpful to have the SCADA working group create a responsibilities matrix early in the design process. As illustrated in Table 1, this matrix assigns ownership of each piece of equipment and establishes which team members need to coordinate to complete each task.

Clearly define the scope of work. The responsibilities matrix aids in the process of evaluating bids from various vendors to ensure that there are no scope-of-work gaps and that you manage interface points between scopes from the outset. This allows you to clearly communicate to all involved parties an understanding of their responsibility. A clearly defined scope of work is critical when you are developing a request for proposal (RFP). The working group must address many questions: How much of the SCADA plan set will the design engineering firm complete, and where do vendors need to step in with their own shop drawings? Will the SCADA provider be on-site during commissioning, or does the EPC team have a qualified individual to serve as field technician in communication with the SCADA provider? When the project goes from the EPC to O&M, will the SCADA provider need to provide training, or will the EPC complete the handoff?

The process of releasing and responding to RFPs is an early opportunity for project developers and SCADA providers to get on the same page with regard to SCADA specifications and equipment decisions. “The request should be as specific as possible,” notes Rob Lopez, director of business development at Nor-Cal Controls. “The list of details should include inverter make, model, capacity and quantity; tracker make, model and quantity of tracker controllers; site power meter make and model; substation IED [intelligent electronic device] specifications; single-line and system block diagrams; site layout; fiber-optic network specifications [single-mode or multimode cable, fiber core diameter, connector type]; communications enclosure locations; contractually required controls; AM and O&M interface requirements [visibility only or advanced controls]; quantity and approximate locations of weather stations; measurement parameters and sensor accuracy requirements; overall project schedule, including SCADA activities; and, if applicable, description of control room.”

Ensure software compatibility. Meeting the needs of multiple stakeholder groups requires multiple HMIs. In terms of software integration, the design team frequently overlooks the AM interface and the operations interface. After the team has built and commissioned the project, someone will need to monitor and ensure continuous operation of the generator. According to Alex Martinez, manager of AM at Coronal Energy, Powered by Panasonic: “Accurate data is critical to analyze past, present and future plant performance. The SCADA system is the backbone of our operations.”

The AM team relies heavily on alarms and status messages to ensure smooth, continuous energy generation. It is important to develop alarm definitions as early as possible and to make sure that these meet the contractual obligations of the involved parties. Most SCADA providers assume that component-level alarms, or simple parroting of equipment alarm messages, is sufficient for downstream operators. Typically, however, additional context is required for asset managers to make sense of equipment fault messages. For example, troubleshooting many of the issues that might lead to an open ac contactor requires data about internal and external temperatures. It is also critical for asset owners and operators to be able to track the performance of subsystems or components and generate alarms based on indications of degradation rather than on failure only.

Having a data historian available, whether located on the site or in the cloud, will enable the system to store project data and provide application interfaces to other software systems. While different stakeholder groups may have different HMIs, each one needs programmatic access to the historian’s data for analysis and display. If the historian does not have a standard application programming interface that other software tools can use, the resulting inconsistency will cause difficulties for downstream teams, requiring rectification.

Coordinate schedules in the field. After you have completed all the design work, the next critical step in the process is field coordination. EPCs need to not only include key milestones related to the SCADA system in the construction schedule, but also keep the SCADA provider up-to-date about schedule changes.

“The biggest issue for us,” say McKinney, “is to know when the inverter pads, panelboards and fiber network will be installed. We also need to coordinate conduit runs and network drop terminations. It’s also important that we know when our cabinets should arrive on-site for the electrical contractor to mount.” McKinney warns: “One issue that EPCs often don’t understand is the criticality of CAISO’s New Resource Integration process. To attain meter certification and secure telemetry, the project must meet specific lead times and milestone approval requirements. EPCs are mistaken if they think that their project will somehow get special treatment and that CAISO will excuse them from adhering to its timeline.”

The project schedule must provide sufficient time for SCADA commissioning, which, depending on project size and complexity, may take as little as a few days or as long as several weeks. SCADA commissioning often gets squeezed due to the last-minute provision of power and communications infrastructure to the site. While some tension in this area is inevitable, as there may be networking costs or contractual reasons for delaying energization, EPCs need to weigh these up-front costs against possible liquidated damages incurred due to delays in passing performance and acceptance tests.

The SCADA responsibilities matrix is helpful to facilitate scheduling around vendor needs, especially relative to other project partners. For example, does the EPC need to complete tracker and inverter commissioning before SCADA commissioning can commence? How will the EPC commission the power system: all at once, one circuit at a time or according to some other pattern? Does the utility require a staged (governed) commissioning to ensure grid stability as you bring the new project on line? If so, how will the EPC handle that staging?

Take time to fine-tune the system. As the EPC brings equipment on line, the SCADA system will expose issues in the power network, as it is designed to do. Establishing protocols for how to flag and resolve status and error messages goes a long way toward ensuring a quick resolution. The goal is for vendors to focus on resolving issues rather than pointing fingers at one another and arguing about who is at fault or who is responsible for troubleshooting. In many cases, the SCADA system is the messenger, not the problem; expecting the SCADA vendor to handle troubleshooting is generally not the most efficient method for resolving field issues.

After establishing commercial operations, the O&M team will need to spend some time fine-tuning the alarm system. Alarm thresholds should be programmable so that operators can adjust their sensitivity. This helps prevent issues related to alarm fatigue. If operators receive too many meaningless messages or false alarms, they may overlook alerts associated with real issues that they need to address.


Bill Reaugh / Blue Oak Energy / Davis, CA /

Rowan Beckensten / Blue Oak Energy / Davis, CA /

Debbie Gross / Blue Oak Energy / Davis, CA /

David Brearley / SolarPro / Ashland, OR /


California Independent System Operator Corporation, “California ISO Company Information and Facts,”, August 2016

First Solar, “‘Grid-Friendly’ Utility-Scale PV Plants,” white paper,, August 2013

NERC, “Balancing and Frequency Control,” technical document,, January 2011

Trimark Associates, “Best Technology Practices: Effective, Utility-Scale Solar Power Resources,” white paper,, February 2016

US Energy Information Administration, “US Electric System Is Made Up of Interconnections and Balancing Authorities,” blog post,, July 20, 2016

SCADA Providers

AlsoEnergy / 866.303.5668 /

Draker / 866.486.2717 /

Nor-Cal Controls / 530.621.1255 /

Trimark Associates / 916.357.5970 /

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Every 3 years the solar industry receives an updated set of instructions for designing and installing PV systems—the National Electrical Code. Although adoption dates for the new Code vary by jurisdiction, many states will be operating under NEC 2017 by the end of this year.

In this article, we discuss the practical implications of NEC 2017 for PV system design and installation; we also provide specific information about the intent of the new requirements, compliance strategies, cost implications and perspectives from industry experts. This article references callout tags, shown in Figure 1, that provide system designers with a quick guide to 2017 Code changes.

Note that large-scale PV systems are not a main focus of this article. One of the changes in NEC 2017 is the introduction of Article 691, “Large-Scale Photovoltaic (PV) Electric Power Production Facility,” which applies to non–utility-controlled solar farms with a capacity greater than or equal to 5 MWac. The focus of this article is those residential, commercial and industrial PV systems that must comply with Article 690.

Callout A: Functional Grounded PV Systems

NEC 2017 introduces a definition for a functional grounded PV system, which is one that “has an electrical reference to ground that is not solidly grounded.” Unsurprisingly, this category includes PV systems that the industry previously referred to as ungrounded, which includes the majority of contemporary string inverters and module-level power electronic (MLPE) devices. Surprisingly, the functional grounded concept also applies to PV systems previously referred to as grounded, which includes legacy systems and large-scale systems that use transformer-isolated inverters.

An informational note in 690.2 elaborates: “A functional grounded PV system is often connected to ground through a fuse, circuit breaker, resistance device, non-isolated grounded ac circuit, or electronic means that is part of a listed ground-fault–protection system. Conductors in these systems that are normally at ground potential may have voltage to ground during fault conditions.” Any technician who has had to troubleshoot a ground fault in a so-called “grounded” PV system knows that “if a ground fault is indicated, normally grounded conductors may be ungrounded and energized.” That is because these systems make the connection to ground via a fuse, which does not meet the solidly grounded definition in Article 100.

The implications of the functional grounded PV system concept ripple throughout NEC 2017, affecting requirements related to disconnecting means, overcurrent protection, wiring methods and conductor identification. While the practical implementation of these changes is not difficult, especially in residential applications or systems with MLPE, it may take some time for installers and inspectors to align their practices and expectations with the new requirements.

Jason Fisher is Solar City’s principal compliance engineer as well as a member of Code-making panel (CMP) 4, which is responsible for Articles 690 and 705. Fisher notes: “In the short term, the new PV system grounding configurations in 690.41 will likely cause some confusion for the installation and enforcement communities. While the new grounding configurations are more comprehensive and accurate than those in previous Code editions, they do have implications beyond grounding practices related to conductor color coding, overcurrent protection and disconnecting means. Since these new installation methods are most appropriate for our current limited electrical systems, I am confident that everyone will become accustomed to these changes over a short period of time. Once you understand the definition of a functional grounded PV system, you realize that we almost never install solidly grounded or ungrounded PV arrays.”

According to Bill Brooks, principal of Brooks Engineering and another member of CMP 4, the expanded system grounding configurations in 690.41 will actually simplify system design, installation and inspection. Brooks points out that CMP 4 was able to eliminate Section 690.35, “Ungrounded PV Systems,” in its entirety as part of the 2017 cycle of revisions. The definition of a functional grounded PV system includes not only PV systems deployed with transformerless (TL) or non-isolated inverters, but also PV systems deployed with transformer-isolated inverters. Brooks concludes: “We now have a single wiring method that works for all types of PV systems and inverters. This single wiring method will help contractors and AHJs, saving everyone time and money. It is also safer.”

Callout B: Conductor Color Marking and Wire Type

Section 690.31(B)(1) permits only solidly grounded conductors to have a white or gray outer finish per 200.6. In light of the new definition of functional grounded systems and the changes in 690.41 and 690.42, the only type of PV system designated as solidly grounded is one with no more than two PV source circuits, and with no dc circuits on or in a building. Thus, practically speaking, any residential or commercial PV system can no longer have field-installed white- or gray-colored dc PV conductors. Because MLPE-based systems without field-installed dc wiring and TL-type string inverters (where the transition away from white- and gray-colored conductors has already occurred) dominate the residential and commercial markets, this is generally not a significant change for most installers. The exception to the rule is large-scale ground-mounted systems deployed using central inverters with fuse-based ground-fault–protection devices: Since these systems are also considered functional grounded under NEC 2017, installers can no longer use white or gray conductors in these applications.

What conductor colors should integrators use? The NEC does not include any prescriptive requirements, except that conductors should not be white or gray [690.31(B)(1)], or green or bare [250.119]. Identifying conductor polarity is important for avoiding field wiring mistakes, and many installers default to using red (positive polarity) and black (negative polarity) for field-installed dc conductors. Installers should be aware, however, that some red conductors have been known to fade to white after short- to medium-term UV exposure. A good option for both longevity and polarity identification is to use black conductors with a colored tracer stripe visible along the length of the conductor.

Servicing legacy systems. The new grounding nomenclature does away with a particularly problematic previous Code prescription that required PV Wire for exposed single-conductor cables in “ungrounded” PV systems, which excluded the use of USE-2 conductors. This requirement meant that service technicians faced nearly insurmountable Code-compliance issues when replacing older “grounded” inverters with TL inverters, as these legacy systems often rely on USE-2 conductors for field wiring. Section 690.31(C)(1) now clarifies that installers may use both PV Wire and USE-2 for any exposed outdoor PV source-circuit wiring within the array.

Due to the new color-marking requirements, however, technicians should be particularly cautious when performing maintenance on older systems. Never make assumptions about polarity or voltage based on labels or color coding. Always use a multimeter to verify potential with reference to ground.

Callout C: Voltage and Current for Systems ≥ 100 kW

Articles 690 and 691 now define generating capacity as “the sum of parallel-connected inverter maximum continuous output power at 40°C in kilowatts.” As part of the 2017 cycle of revisions, CMP 4 made an effort to reduce costs for larger PV systems, specifically those with a generating capacity greater than or equal to 100 kW. To that end, it added new maximum voltage and circuit current calculation methods, in 690.7(A)(3) and 690.8(A)(1)(2), that allow PEs to use computer simulations to calculate these values. While the traditional calculation methods ensure safety, the CMP recognized that they may also be overly conservative. Using computer models to simulate maximum voltage and current is not only more accurate, but also may allow for more modules per source circuit or smaller conductors and conduit—all of which can lower material costs.

Designers on projects with a generating capacity of more than 100 kW can utilize these new calculation options where a licensed PE designs the system using “an industry-standard method” and provides stamped documentation. Informational Notes clarify that Sandia National Laboratories’ “Photovoltaic Array Performance Model” is one example of an industry-standard method for calculating these values. Since a variety of common PV system simulation programs—such as Helioscope, PVsyst and SAM—incorporate the Sandia model, PEs can use these platforms to calculate maximum voltage and current values for dc PV circuits.

Calculating maximum current. With regard to the maximum current calculation for PV source and output circuits, it is worth noting that 690.8(A)(1)(2) contains two directives. First, the value must be based on the “highest 3-hour current average resulting from the local irradiance on the PV array accounting for elevation and orientation.” This is the value that PEs can derive from simulation program data. Second, the Code establishes a floor or minimum value that applies regardless of the simulation results. Specifically, the current value cannot be less than 70% of the value calculated using 690.8 (A)(1)(1), which is the traditional method of calculating the maximum current based on 125% of the parallel-connected PV module Isc ratings.

“It will take engineers a while to grasp the maximum current calculation method,” opines Brooks, “but once they do, PV system designs will improve. The new calculation method will reduce conductor and conduit costs, which make up an increasing percentage of the overall costs in large PV systems.”

As an example, consider a case in which a professional electrical engineer performs a simulation showing that the highest 3-hour average annual source-circuit current value is 8.6 A for an array made up of modules with an Isc rating of 9.49 A. If the system has a generating capacity of less than 100 kW, the PE must size the source-circuit conductors based on 690.8(A)(1)(1): 9.49 A x 125% = 11.86 A. If the system has a generating capacity of more than 100 kW, the PE can size the conductors based on the simulated value (8.6 A), according to 690.8(A)(1)(2), provided that the simulated value is not less than 70% of the 690.8(A)(1)(1) value. In this case, the simulated value is the maximum current for design purposes, since 8.6 A is higher than the minimum allowable value of 8.3 A (11.86 A x 70%).

Maximum voltage. Integrators and inspectors should note that 690.7 expands on the maximum voltage limits between any two circuit conductors and any conductor and ground. As in earlier Code editions, the maximum allowable voltage in one- and two-family residential applications remains 600 Vdc. Unlike in earlier editions, the maximum allowable voltage for PV systems on other types of buildings is now 1,000 Vdc. Ground-mounted systems, meanwhile, are not subject to a voltage limitation and do not need to comply with Parts II and III of Article 490 if they have a rated voltage of 1,500 Vdc or less.

Callout D: DC Arc-Fault Detection and Interruption

The 690.11 requirements for dc arc-fault circuit protection for PV systems operating at 80 Vdc or greater are unchanged in 2017. However, the CMP added an exception for PV output circuits and dc-to-dc converter output circuits not in or on buildings; this exception applies to circuits that are direct buried or installed in metal raceway or enclosed metal cable trays. It is also worth noting that 691.10 allows for large-scale (5 MW or greater) PV systems that do not comply with 690.11, provided that a PE designs and documents an alternative fire mitigation plan.

Brooks explains the logic behind these requirements: “The exception in 690.11 is based in part on the fact that no arc-fault–detection equipment exists for circuits operating above 40 A. While there are no protective devices that address PV output circuits, arcing faults in circuits that are direct buried cannot start a wildfire, and the ground-fault–protection system will detect arcing faults in circuits in metal raceways and enclosures. Since the exception does not cover source circuits, ground-mounted PV plants with a generating capacity less than 5 MW are still required to have arc-fault detection on source circuits. Developers of large-scale systems can look to Article 691.”

It is important to note that the dc arc-fault exception for PV output circuits does not cover roof- or building-mounted systems. Unless UL develops new product safety standards to address higher-current dc arc-fault devices, dc PV circuits operating above 80 V and 40 A cannot comply with NEC 2017, which means that higher-capacity central inverters with PV output circuits are essentially not allowed in rooftop applications. String inverters with integrated dc arc-fault protection can meet 690.11 requirements in rooftop or ground-mounted applications. Where the exception applies, ground-mounted applications can use dc combiners with string-level arc-fault devices.

Callout E: Rapid Shutdown of PV Systems on Buildings

For the second Code cycle in a row, 690.12, “Rapid Shutdown of PV Systems on Building,” is raising eyebrows. The CMP made significant changes and additions to this section, expanding it from a mere 133 words in NEC 2014 to more than 1,100 words in NEC 2017. We focus on a few of the most notable revisions related to initiation device type and location, and control limits outside and inside the array boundary.

Initiation device. The new subsection 690.12(C) provides specific guidance regarding allowable types of rapid-shutdown– initiation devices, including the service disconnecting means, PV system disconnecting means and readily accessible switches that clearly indicate “on” and “off” positions. This subsection further states that initiation devices at one- and two-family dwellings must be readily accessible and located outside the buildings. A six-handle initiation device rule also applies where there are multiple PV systems on a single service.

Outside array boundary. The NEC 2017 requirements for controlling PV circuit conductors outside the array are similar to those in NEC 2014, with one notable exception that will be of particular concern to system designers and installers: As shown in Figure 2, the 2017 Code defines the array boundary as extending 1 foot from the array in all directions, rather than the NEC 2014 5-foot boundary for conductors entering a building or 10-foot boundary for conductors on the roof. In the short term, integrators can design and install NEC 2017–compliant PV systems much as they are doing now—using MLPE, remotely operable roof-mounted shutdown devices or roof-mounted string inverters—except that they must now locate the latter two solutions much closer to the PV modules. Note, however, that subsection 690.12(D) requires the use of equipment specifically listed for performing the rapid-shutdown function as opposed to simply rated for the switched current and voltage.

Inside array boundary. New requirements in 690.12(B)(2) for controlling PV circuit conductors within the array illustrate where rapid-shutdown compliance becomes more difficult. This is the subsection that has industry stakeholders using the term module-level rapid shutdown when talking about the new Code requirements. This term is not entirely accurate, however, as 690.12(B)(2) lists three methods of controlling conductors within the array: using listed rapid-shutdown PV arrays [690.12(B)(2)(1)]; limiting conductors to 80 Vdc or less within 30 seconds (module-level shutdown, in other words) [690.12(B)(2)(2)]; or employing PV arrays with no exposed wiring or conductive metal parts [690.12(B)(2)(3)].

The requirements for controlling conductors within the array boundary are contentious for several reasons. Many solar industry stakeholders feel that they will drive up costs and may compromise system reliability. Others question their efficacy with regard to firefighter safety, the primary goal of rapid shutdown. While it is beyond our scope to explore all of the technical issues and stakeholder perspectives related to this topic,  “Module-Level Rapid Shutdown for Commercial Applications” covers them in detail (SolarPro, September/October 2016).

One bit of good news for the installer community is that the CMP delayed enforcement of the new requirements inside the array boundary until January 1, 2019. This short-term relief is intended to provide a UL Standards Technical Panel time to develop a product safety standard for listed rapid-shutdown arrays, as well as to allow manufacturers time to develop compliant products and solutions.

Systems with energy storage. More good news for system integrators is that the CMP added several new diagrams to 690.1. In particular, Figure 690.1(b) clarifies that the Code does not consider energy storage systems, multimode inverters, stand-alone inverters or any associated loads to be PV system circuits. Therefore, these circuits are not subject to the rapid-shutdown requirements in 690.12. The Code requirements related to energy storage systems are found in Article 706, which does not mention rapid shutdown.

Callout F: Overcurrent Protection and Disconnects

Apart from rapid-shutdown requirements for PV systems on buildings, the most substantial 2017 Code changes with regard to system design relate to overcurrent protection devices (OCPDs) (690.9, “Overcurrent Protection”) and disconnecting means (690.13, “Photovoltaic System Disconnecting Means”; and 690.15, “Disconnection of Photovoltaic Equipment”). Designers and installers should read these sections carefully.

Overcurrent protection. System designers and installers should pay particular attention to the revised OCPD requirements for PV source and output circuits in 690.9(C). Whereas NEC 2014 and earlier Code editions required OCPD in both poles of PV systems deployed using non-isolated Type-TL inverters, NEC 2017 requires only a single OCPD, as shown in Figure 3. Designers can place this single OCPD on either pole of the array, provided that all the devices in the PV system are in the same polarity.

Much of the content in 690.9(B) regarding OCPD rating is not new, but the 2017 edition reorganizes it. For example, the CMP moved the requirement that OCPDs in dc PV circuits be listed for the application to this subsection. Note that the CMP added a new allowance for adjustable electronic OCPDs in 690.9(B)(3).

Disconnecting means. Previous Code editions sometimes left system designers and installers at odds with jurisdictional authorities regarding what constituted the PV system disconnect, where to locate it and how to label it. The additions and changes to Figure 690.1(b) are welcome clarifications, as the PV system disconnect location is clearly marked for a variety of system configurations. These diagrams, in combination with extensive rewrites to 690.13, should allow designers to confidently implement NEC 2017 requirements for PV system disconnecting means.

It bears emphasizing that all energy storage equipment, battery-based inverters and loads lie outside the boundary of the PV system. This is a very important distinction that SolarPro has covered previously in some detail. See the article by Bill Brooks, “NEC 2017 Updates for PV Systems” (SolarPro, May/June 2016), for an in-depth discussion of this topic.

System designers should pay careful attention to 690.15, as some of the terminology may be new to many in the solar industry. As an example, the CMP introduced the term isolating device, which in this context is a device that is intended for isolating PV equipment and circuits from the source of power and that does not require an interrupt rating. Note that the allowable types of isolating devices are listed in 690.15(C).

While these devices must be able to provide isolation from all conductors that are not solidly grounded, they are not subject to the simultaneous disconnection requirements that apply to PV system disconnecting means [690.13(F)(1)]. Note, however, that isolating devices alone do not suffice for dc combiner output circuits, or inverter or charge controller input circuits operating over 30 A; these circuits require an equipment disconnecting means. Unlike isolating devices, equipment disconnecting means are subject to simultaneous disconnection requirements [690.15(D)]. Both equipment disconnects and PV system disconnects are allowed in place of isolating devices.

Practically speaking, one of the most significant changes in NEC 2017 is that it requires isolating devices or disconnecting means in both poles of a PV circuit, as shown in Figure 3. The Code requires the provision of these devices as needed to isolate PV equipment—including modules, fuses, dc-to-dc converters, inverters and charge controllers—from “all conductors that are not solidly grounded.” Since the vast majority of PV systems are functional grounded rather than solidly grounded, it is necessary to disconnect both poles of PV circuits.

Practical considerations. It is helpful to think about how NEC 2017 requirements apply to common applications, such as dc combiners, inverter-integrated combiners or inverter input circuits. First, disconnection means are required to isolate fuses from ungrounded conductors. A touch-safe fuseholder itself qualifies as an isolation device for circuits with a maximum current up to 30 A. Second, dc combiner output circuits with a maximum current greater than 30 A require an equipment disconnecting means that is capable of opening both poles simultaneously and is either integral to the equipment, located within sight and within 10 feet of the equipment, or remotely operable from within 10 feet of the equipment. The requirement for equipment disconnecting means also applies to inverter input circuits (>30 A).

In rooftop applications, arc-fault requirements effectively limit dc combiner outputs to 40 A or less; rapid-shutdown requirements, meanwhile, mandate remotely operable equipment disconnecting means capable of simultaneously disconnecting all current-carrying conductors. When specifying equipment for ground-mounted systems with a generating capacity of less than 5 MWac, integrators should be aware that the majority of disconnecting combiners currently on the market are designed to disconnect one pole of the array only. In large-scale applications, 691.9 provides PEs with more design latitude for PV equipment isolation; this allowance assumes that only qualified persons service the array and that they are provided with written safety procedures and conditions, as well as  operation and shutdown procedures.

It is not clear how manufacturers will go about meeting the demands of a fragmented market, given that Code cycle adoption varies across the US. Brian Lydic, senior standards and technology engineer at Fronius USA, elaborates: “Our non-isolated units already required simultaneous disconnects for all poles, so that’s no issue for us. The single-pole OCPD question is more interesting. Right now, installers have the ability to install ‘slugs’ or blanks in fuseholders, which means they can fuse poles or not depending on the AHJ’s adopted Code cycle. To reduce costs, of course, we’d like to eliminate half of the fuseholders as soon as possible. We want to work with industry stakeholders to push the acceptance of the new wiring methods so that all customers, even those in pre-2017 jurisdictions, can enjoy the lowest costs.”

Michael Neiman, an applications engineer at Yaskawa–Solectria Solar, echoes these sentiments: “We designed the dc and ac interfaces of our products with flexibility in mind. Thanks to this flexibility, we are configuring interfaces across our inverter and combiner product families to take full advantage of—as well as fully comply with—the new Code requirements. For example, we can simplify our string combiners by fusing just one dc polarity and not both. This lowers the product cost to our customers.”

Callout G: Equipment and System Grounding

In Part V of Article 690, there is a lot of shaded gray text, which the NFPA uses to indicate where the Code has changed. In many of these places, including in 690.43, “Equipment Grounding and Bonding,” the CMP reorganized and clarified existing requirements without making substantial changes. It left other sections, such as 690.45, “Sizing of Equipment Grounding Conductors,” more or less unchanged.

Perhaps the biggest changes are in 690.47, “Grounding Electrode System.” At first glance, the brevity of this section compared to earlier editions is striking. However, this results largely from the fact that the new functional grounded PV system definition eliminates the need to differentiate between various system grounding configurations. On the whole, the revised rules will simplify system design and installation, as well as reduce material costs.

As an example, the 2017 Code cycle removes all requirements related to dc-specific grounding electrode conductors (GECs) for systems that are not solidly grounded. This means that PV system grounding conductors do not have to be continuous and are not sized per 250.166, but rather in accordance with 250.122. Only solidly grounded PV systems, which are increasingly rare, are required to have a dc GEC connected to the grounding electrode system and sized in accordance with 250.166. As described in 690.41(A), the most common PV system grounding configurations are not solidly grounded. This means that the equipment grounding conductor, on the output of the PV system and connected to the associated distribution equipment, provides the connection to ground for ground-fault–protection purposes and bonding. Part VII of Article 250 defines the allowable methods of equipment grounding.

Metal in-ground support structures. One important point of clarification appears in 690.47(A), which requires that both buildings and structures supporting PV arrays have a grounding electrode system. Since Article 100 defines structure as anything that is “built or constructed, excluding equipment,” this extends to PV racks and mounting structures. With this in mind, integrators working on ground-mounted PV systems should take note of a new type of grounding electrode permitted.

A new subsection, 250.52(A)(2), is dedicated to metal in-ground support structures that comprise a metal extension of a building or structure and qualify as grounding electrodes. Many of the foundations used for ground-mounted PV systems—including pilings, ground screws and other metal foundations—can qualify as grounding electrodes provided that the metal is in direct vertical contact with the earth for at least 10 feet. More important, at buildings or structures with multiple metal in-ground supports—as is typically the case with PV ground mounts—installers need to bond only one of these in-ground supports to the grounding electrode system. This last detail is important. Normally, 250.50 requires that all the grounding electrodes at a building or structure be bonded to form a single grounding electrode system. The allowance in 250.52(A)(2) means that installers working on a structure with multiple pilings can use a single bonding jumper to connect one piling to the grounding electrode system.

Additional auxiliary electrodes. NEC 2017 has renumbered the sometimes controversial requirement for additional auxiliary electrodes as 690.47(B) and, significantly, has made it more permissive. The revised version allows— but does not require—installation of electrodes at the location of ground- and roof-mounted arrays, and changes the GEC-sizing requirement. Revised language in 250.66 (which concerns ac grounding electrode sizing) clarifies that the GEC does not need to be sized any larger than the particular maximum for a given type of electrode, provided that the GEC “does not extend on to other types of electrodes that require a larger-size conductor.”

Note that the Code does not require bonding additional auxiliary electrodes to an existing grounding electrode system by means of a bonding jumper. In many cases, however, installing a bonding jumper will provide a superior path for lightning-induced surges as compared to bonding by equipment grounding conductors only.

According to SolarCity’s Fisher, the revised 690.47(B) will reduce system costs and eliminate confusion. He notes: “This section has always been confusing to understand and to comply with. The language that presented real challenges was the directive to locate the auxiliary grounding electrode ‘as close as practicable to the location of roof-mounted PV arrays.’ Frequently this language requires a site-specific discussion with the field inspector prior to installation, especially for complex arrays and buildings. It also presents real challenges to people concerned about the impact of this new grounding electrode system with regard to lightning effects. NEC 2017 clarifies that a grounding electrode system must be in place for a building, but that an existing system that is Code-compliant is satisfactory. The PV system equipment grounding conductors must simply be bonded to this grounding electrode system using traditional methods found in Section 250. This revision helps reduce costs by removing ambiguity around NEC requirements.”

Callout H: Labeling and Marking

While the majority of labeling requirements for PV systems remain unchanged, installers will appreciate the fact that NEC 2017 removed a few, including the 2014 requirements for ground-fault warning labels for both grounded systems [690.5(C)] and ungrounded systems [690.35(F)].

In addition, the CMP simplified the dc PV power-source labeling requirements. To meet 690.53, most PV systems will need a label with only two lines: maximum voltage [per 690.7] and maximum circuit current [per 690.8(A)]. Where charge controllers or dc-to-dc converters are installed, the label must also call out these maximum current values. Installers should place the 690.53 label on dc PV equipment disconnects or dc PV system disconnects in multimode or stand-alone inverter systems. The PV system disconnecting means for interactive systems does not require this label, since this disconnect is on the ac side of the system [see Figure 690.1(b)].

Unfortunately, installers will spend any pennies saved on ground-fault and dc PV power-source labels on new rapid-shutdown labeling: 690.56(C)(1) requires a label identifying the type of rapid shutdown (inside and outside the array boundary or outside only); 690.56(C)(2) requires a roof map for buildings with more than one type of rapid shutdown, as shown in Figure 4; and 690.56(C)(3) requires a label identifying the initiation device. (See “NEC 2017 Updates for PV Systems,SolarPro, May/June 2016, for more information.)

Callout I: Point of Interconnection

The CMP greatly revised the point of interconnection requirements as part of the 2014 revision cycle. The most significant changes are largely intact in NEC 2017, though some of the numbering is revised and the term “power source” replaces “inverter” in many cases. For an in-depth discussion of options for making a Code-compliant interconnection under NEC 2014 or NEC 2017, see Jason Fisher’s recent article “Interactive Inverter Interconnection(SolarPro, January/February 2017).

One notable change in 705.12 bears mentioning, since it will benefit some residential installers: The CMP added a version of the longstanding “120% rule” that applies specifically to center-fed panelboards. A new subsection, 705.12(B)(2)(3)(d), clarifies that installers can make a load-side connection on either end—but not both ends—of a center-fed panelboard, as shown in Figure 5, provided that the sum of 125% of the power-source output current plus the rating of the OCPD protecting the busbar is less than or equal to 120% of the busbar rating.

Practice Makes Perfect

As is the case with each Code cycle, NEC 2017 revisions both reflect the past and look to the future. The CMP seeks to improve on the past by addressing common design and installation mistakes that compromise the safety of fielded PV systems. At the same time, it may also use new Code requirements—such as module-level rapid shutdown—to push manufacturers and industry stakeholders to develop products or features that improve safety. To that end, manufacturers have become increasingly involved in the Code-making process over the last few cycles, in part so that they can implement design changes focused on making installations easier and more affordable while still meeting evolving Code requirements. We recommend that system designers and installers also get involved—and quickly. The deadline for public input for NEC 2020 is September 7, 2017.


Rebekah Hren / Solar Energy International / Winston Salem, NC /

Brian Mehalic / Solar Energy International / Winston Salem, NC /

Primary Category: 

Module manufacturers are continuously refining their cell materials, designs and manufacturing processes; optimizing cell and cell-string electrical interconnectivity; and developing specialized glass, encapsulants and structural elements to create large-format, high-power products. These approaches have resulted in the rapid expansion of a high-power module product class that solar professionals commonly delineate as products with outputs of 300 W STC and greater.

Updated for 2017, the following c-Si module specifications table includes detailed electrical and mechanical specifications for 232 models with rated outputs of 300 W STC and greater from 29 manufacturers. The included models are listed and available for deployment in US-based projects. This c-Si specifications table is not intended to be exhaustive or all-inclusive; rather, our goal is to present comparative information on a wide cross-section of high-power PV solutions for utility, commercial and select residential projects.


Joe Schwartz / SolarPro / Ashland, OR /

PV Manufacturer Contact:

Astronergy / 415.802.7399 /

Auxin Solar / 408.868.4380 /

AXITEC / 856.254.9057 /

Boviet Solar / 877.253.2858 /

Canadian Solar / 888.998.7739 /

Centrosolar America / 877.348.2555 /

ET Solar / 925.460.9898 /

Hanwha Q Cells / 949.748.5996 /

Itek Energy / 360.647.9531 /

Jinko Solar / 415.402.0502 /

Kyocera Solar / 800.223.9580 /

LG / 888.865.3026 /

Mission Solar Energy / 210.531.8600 /

Panasonic /

Phono Solar / 855.408.9528 /

REC Group / 877.890.8930 /

Silfab Solar / 905.255.2501 /

Solaria / 510.270.2500 /

SolarTech Universal / 561.440.8000 /

SolarWorld / 503.844.3400 /

Sonali Solar / 888.587.6527 /

Suniva / 404.477.2700 /

SunPower / 408.240.5500 /

Ten K Solar / 877.432.1010 /

Trina Solar / 800.696.7114 /

Upsolar / 415.263.9920 /

Vikram Solar /

WINAICO / 844.946.2426 /

Yingli Solar /

Primary Category: 

Modeling PV system energy production is a critical step in the solar design process. Accurate energy predictions are required to understand the performance implications of different hardware components and to assess the financial returns of a proposed design. Multiple approaches and software tools can simulate solar energy production, ranging from simple array-level calculations to detailed component-level circuit models. In this article, I discuss taking the latter approach even further: to the sub-module level, which analyzes the shade impacts and electrical behavior of a design down to the level of cell strings and bypass diodes inside the solar modules. 

Simulating solar designs to the cell-string level can have an appreciable impact on energy production estimates. Only by simulating at this level can you accurately assess the effects of bypass diodes, especially for commercial designs with interrow shading and residential designs in partial shade. Moreover, some integrated power electronics such as cell-string optimizers require a submodule simulation to accurately model their impact on energy production. Taking into account manufacturer-verified cell-string and bypass diode configurations helps ensure that a project’s predicted energy yield is as accurate as possible.

Bypass Diodes

Module datasheets often include current voltage and power voltage curves that show how the module output power varies in relation to irradiance. When the irradiance on the module is very low—as is the case when the module is fully shaded—its power output is generally low. If this module is part of a string of modules connected to an inverter, it can cause the power of the entire string to drop because the current through the string can be only as high as the current through the most shaded module. Manufacturers integrate bypass diodes into their modules to mitigate this effect.

A bypass diode is a semiconductor device that, for the purpose of its application in solar modules, can be thought of as an on/off switch. When the diode is off, it is not conducting any current; but when it is on, it can conduct any amount of current. The diode typically turns on at a voltage of 0.6 V–0.7 V. Assuming a scenario with one bypass diode per module, when the diode is on, it effectively shorts out the module by routing the string current through the diode instead of through the shaded cells.

As an example, consider the case where nine out of 10 modules are capable of outputting 8 A of current at a voltage of 32.5 V, but one of the 10 modules is shaded and can produce only 1 A at about the same voltage, as shown in Figure 1. If current cannot bypass the weak module, then the total output power will be roughly 325 W (10 modules × 32.5 V × 1 A), because the entire string is forced to operate at the lowest module current. (This assumes the unshaded modules still operate at their rated Vmp; in reality, they operate closer to their Voc.) If, however, current can skip the shaded module because its bypass diode turns on, then the total output power becomes 2,340 W (9 modules × 32.5 V × 8 A), excluding some small power loss due to voltage drop across the diode. It is clearly preferable to bypass the shaded module, because the increase in output power from operating the string at the higher current level far outweighs the shaded module’s contribution to the total power.

Submodule Shade Effects

What happens if only part of the module is shaded? Can the unshaded sections of that module still generate energy? Manufacturers integrate more than one diode into a module to allow for exactly that. This multiple bypass diode approach divides the module into smaller sections, called cell strings, each with a parallel bypass diode. Integrating multiple bypass diodes allows string current to bypass individual cell strings only, while the rest of the module operates at maximum power.

For a module with three cell strings and three bypass diodes, as shown in Figure 2, shading of just one cell string causes the loss of only about 33% of the module’s power, instead of all its power. Modeling solar designs to the cell-string level can have an appreciable impact on energy production results, and therefore on expected financial returns, in both commercial and residential applications.

Commercial design scenario. Interrow spacing is an important design variable in low-slope commercial roof applications. On the one hand, decreasing the space between rows allows designers to increase array capacity and annual energy production. On the other, self-shading increases as the rows get closer together, which reduces energy yield (kWh/kWp). The aerial view in Figure 3 illustrates these design trade-offs, comparing interrow shading at noon in early December and the overall rooftop power density for a commercial system in California (37.4°N latitude) with a 20° tilt angle. Submodule- or cell-string–level performance modeling allows designers to better account for the impacts of self-shading associated with tight interrow spacing.

As illustrated in Figure 4, submodule performance simulations become increasingly important as designers reduce spacing between rows. Simulations that model each module as an equivalent circuit tend to underestimate annual production compared to cell-string–level simulations. These impacts actually increase as interrow spacing decreases. Though a few percentage points of difference may seem insignificant, those points can translate to a substantial amount of energy and money for large-scale projects.

A submodule-level simulation also enables designers to evaluate how modules with the same power rating but different cell-string or bypass diode configurations perform. While most module manufacturers split modules into three equal cell strings, each with its own bypass diode, others have employed different configurations in an attempt to mitigate interrow shading and maximize performance. Panasonic, for example, uses four bypass diodes in its 96-cell, 330 W VBHN series modules. To accurately compare the energy production of a four-cell string versus a three-cell string product, system designers must use a performance model that defines the exact bypass diode configuration and simulates performance at the cell-string level.

Residential design scenario. Submodule-level simulations, such as those Aurora performs, also allow system designers to assess the impact of new technologies such as cell-string–level optimizers. Maxim Integrated, for example, has partnered with several module manufacturers—including ET Solar, Jinko Solar and Trina Solar—to develop modules with dc power optimizers on every cell string. These cell-string optimizers replace the bypass diodes in conventional PV module designs and allow each cell string to operate at its own maximum power point, with the goal of improving energy harvest in fielded systems. Because the cell-string optimizers operate at a submodule level, an array- or module-level simulation is not granular enough to accurately model their impact on energy production.

As an example, consider the residential design in Figure 5, which utilizes a 6 kW inverter with two MPPT inputs and integrates 28 modules rated at 255 W each. The system has two parallel-connected 11-module strings, shaded by a tree to the southwest of the subarray, on one MPPT input, and a shorter 6-module string, shaded by a chimney, on the second MPPT input. The associated table details the annual energy production and energy yield based on different simulations in Aurora. Rows 1 and 2 in the associated table compare the modeled performance for conventional modules based on module- versus submodule-level simulations; Row 3 describes the simulated results for modules with cell-string–level optimizers based on submodule-level modeling. Because the cell-string optimizers localize the impacts of shading, system-level performance improves significantly. It is impossible to accurately model the performance boost that cell-string optimization offers in this scenario without a simulation platform that can model the impacts of shade and optimization down to the cell-string level.

David Bromberg / Aurora Solar / Palo Alto, CA /

Primary Category: 

Conventional PV modules are monofacial, meaning that their electrical power output is a function of the direct and diffuse radiation captured on the front side of the module only. By contrast, bifacial modules convert light captured on both the front and back sides of the module into electrical power. Bifaciality improves PV system energy capture—dramatically in some cases—and rewrites conventional system design rules in interesting ways.

This article is an introduction to bifacial PV systems. After briefly reviewing the history of bifacial PV cells and providing a high-level overview of bifacial cell technologies, I summarize the potential benefits of bifacial PV modules and systems. I then focus on best practices and applications for designing and deploying systems that integrate bifacial PV modules. Finally, I consider some challenges to adoption and important efforts under way internationally to unlock the full commercial potential of bifacial PV systems.


Research on bifacial PV cells dates back to the dawn of the solar industry, according to Andrés Cuevas’ oft-cited article, “The Early History of Bifacial Solar Cells” (see Resources). Japanese researcher H. Mori proposed a bifacial PV cell design as early as 1960 and had successfully developed a working prototype by 1966. Russian and Spanish researchers proposed uses for bifacial PV cells around the same time. It was the Russians, however, who first deployed bifacial PV modules in the 1970s, as part of their space program. A major milestone occurred in 1980, when Cuevas and some of his colleagues in Spain documented the ability of light-colored surfaces to direct reflected light (albedo) to the back of a bifacial PV cell and increase its power output by 50%.

Due to the high cost of producing bifacial PV cells, the first terrestrial applications for this technology were relatively late to emerge. One of the best-documented early field applications is a north-south–oriented vertical photovoltaic noise barrier that Swiss researchers deployed in 1997 along the A1 motorway in Zurich using 10 kW of bifacial PV modules. The first signs of commercialization, at least in North America, appeared roughly a decade later when Sanyo introduced its first UL-listed HIT Double bifacial PV modules. Though Panasonic, which acquired Sanyo, subsequently discontinued the bifacial product line, as of January 2017, at least eight manufacturers offer bifacial PV modules certified for use in North America (see Table 1).

Cell technology. While bifacial PV cells currently make up an insignificant percentage of worldwide PV cell sales, the technology is in some ways a continuation or logical extension of standard monocrystalline silicon (mc-Si) cell technology. Depending on whether the semiconductor material contains a relative abundance or deficiency of electrons, the industry broadly categorizes mc-Si cells as either n-type or p-type devices, respectively. It is possible to fabricate bifacial cells out of both p-type and n-type wafers, given high-quality silicon material, although the process requires some additional manufacturing steps compared to producing conventional monofacial cells.

In practice, more than 90% of the PV cells sold worldwide are based on a p-type architecture, while the vast majority of the bifacial products in Table 1 are n-type devices. This underscores the fact that many n-type PV cells, which are primarily found in niche high-efficiency modules from companies such as LG, Panasonic and SunPower, are inherently bifacial. (Some people trace the history of bifacial PV cells all the way back to Bell Labs, since its first practical solar cell in 1954 was an n-type device.) P-type devices dominate the market because they are cost-effective to fabricate at scale. While n-type bifacial cells offer the highest efficiency, companies such as SolarWorld are betting that p-type bifacial cells can provide a good balance between performance and cost.

Regardless of the specific cell technology, the rear side of a bifacial PV cell needs to be able to act as a collector, which requires advanced architectures and manufacturing techniques. The authors of the informative Electric Power Research Institute (EPRI) Bifacial Solar Photovoltaic Modules (see Resources) explain: “Today’s crystalline silicon and thin-film monofacial PV cells commonly use a fully metallized backside. This feature involves a moderately thick metal contact for reduced series resistance and is relatively inexpensive to produce. By contrast, bifacial cells incorporate selective-area metallization schemes to allow light between the metallized areas.”

Though thin-film manufacturers are still working out the material science issues necessary for bifacial thin-film modules, many mc-Si manufacturers have successfully produced bifacial cells, which often incorporate thin-film layers, such as the rear passivation layers of amorphous silicon in Figure 1. The next challenge is adapting these technological advances for mass manufacturing. The EPRI report continues: “The lower amount of metal changes how cell performance is optimized, potentially requiring tighter (more expensive) specs on the silicon and thin-film material used and also increasing series resistance concerns. Furthermore, bifacial cells may employ different metals, such as copper and nickel, and/or deposition methods, such as plating or inkjet printing, which, in part, requires different equipment and entails a potentially more complex manufacturing process. Consequently, the backside metal represents a nontrivial impediment to manufacturing bifacial cells with high performance and low cost. This added complexity and cost needs to be offset by the performance gains from increased light collection.”


The rapid growth of the solar industry in recent years has been largely premised on significant up-front cost reductions, especially lower costs for PV modules. Bifacial PV modules run counter to the grain in the market since they are inherently more expensive than conventional monofacial modules. Fabricating bifacial PV cells requires not only high-quality mc-Si wafers, but also anywhere from two to six additional manufacturing steps compared to conventional cells.

The crux of the bifacial value proposition, therefore, is improved production and performance over the life of the system, which is a function of both bifacial energy gains and improved durability. Because bifacial modules offer high conversion efficiencies, they also have the potential to lower BOS costs, which make up an increasing percentage of up-front system costs. The ultimate goal, of course, is a lower levelized cost of energy (LCOE).

Increased energy generation. Unlike PV systems deployed with monofacial modules, bifacial PV systems can convert light that shines off the back of the module into electricity. This additional back-side production increases energy generation over the life of the system. Ongoing research and side-by-side testing suggests that a bifacial PV system could generate 5%–30% more energy than an equivalent monofacial system, depending on how and where you install the modules. Moreover, the manufacturers’ linear performance warranties for bifacial PV modules are some of the best in the industry.

Improved durability. To allow light to shine on the back-side of a bifacial cell, module manufacturers need to use either a UV-resistant transparent backsheet material or an additional layer of solar glass. In most cases, as shown in Table 1, manufacturers have opted for a glass-on-glass package that generally improves field durability as compared to glass-on-film options. Not only is a glass-on-glass package more rigid—which reduces mechanical stress on cells during transportation, handling and installation, or from environmental conditions such as wind or snow—but it is also less permeable to water, which may reduce annual degradation rates. Moreover, many bifacial modules are frameless, and eliminating the aluminum frame effectively reduces opportunities for potential-induced degradation (PID).

Reduced BOS. As prices for modules and interactive inverters have fallen in recent years, BOS costs—specifically, the costs associated with mounting systems—have come to make up an increasing percentage of total PV system costs. An interesting side effect of this trend is that commercializing higher-module efficiencies is beginning to look like one of the best opportunities to squeeze additional value out of PV systems. Higher-efficiency modules not only reduce the area of the mounting system on a per kW basis, but also allow a developer to increase system capacity and energy harvest at a given site with fixed development costs.

Lower LCOE. The LCOE for a power generation asset is found by dividing the total life-cycle costs—both the up-front construction costs and the operational costs over time—by the total lifetime energy production. In the field, bifacial PV modules outperform their nominal power and efficiency ratings, which addresses the energy-generation side of the LCOE calculation. Factoring in the bifacial energy gain, a 19% efficient bifacial 300 W module might harvest energy in a field application equivalent to what a 21% efficient 335 W monofacial module produces. From the manufacturer’s perspective, meanwhile, it is could be more cost-effective to add bifaciality to a 20% efficient mc-Si cell than to mass-produce a monofacial one that is 22% efficient. This balance between performance and cost can make bifaciality an attractive feature for a module manufacturer’s technology roadmap.


Though bifacial PV modules can convert both front- and rear-side irradiance to electrical power, they nevertheless put their best face forward, in the sense that front-side efficiencies are invariably higher than back-side efficiencies, whether due to semiconductor properties or the amount of back contact metallization. The bifacial ratio quantifies the STC-rated power of a bifacial module’s back side in relation to the front-side power. For the products in Table 1, bifacial ratios range between 55% and 95%, which obviously suggests something about the relative energy production for different products in equivalent applications.

Regardless of its specific bifacial ratio value, the field performance of any bifacial PV system is highly dependent on back-side irradiance. Generally speaking, back-side irradiance is light reflected off an adjacent horizontal surface. Therefore, you can optimize bifacial PV systems by following a few simple guidelines: Install bifacial arrays above surfaces that reflect as much light as possible, increase array height or tilt angle to collect more reflected light and avoid shading the back side of the array.

Surface reflectivity. A bifacial PV system will generate more energy when installed over a light-colored rather than a dark-colored surface. This is because the former will reflect more light onto the back of the array, whereas the latter absorbs more of the incident irradiance. Albedo is a dimensionless quantity, usually expressed as a percentage, that describes this ratio between light reflected off a surface and the original incident irradiance. The higher the albedo value, the higher the surface reflectivity.

Table 2 provides representative albedo values for a variety of common ground surface types, as documented in the SolarWorld white paper “How to Maximize Energy Yield with Bifacial Technology” (see Resources). These values suggest that white roofing membranes, which reflect roughly 80% of the incident light when new and unweathered, are an ideal ground cover surface under a bifacial PV array. By contrast, the measured albedo value for raw concrete is only 16%. While the albedo for concrete increases dramatically when it is painted white, SolarWorld’s research indicates that not all light-colored surfaces are created equally. White gravel, for instance, has a relatively low albedo due to an “open-pored structure [that] causes a large amount of light to be lost within the voids.”

While the additional rear-side power output in a bifacial system is clearly proportional to ground surface albedo, the authors of the EPRI article note that this simple relationship “belies the fact that, in practice, energy gain depends on a number of complicated installation-specific factors.” For example, white surfaces reflect light of all colors, whereas other surfaces reflect light preferentially, absorbing some colors and reflecting others. Grass, for instance, absorbs blue and red light and mostly reflects green light. PV cells, meanwhile, vary in their ability to collect and convert different wavelengths of light into electrons.

Height and tilt angle. The closer you install a bifacial array to the ground or roof surface, the more self-shading occurs. Flush mounting, for example, effectively blocks any reflected light from reaching the back of the array. Increasing the height of the array or its tilt angle increases reflected light collection and enhances the bifacial contribution. Generally speaking, the higher you can install a bifacial PV array, the better its bifacial energy gain. However, this does not mean that bifacial modules are suited for carports and awnings only.

SolarWorld simulations suggest that a significant bifacial energy boost is possible with a relatively modest height increase. Not only is the energy boost curve in Figure 2 steepest between 0 and 0.2 meters (7.9 inches), but also the inflection point occurs somewhere around 0.5 meters (19.7 inches), after which point the curve begins to flatten out; the saturation point occurs around 1.0 meter (39.4 inches), meaning that additional energy gains are negligible above this height. These data suggest that bifacial modules are potentially well suited for just about any ground-mounted application, as the leading edge of these arrays is often 18 inches–36 inches above grade.

It is also possible to adapt conventional flat roof– mounting systems for use in bifacial applications. In its bifacial system design guide, for example, Prism Solar recommends a minimum height of just 6 inches above the reflective surface. To facilitate a slight increase in array height in low-slope–roof applications, the company has worked with mounting system manufacturers, most notably Opsun Systems, to develop structural solutions optimized for use with bifacial modules. In addition to a modified ground-mount system, the Bifacial SunGround, Opsun Systems also offers the SunRail Structure Bifacial, a higher-elevation version of its standard commercial rooftop mounting system.

Back-side shading. To optimize bifacial energy gains, system designers also need to avoid shading the back side of the array. Most racking systems have rails that run across the module’s backside, which an opaque white or black film usually covers. These structural components, especially support rails, are potential sources of shade in a bifacial system. As a result, mounting systems optimized for bifacial applications locate mounting rails at the perimeter of the modules, orienting these in parallel with rather than perpendicular to the module frame or the edge of the glass.

Back-side shading is also a concern for bifacial module manufacturers. The junction box on many monofacial modules, for example, is located directly behind one or more PV cells. By contrast, most bifacial modules have a low-profile junction box located at the perimeter of the module to minimize back-side cell shading. Though testing indicates that back-side shading from junction boxes or mounting structures will not damage a bifacial module, it does result in yield losses.


Data from initial test beds and performance simulations—some of which are summarized later in this article—suggest many potential applications for bifacial PV systems. These include most conventional applications such as flat roofs and free fields, where installers deploy monofacial PV modules today, as well as niche applications such as building-integrated PV (BIPV) carports and awnings, where they typically deployed early bifacial modules. Back-side power collection also rewrites the rules that apply to traditional PV system design and performance, which could enable new markets and business models.

Sandia test results. Sandia National Laboratories recently published a report (see Resources) documenting the side-by-side test results for Prism Solar bifacial modules in comparison to reference monofacial modules. Sandia installed modules at the test bed in five orientations over two surfaces at its New Mexico Regional Test Center. Data collected over a 6-month period (between February 15 and August 15, 2016) indicated that the bifacial modules were outproducing the monofacial devices by anywhere from 18% to 136%, depending on the orientation and ground cover. Figure 3 provides the average daily power output curve for each test condition.

The report’s authors draw some interesting conclusions from these data. First, they note that bifacial gains vary throughout the day, depending on the angle of the sun or whether conditions are clear or cloudy. The impacts of sun angle are somewhat intuitive when you consider that the sun is closest to the horizon early in the morning and late in the afternoon, which not only decreases the available incident energy but also increases the amount of reflected light. As a result, the percentage of the instantaneous power output resulting from the bifacial contribution is highest at these times, and the bifacial gains are relatively lower at or around solar noon. The impacts of direct versus diffuse irradiance are similar. During cloudy conditions, the incident energy is relatively low, which increases the percentage of bifacial gain due to reflected light. Under sunny conditions, by comparison, the bifacial contribution is higher in absolute terms (back-side power) but lower in relative terms (percentage of bifacial gain).

The authors also note that bifacial modules are relatively insensitive to changes in array azimuth. As you rotate a bifacial array east or west of true south, the bifacial boost increases, effectively offsetting some of the losses that a monofacial array experiences in non-optimal orientations. As a result, “west-facing bifacial modules tilted at 15° produced a similar amount of energy as south-facing, 15°-tilted bifacial modules and surpassed the energy production of all of the monofacial orientations considered.” Not only did the west-facing, 15°-tilted bifacial array outperform the optimally oriented monofacial arrays, tilted at 15° and 30°, but also the west-facing, vertically oriented (90° tilt) bifacial array “outperformed monofacial modules at any orientation.”

Not surprisingly, the bifacial gains were also greatest in a west-facing, vertically oriented application, which creates an effective collection area for bifacial modules literally double that of monofacial modules. As a result, the bifacial power curve in this application has two peaks, one in the morning and one in the afternoon, whereas the equivalent monofacial power curve has one peak only. An east-west facing array is also effective at shifting solar power production later into the afternoon, when electric demand is often greatest. This configuration is likely well suited to take advantage of certain time-of-use rate structures and could provide additional value to utility operators. (The downside of an east-west vertical orientation is its high susceptibility to horizon shading losses.)


On the one hand, bifacial PV arrays require specialized modules and mounting systems, as compared to conventional PV systems, which invariably increases up-front system costs. On the other, side-by-side field tests, such as those Sandia conducted, clearly reveal a bifacial energy boost. It is entirely possible, therefore, that bifacial PV systems could provide the best value, in terms of LCOE or return on investment, in certain applications. Making that case and taking it to investors, however, remains a barrier to widespread market adoption.

Macroeconomic conditions. In the short term, the low costs for conventional monofacial PV modules represent one of the biggest challenges to the commercialization of bifacial products. Module prices are at an all-time low, largely due to downward price pressure caused by global oversupply. As a result, many manufacturers are operating at low to negative operating margins, which hinders investment in new manufacturing tools and product lines.

The authors of the EPRI report note: “It is financially difficult to sustainably grow manufacturing capacity of existing products, let alone a more innovative concept such as bifacial PV modules. This issue is exacerbated by the more expensive manufacturing tooling and processes required to produce bifacial modules today. The high capital expense and low returns on cell and module production is a bottleneck for adoption by manufacturers.”

Module nameplate power rating. Today, STC ratings for bifacial modules are based on front-side performance only, which obviously fails to capture the effects of bifaciality. To reflect the fact that bifacial electrical properties vary in proportion to back-side irradiance, manufacturers will also provide some version of Table 3, detailing performance characteristics at different levels of bifacial gain. The manufacturers leave it to the designer to decide how to apply these data. Since back-side irradiance has no impact on open-circuit voltage and has a negligible impact on voltage at maximum power, the real design consideration is the potential for higher currents.

Industry stakeholders around the world are actively developing a consensus on standard testing procedures for rating bifacial PV modules that the International Electrotechnical Commission (IEC) will eventually publish as IEC 60904-1-2. Researchers at the National Renewable Energy Laboratory (NREL), for example, have proposed flash-testing both sides of bifacial PV modules and using these flash test data to derive a compensated short-circuit current value. Additional indoor and outdoor testing is under way at NREL and Sandia to determine the accuracy of this approach.

Production modeling. Perhaps more important, the industry needs bankable methodologies for modeling bifacial system energy production in the field, a requirement complicated by the fact that field conditions have an inordinate impact on bifacial system performance. Performance models need to account for rear-side shade effects associated with mounting structures and adjacent rows of modules, which will vary considerably both over the course of a day and from one application to the next. Ground-surface albedo is another consideration. This can change seasonally, when snow covers grass or dirt, or over time, due to soiling effects. The albedo for a white roof membrane, for example, might be 80% when the membrane is newly installed but only 50% after it has spent a few years in the field. Research also indicates that rear-side irradiance is also nonuniform, meaning that it varies across the back of the array.

Because of all these factors, field test results are essential for developing and verifying the accuracy of bifacial performance models. Unfortunately, many laboratory test beds consist of only a few rows of modules, which are often spaced out to minimize self-shading. These results tend to overestimate performance in larger systems, especially in applications where rows are more tightly packed together. This creates a chicken-and-egg scenario. To optimize design variables, such as ground-cover or dc-to-ac ratios, you need a sophisticated production-modeling tool. But to develop an accurate production-modeling tool, you need field data—and the more of it, the better.


David Brearley / SolarPro / Ashland, OR /


Cuevas, Andrés, “The Early History of Bifacial Solar Cells,” 20th European Photovoltaic Solar Energy Conference (EU PVSEC) Proceedings, 2005

Electric Power Research Institute (EPRI), Bifacial Solar Photovoltaic Modules, September 2016

Lave, Matthew, et al., “Performance Results for the Prism Solar Installation at the New Mexico Regional Test Center: Field Data from February 15 to August 15, 2016,” Sandia National Laboratories, SAND2016-9253

SolarWorld, “How to Maximize Energy Yield with Bifacial Technology,” white paper, 2016


LG / 855.854.7652 /

Lumos Solar / 877.301.3582 /

Mission Solar Energy / 210.531.8600 /

Opsun Systems / 581.981.9996 /

Prism Solar Technologies / 845.883.4200 /

Silfab Solar / 905.255.2501 /

SolarWorld USA / 503.844.3400 /

Sunpreme / 866.245.1110 /

Yingli Solar / 86.312.8929.800 /

Primary Category: 

Solar carports and canopies have proven to be a successful and marketable approach to PV system siting and deployment. In addition to generating power, these structures add significant value to frequently underutilized parking areas, providing shade during the sunny months and protection from precipitation during the wet ones. This article provides system designers, engineers, and procurement and sales teams with overviews of 17 companies that offer solar carports, canopies or awnings in their product and service portfolios.

Many of the companies profiled have long business histories working with steel structures. As the solar industry gained momentum and entered new geographical markets, these vendors optimized their designs to integrate with PV arrays. As evidenced by the substantial number of companies profiled, a competitive market has developed for solar carports and canopies, driving the designers and fabricators of these structures to advance their designs. Today, project developers, integrators and EPC firms have an impressive range of solutions in this product class with a high level of optimization and refinement.

Absolute Steel

Headquarters: Tempe, Arizona
Contact: • 877.833.3237

Arizona Storage, a privately owned company that also does business under the Absolute Steel brand name, was founded in 1999. At its production facilities on company-owned properties in Arizona and Texas, Absolute Steel fabricates a selection of steel-frame solar-ready carport systems that range from small canopies with two parking spaces to large carport designs suitable for commercial applications. Its showroom in the metropolitan Phoenix area displays its steel buildings, carport systems, barns and storage sheds. Absolute Steel supports customers with site evaluation, structural engineering, on-site management and training, and domestic and international shipping services.

Baja Construction 

Headquarters: Martinez, California
Contact: • 800.366.9600

In operation since 1981, Baja Construction is a privately owned and vertically integrated design and construction firm with an in-house engineering department as well as its own construction crews. The company specializes in prefabricated, pre-engineered, high-tensile light-gauge steel structures that include solar carports, ground mounts and electric vehicle charging stations, as well as nonsolar carports, and RV, boat and self-storage facilities. Its engineering services and custom designs enable Baja to develop structures that meet site-specific wind load, snow load and geotechnical requirements. The company operates regional offices in Fontina, California; Dallas; Holbrook, New York; Las Vegas; and Phoenix.

Baja’s product line includes four standard configurations. Designed to cover a single row of parking spaces, its Braced Single Post carport includes flat, upslope and downslope options. Full Cantilever offers the same slope configurations, with the carport posts located along one of the structure’s eves. Full Cantilever T covers two rows of parking spaces, with posts located along the structure’s centerline between rows, and is available in flat and sloped array options. Finally, Single Post Back to Back couples two single-post configurations installed adjacent to each other to create a common flat or sloped array surface that covers two rows of parking spaces. All four of these configurations allow for customer-specified design requirements such as eve height, array tilt angle and purlin spacing based on module dimensions, and facilitate both portrait and landscape module layouts.

Carport Structures

Headquarters: Oxford, Michigan
Contact: • 800.442.4435

Carport Structures has been providing covered parking solutions and structural steel canopy products for commercial applications for more than 40 years. The privately owned and operated fabrication and construction company specializes in the design, manufacturing and installation of structural steel products such as multi-housing carports, walkway canopies and covers, shade structures, park shelters and RV carports.

In recent years it has developed solutions for commercial and utility PV applications, offering a range of services that include project quoting and presentation, site analysis, regional building code review and analysis, structural design, foundation design and layout, project management, foundation excavation and construction, steel structure erection and field fabrication, field painting, and PV racking and module installation. In addition to creating custom designs, it offers 11 standard carport products including single-column cantilever configurations, two-column configurations and louvered configurations that set each individual module row at a customer-specified tilt angle. All carport solutions are available for single-, double- and multiple-lane elevated structures.

Envision Solar International

Headquarters: San Diego
Contact: • 866.746.0514

Envision Solar International is a San Diego–based technology company with solar solutions for electric vehicle charging, media and branding, and energy security systems. Founded in 2006, the company went public in 2010 (ticker: EVSI). Envision Solar offers two specialty solar canopy lines: the EV ARC and the Solar Tree. Designed for stand-alone PV-powered electric vehicle charging, the EV ARC line includes several models, such as the EV ARC 3, which has a 3.4 kW canopy-mounted array coupled with 22.5 kWh of energy storage, and the EV ARC 4, which has a 4.1 kW array and 30 kWh of energy storage. Both models are equipped with dc chargers for plug-and-play electric vehicle charging. The EV ARC Digital model combines the EV ARC 4 with an outdoor-rated screen for advertising and branding. In addition, Envision Solar developed the EV ARC Bike/Moto, for electric bike and motorcycle charging. Like the EV ARC products, the Solar Tree line handles stand-alone power generation and vehicle charging. The Solar Tree DCFC (DC Fast Charger) is a compelling option for sites where customers desire fast dc charging for electric vehicles but utility power is not present or is expensive to access.

Florian Solar

Headquarters: Georgetown, South Carolina
Contact: • 800.356.7426

Florian Solar is a designer and manufacturer of integrated solar structures including sunrooms, greenhouses, canopies, awnings, skylights, and residential and small-scale commercial carports. The third-generation privately owned company was founded in 1947. It partnered with Sanyo, an early manufacturer of glass-on-glass bifacial modules, to develop its first line of solar structures in 2007. Florian’s product line features designs with a high level of aesthetic appeal that fill a niche market in the solar industry; for example, its sunroom and awning systems can completely conceal module interconnect and homerun conductors. While Florian can integrate most module types into its integrated structures based on customer preference, it frequently utilizes bifacial modules from Prism Solar Technologies and Sunpreme. Its structural designs do not shade the back side of installed modules, enabling the back-side generation potential of these products to be harnessed.

Lumos Solar

Headquarters: Boulder, Colorado
Contact: • 303.449.2394

Established in 2006, Lumos Solar is a privately held company that designs and manufactures two lines of frameless, glass-on-glass modules, as well as integrated rail systems and wireways that conceal conductors, protecting them from damage while improving the visual aesthetics of the array in the built environment. Integrators commonly deploy Lumos systems in solar awning, canopy and carport systems. The Lumos in-house design and engineering team assists customers with conceptual renderings, PE wet-stamped engineering drawings and packages to streamline project permitting.

Lumos Solar developed the LSX and GSX module and rail systems for integration with elevated solar structures, both of which integrate with most third-party solar carport and canopy structural array support systems. The LSX system includes frameless, glass-on-glass 60-cell modules rated at 265 W, 270 W and 275 W at standard test conditions. These modules integrate with the LSX Rail 1.1 system, which includes an integrated wireway. The recently launched GSX Bifi system uses 60-cell bifacial GSX modules rated at 300 W STC for front-side power production and a combined front-side and back-side rating of 330 W per IEC bifacial measurement standard (IEC 60904-1-2 TS). Its mounting and racking system conceals the module junction box and creates a waterproof array surface.

M Bar C Construction

Headquarters: San Marcos, California
Contact: • 760.744.4131

MBar C Construction is a family-owned and -operated manufacturing and construction firm. The company was founded as M Bar C Carports in 1975 and began developing and installing carports for solar applications in 1997. In 2005, it reestablished itself as M Bar C Construction. The company specializes in both light- and heavy-gauge steel prefabricated and custom parking lot and structure canopies for large-scale projects. It incorporates elevated steel structure design, manufacturing and installation, as well as commercial and industrial electrical services through its M Bar C Electric division. In addition to manufacturing structural steel elements for carports and canopies, M Bar C Construction has developed the SOLAR F.I.T. (Fast Install Track) SYSTEM, which uses a channel system rather than top-mount clamps to secure modules to a substructure. This approach allows installers to mount modules from below and eliminates some of the OSHA safety concerns associated with typical top-mount systems. M Bar C Construction primarily serves the Western US, including Arizona, California, Colorado, Hawaii, Nevada and Oregon. Approximately 90% of its installations are design-and-build projects.

Orion Solar Racking

Headquarters: Commerce, California
Contact: • 310.409.4616

Founded in 2009, the privately owned Orion Solar Racking develops and manufactures solar-mounting solutions for residential, commercial, industrial, agricultural and utility-scale projects. Orion Solar offers three standard product models for carport systems: KRONOS, LETO and TITAN. The KRONOS model is primarily intended for single-parking-space residential systems and is available with clearance heights from 8 feet, 5 inches, to 11 feet, 5 inches. Custom colors are available. Its galvanized steel, curved single-post design supports six or eight modules in portrait orientation at tilt angles of 0°, 5° or 10°. The LETO carport system is a steel double-column single-cantilever carport designed to span two parking spots for a total of 18 feet. Intended for commercial applications, LETO structures allow side-by-side installation to shade larger areas. The system’s columns and beams are available with galvanized or primed finishes. Orion Solar’s TITAN carport system is a double-column, double-cantilever tee-style carport designed to cover four parking spots in a two-by-two parking configuration. The LETO and TITAN systems are available with an array tilt angle of 0°, 5° or 10° and feature purlins that allow slide-in module mounting. Options include area lighting under the canopy and electric vehicle charging stations. Orion Solar also offers custom-designed solar carport solutions.

Quest Renewables

Headquarters: Atlanta
Contact: • 404.536.5787

Quest Renewables is a privately owned company launched in 2014 to commercialize solar racking products developed by the Georgia Tech Research Institute under the US Department of Energy’s SunShot Initiative. The company’s QuadPod Solar Canopy uses steel top and bottom chords connected with a series of tubular web struts to create 3-D trusses, which support elevated-structure solar arrays such as carports and canopies. This design can handle 60-foot spans between piers, 30-foot cantilevers and array capacities of 30 kW per pier.

The QuadPod’s modular design streamlines shipping costs and provides flexibility on-site. Installers assemble the truss components using bolted hardware, and they then secure and prewire modules on-site at ground level. They use a crane to lift the completed assemblies atop the piers’ tubular support columns. This pick-and-place approach minimizes overhead work and improves jobsite safety. Quest Renewables offers an east-west configuration of its QuadPod system that enables a 15% higher power density than south-facing QuadPod canopies provide and that allows integrators to optimize inverter capacities when sizing for east-west array production curves.

Powers Solar Frames

Headquarters: Phoenix
Contact: • 888.525.0180

Powers Solar Frames is a division of privately owned Powers Steel and Wire, a manufacturer of steel structures, lintels, masonry products, rebar and solar racking systems. The solar product line includes driven-pile and ballasted racking systems for commercial, industrial and utility-scale projects, as well as solar carport frames. Powers Solar Frames’ carports use galvanized structural elements (columns, rafters and purlins) that do not require on-site painting. In addition, all structural members have bolted connections that eliminate field welding and weld inspections.

Power Solar Frames offers two carport designs, its semi-cantilever box-beam model and its tee box-beam model. Both systems use 10-gauge 16-inch-by-8-inch galvanized structural members for the carport’s columns and rafters. The tee box-beam model’s rafter can span up to 39 feet. Both carport models permit modification for tilt angle, clearance height and site-specific requirements such as snow load, wind load, and geotechnical and seismic requirements. Power Solar Frames’ carport structures feature its patented steel Super Purlin. The purlin’s profile creates a channel that allows installers to slide in modules from the carport system’s gable ends. This approach eliminates top-down module-mounting hardware and fall hazards associated with working above the array plane. Each module requires four UL 2703–certified gator clamps that install from the underside of the array to secure the module to the adjacent purlin.

RBI Solar

Headquarters: Cincinnati
Contact: • 513.242.2051

RBI Solar designs, engineers, manufactures and installs solar mounting systems for commercial and utility-scale solar projects. The privately owned company operates US offices in Atlanta; Temecula, California; and Washington, North Carolina. It completed two notable acquisitions in 2014, including PV carport manufacturer and installer ProtekPark Solar, and Renusol GmbH and its subsidiary, Renusol America. RBI Solar’s services include design, engineering drawings for all 50 states, project management and nationwide installation.

RBI Solar offers pre-engineered solar carport structures, including single-slope, gable, inverted and full-coverage designs. It typically utilizes the two-slope gable configuration for north-south orientation with panels sloping 5° on the east and west array faces. This inverted design provides increased clearance at the structure’s eaves while promoting water and snow movement toward the center column row of the structure. RBI Solar also offers a full-coverage design suitable for protecting large parking areas, including the drive aisles between parking rows. Typical applications for the full-coverage carport configuration are parking garages, drive-throughs, and bus or truck loading and unloading zones. RBI Solar carport systems do not require field welding, drilling or other on-site fabrication. The company offers customized designs as well as numerous options including galvanized and epoxy-coated finishes.


Headquarters: Shelby, North Carolina
Contact: • 888.608.0234

Schletter GmbH has a 40-year history in the design and manufacture of steel and aluminum products. The privately owned company founded its US subsidiary in 2008 with the launch of a sales and manufacturing facility in Tucson, Arizona. Its solar product portfolio includes mounting structures for carports, roofs and ground-mounted PV applications in the utility, commercial, industrial and residential markets.

Schletter’s Park@Sol carport line includes three standard configurations that accommodate single and double rows of parking. Its carport structures do not require on-site welding or cutting. Multiple foundation options are available, such as cast-in-place concrete ballasts, concrete pillars and micropiles. The micropile foundation, which allows a streamlined foundation design, uses a hollow metal rod that the construction team installs to an engineered depth to minimize concrete requirements while meeting high wind- and snow-load requirements. Schletter has an in-house staff of engineers and geotechnicians to assist with site-specific carport system engineering. It offers multiple options for its Park@Sol structures, including cable management, subdecking, inverter mounts, custom designs and color options, and branding solutions.


US Headquarters: Denver
Contact: • 303.522.3974

With its global headquarters in Hamburg, Germany, privately owned S:FLEX GmbH was founded in 2009. S:FLEX’s product lineup includes solutions for pitched and low-slope rooftops, ground-mounted systems and solar carport applications. Its standard carport products include full cantilever, partial cantilever, and tee upslope and downslope configurations, as well as an inverted configuration that channels precipitation runoff to the structure’s center. S:FLEX carport systems provide several module-row configuration options and are compatible with both framed and frameless modules mounted in portrait or landscape orientation. Standard array tilt angles of up to 15° are available

While S:FLEX engineers its column spacing and spans based on site-specific wind, snow and seismic load requirements, designs typically space columns at 27 feet on center and place them between every three parking bays, creating individual parking spaces that are 9 feet wide. Its carports are compatible with multiple foundation types, including spread footings and foundations with embedded helical piers. Carport options include integrated electrical grounding and industrial painting of steel structural components. S:FLEX supports carport projects with project-specific design and engineering, as well as installation support.

Skyline Solar

Headquarters: Gilbert, Arizona
Contact: • 480.926.0122

Skyline Solar is a division of Gilbert, Arizona–based Skyline Steel. Founded in 1983, Skyline Steel designs, manufactures and installs commercial covered parking structures. It recognized the added value that solar offered many of its carport customers and entered the solar industry in 2002, establishing Skyline Solar in 2009.

Skyline Solar offers products for solar applications including carports; large-area canopies for parking garages; bus and truck parking; RV, boat and self-storage facilities; electric vehicle charging stations; and commercial and utility-scale low-slope–roof and ground-mount structures. A design-build firm, Skyline Solar typically provides products and services to integrators, developers and EPC firms that are responsible for the installation and commissioning of solar power systems. Its services include project estimating and management, conceptual project renderings, structural plan sets and certifications in all 50 states, foundations, steel construction and erection, and PV module installation.

Skyline Solar offers a wide range of standard solar carport and canopy models as well as custom designs. Its prefabricated one-column SkyTree shade structure, supporting array capacities of up to 18 kW at a tilt angle of 5° or 10°, is well suited for small covered-parking installations. For large-scale projects, Skyline Solar offers single- and double-cantilever tee designs that support modules at tilt angles of 5°, 10° or 15° in portrait or landscape orientation. Its dual- and multiple-post solar canopies are intended for large parking areas, garage tops, school playgrounds and bus parking lots, and they allow module-mounting options including flat canopy, 5° canopy or louvered module installations at tilt angles of 5°, 10° or 15°. Skyline Solar also offers fastener solutions such as its SkyBite clip (ETL certified to UL 467), which permits installers to secure and electrically bond modules to the carport or canopy structure’s purlins from underneath the array.

Solar Carports

Headquarters: Sarasota, Florida
Contact: • 941.702.2342

With manufacturing facilities in California and Virginia, Solar Carports specializes in the design and installation of structural canopies to support solar power systems. It offers several pre-engineered designs as well as custom carport and canopy designs. Standard models include partial cantilever, full cantilever and tee upslope and downslope configurations, as well as inverted configurations. Options include galvanized and painted finishes, watertight canopies, gutters, downspouts, and LED canopy under lighting. Solar Carports’ affiliate, Sarasota-headquartered Region Solar, provides full EPC and project management services for installations deploying Solar Carport’s structures.

Structural Solar

Headquarters: Chicago
Contact: • 708.275.9030

Structural Solar provides solar carport and canopy design-build and contract manufacturing services to solar developers, integrators and EPCs based on site-specific and project-specific requirements. Its services range from solar structure design and engineering to fully manufactured and installed structural systems in locations nationwide, including Hawaii and Puerto Rico. In addition to providing carport and canopy designs, Structural Solar offers waterproof structures for frameless glass-on-glass bifacial PV module installations.


Headquarters: San Jose, California
Contact: • 800.786.7693

Publicly held SunPower designs, manufactures and deploys high-efficiency PV modules and systems worldwide for residential, commercial and utility-scale projects. Founded in 1985, SunPower announced its initial public stock offering in 2005 (ticker: SPWR). In 2015, SunPower acquired Solaire Generation, a well-established solar carport and canopy design, fabrication and installation firm founded in 2008.

Solaire by SunPower’s product line includes patented solutions for large-scale parking lot and garage-top applications. Its carport configurations include single-column, single-cantilever and double-cantilever tee designs on a single incline; dual-incline inverted designs; and dual-column long-span designs. For example, its Long Span 360 product covers two parallel parking rows and an internal drive aisle with one contiguous PV-covered canopy that has an array inclination angle of 1°–10°. Another example is its 360 D model, which has a dual-incline configuration that safely directs snow and ice to the center of the structure. It features a standard minimum drive aisle clearance of 13 feet, 6 inches, and is available in widths of 34 feet to 41 feet, column-to-column spacing of 18 feet to 32 feet and inclination angles of 1° to 15°.

In 2015, SunPower launched its highly integrated Helix PV system platform for commercial and industrial low-slope rooftop, carport and tracked PV systems. The system is standardized but configurable. It incorporates five major value-engineered component groups: modules, mounting hardware, cable management, power stations and energy analytics. Several configurations of the Helix Carport Structure are available, and all feature the Helix platform’s integrated approach. Components and features include high-efficiency SunPower panels, a mechanical mounting and electrical system, a column-mounted plug-and-play inverter power station, SunPower EnergyLink Monitoring hardware and software, and LED lighting. Design options include painted columns and beams, snow guards, and decking and branding solutions.

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A short-circuit fault, which is an abnormal condition that occurs when current bypasses the normal load due to unintentional contact either between phases or to ground, is possible in any electrical system. PV power systems are somewhat unusual in that the PV source itself is current limited. However, the potential short-circuit current increases dramatically when you connect a PV system to the grid. In the event of a short circuit in an interactive PV system, circuits designed for 10s or 100s of amps of current may suddenly carry fault currents on the order of 10,000 or 100,000 amps.

If you do not deploy electrical systems with the available fault current in mind, a short-circuit fault could result in a catastrophic explosion or electrical fire. Overcurrent protection devices (OCPDs), of course, are the first line of defense against short-circuit faults. NEC Section 110.10 states: “The overcurrent protection devices, the total impedance, the short-circuit current rating and other characteristics of the circuit to be protected shall be coordinated to permit the circuit protective devices used to clear a fault to do so without extensive damage to the electrical equipment of the circuit.”

Since the 2011 Code cycle, Section 110.24 has required field markings on service equipment that identify the available fault current in multifamily, commercial and industrial applications. NEC 2017 takes this a step further: “The [available fault current] calculation shall be documented and made available to those authorized to design, install, inspect, or operate the system.” To verify that electrical system designers have selected appropriate OCPDs, it is therefore increasingly common for AHJs to require that PV system integrators document both the available fault current and the ampere interrupting capacity of OCPDs in their plan sets.

Available Fault Current

The available fault current is the highest electrical current that can exist in a particular electrical system under short-circuit conditions. The two potential sources of fault current in interactive PV power systems are the inverter and the utility. From a system design point of view, the available fault current from the utility is what matters.

Like the PV power source itself, an interactive inverter is a current-limited device. According to the National Renewable Energy Laboratory (NREL) technical report, “Understanding Fault Characteristics of Inverter-Based Distributed Energy Resources,” independent testing conducted at NREL suggests that “inverters designed to meet IEEE 1547 and UL 1741 produce fault currents anywhere between 2 to 5 times the rated current for 1 to 4.25 milliseconds.” The authors explain: “Inverters do not have a rotating mass component; therefore, they do not develop inertia to carry fault current based on an electromagnetic characteristic.” In effect, this means that fault current from an interactive inverter is insufficient to open OCPDs.

The utility, by comparison, contributes sufficient fault current to not only open OCPDs but also potentially damage electrical equipment. Therefore, one of the first steps in designing an interactive PV system is to determine the available fault current from the utility, as this value will influence, if not drive, equipment selection. This value is primarily a function of the utility transformer—its capacity (kVA), voltage and impedance—that serves the premises wiring.

For existing electrical services, the easiest way to determine the available fault-current value at the transformer or main service is to contact the utility and request this value. Before doing so, be prepared to provide utility representatives with any relevant information, including site address, transformer location and number (if available), distance from transformer to main service, main service size and so forth. In some cases, you can find the available fault current noted on the electrical plans. If new construction plans do not identify this value, contact the project’s electrical engineer of record.

Note that as you get farther away from the utility transformer, the available fault current decreases in proportion to the impedance of the conductors, as well as on the inverter side of a premises-sited transformer. If, for example, you have a step-down transformer between 3-phase 480 Vac inverters and 3-phase 208 Vac premises wiring, then the available fault current invariably will be lower at the inverter OCPDs than at the service point. In this scenario, you can find the available fault current at the inverter output by dividing the full load current on the PV side of the transformer by its impedance, as identified on the equipment nameplate. Assuming you were using a 3-phase 45 kVA transformer with 5% impedance, you would calculate the available fault current (AFC) thus:

AFC = (45,000 VA ÷ (480 Vac x 1.732)) ÷ 0.05 = 1,083 A

Though the effect of conductor impedance is relatively small compared to the standard interrupt ratings, this could make a difference in circumstances that involve long conductor runs, such as an inverter accumulation panel located a good distance away from the main service. In such a scenario, it might make sense to calculate the available fault current at the subpanel, factoring in the effect of conductor impedance, rather than using the value at the main service panel. While calculating fault current after a length of conductor is beyond the scope of this article, Thomas Domitrovich details the process in the IAEI magazine article “Calculating Short-Circuit Current” (May/June 2015).

Ampere Interrupting Capacity

Once you determine the available fault current, you can select appropriately rated circuit breakers or fuses. There are two basic short-circuit protection systems: fully rated systems, which you must selectively coordinate in certain circumstances (see “Selective Coordination of OCPDs,” p. 16), and series-rated systems. As long as you use a listed circuit breaker (UL 489) or fuse (UL 248) in accordance with its ampere interrupting capacity (AIC) and voltage rating or in accordance with its listing as part of a series-connected system, a Nationally Recognized Testing Laboratory (NRTL) has verified its ability to clear a fault without extensive damage to the equipment or electrical system.

Fully rated system. Designing and deploying a fully rated system is relatively straightforward. Listed OCPDs are certified to and marked with an AIC, which identifies the maximum available fault current the device is rated to withstand on its own. These AIC ratings step up in standard increments, such as 10K, 18K, 22K, 25K, 35K, 42K, 65K, 100K and 200K. Listed panelboards, meanwhile, are marked with a short-circuit current rating (SCCR), which is the maximum current the component or assembly can withstand.

In a fully rated system, each OCPD device has an AIC rating that is greater than or equal to the available fault current. Moreover, the piece of equipment in the assembly with the lowest interrupt rating determines the full rating for a panelboard with circuit breakers installed. As an example, the equipment configuration in Figure 1 would have a full rating of 22K amperes—even though the panelboard and main breaker are rated for 65K amperes—as determined by the lowest-rated piece of equipment or OCPD, which in this instance is a branch circuit breaker.

You must design an electrical system with a single OCPD as a fully rated system. If you are designing an electrical system with multiple OCPDs, however, a series-rated system may provide the best value, which is an important consideration for your customers.

Series-rated system. The NEC allows the available short-circuit fault current to exceed the AIC rating of an OCPD under certain circumstances, as detailed in 240.86, Series Ratings. As described in the NEC Handbook, a series-rated system is “a combination of circuit breakers or fuses and circuit breakers that can be applied at available short-circuit levels above the interrupt rating on the load-side circuit breakers but not above the main or line-side device.” This arrangement is allowed for tested combinations of equipment [240.86(B)] or under engineering supervision in existing installations [240.86(A)]; it is not allowed with certain motor-load levels or configurations [240.86(C)].

The most common way to design and deploy a series-rated short-circuit protection system is to use tested equipment combinations, which are combinations of OCPDs that have passed NRTL product safety and certification tests as an assembly. In a series-rated system, only the first OCPD needs to be AIC rated for the full available fault current. Downstream series-connected devices may have a lower AIC rating, provided that an NRTL has shown that the series-connected assembly works together to clear a fault and protect the electrical equipment from damage. If the main and branch circuit breakers in Figure 1 were part of a listed series-rated combination, then the assembly would be series rated for 65K amperes of fault current, as determined by the main breaker AIC rating and panelboard SCCR.

When using series-rated equipment, you must do so in a manner consistent with the product listing and the manufacturer’s instructions. The first step is to get your hands on the series-rating tables for equipment you would like to use. These tables are readily available online. UL maintains these data in tabular form, organized by manufacturer, and most manufacturers also publish their own tables, which must comply with UL standards. The UL or the equipment manufacturer may organize and present these data in a number of ways: by service voltage, by type of breaker or fuse, by equipment combination (breaker-breaker, fuse-breaker, triple-series rating) and so forth. Regardless of the method of data organization, you basically need to find the series combination that matches your design voltage, available fault current and OCPD capacity. The following example illustrates this process for a breaker-breaker combination.

Example of a tested series configuration: This scenario assumes an available fault current of 28,000 amperes at 480 Vac. If you would like to use a 3-phase 250 A Eaton panelboard, subject to the series equipment ratings in Table 1, then you need to look at the 35 kA column and the 250 A main breaker row to meet or exceed the available fault current at the desired capacity level. According to the highlighted cell, you may use a JD- or JDB-type main breaker in series with GHB-type branch circuit breakers. However, this series rating only applies if all the branch circuit breakers in the panelboard are rated between 15 A and 50 A. To accommodate a GHB-type branch circuit breaker rated for more than 50 A, you would need to step up to the 65K A column, which calls for a HJD-type main breaker.

In existing installations, the Code also allows a licensed professional engineer (PE) to select series-rated devices. In these calculated applications, the PE must evaluate the time-current curves for the OCPDs and ensure that the downstream circuit breakers will remain passive (closed) when the upstream device clears the available fault current. In addition to performing manual calculations, a PE can also use specialized software tools as a means of selecting appropriate devices.

Note that product safety standards require specific markings for panelboards and switchboards that a NRTL has investigated and approved for use in a series-rated system. These markings identify allowable combinations of integral and remote OCPDs, which you must observe to maintain the panelboard’s marked SCCR. Furthermore, NEC Section 110.22 includes identification requirements for equipment enclosures with series-rated devices. Installers must field-identify these labels with the effective series-connected protection rating, as directed by a PE or the equipment manufacturer. To maintain this level of protection, the label must also state that identified replacement components are required.

Ben Bachelder / Sun Light & Power / Berkeley, CA /

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

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

POC Options

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

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

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

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

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

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

Load-Side Connections

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

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

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

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

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

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

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

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

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



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

Busbar ≥ Load OCPDs + Inverter OCPDs [3]

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



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

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

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



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

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

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

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

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

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

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

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

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

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

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

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

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

Load-Side Breaker ≤ Feeder Ampacity [5b]

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

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

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

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

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

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

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

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

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

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

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

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

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

Supply-Side Connections

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

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

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

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

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

Connections to Other Equipment

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

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

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

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

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

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

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

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

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


Jason Fisher / Solar City / Charlottesville, VA /

Primary Category: 

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

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


Joe Schwartz / SolarPro  / Ashland, OR /


ABB / 877.261.1374 /

Chint Power Systems / 855.584.7168 /

Delta / 510.668.5100 /

Fronius USA / 877.376.6487 /

Ginlong Solis / 866.438.8408 /

Growatt / 818.800.9177 /

HiQ Solar / 408.970.9580 /

Huawei / 214.919.6000 /

Ingeteam / 408.524.2929 /

KACO new energy / 415.931.2046 /

Pika Energy / 207.887.9105 /

Schneider Electric / 888.778.2733 /

SMA America / 916.625.0870 /

SolarEdge Technologies / 877.360.5292 /

Sungrow USA / 510.656.1259 /

Yaskawa–Solectria Solar / 978.683.9700 /

Primary Category: 

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.


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.”


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 /


GTM Research, 1,500-Volt PV Systems and Components 2016–2020: Costs, Vendors, and Forecasts, January 2016,

Kellner, Tomas, “Something New under the Sun: GE’s Industrial-Grade Inverter Takes Solar Power to a New High,” GE Reports, September 2015,

Morjaria, Mahesh, et al., “The Next-Generation Utility-Scale PV plant,” PV-Tech Power, Feb. 2015 ,


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