Products & Equipment : Monitoring

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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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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 /

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

Modeling, Measurement and Testing

Aurora Solar - Booth WSUA12

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

Curb - Booth W902

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

Folsom Labs - Booth 3053

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

Seaward Solar - Booth W824

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


LG Solar - Booth 1447

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

SolarWorld - Booth 911

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

Sunpreme - Booth 2125

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

Ten K Solar - Booth 759

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

Power Electronics

Delta - Booth 2259

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

OutBack Power - Booth 2825

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

SMA America - Booth 959

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

Trackers, Racking and Mounting

Array Technologies - Booth 2805

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

Beamreach Solar - Booth 2941

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

SunLink - Booth 2037

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

Conductor Aggregation and Management

CAB Solar Booth 311

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

HellermannTyton - Booth 625

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

SolarBOS - Booth 935

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

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The following content is from a recent thread on SolarPro’s technical discussion forum. It is a response to a QA article published in the August/September 2014 issue of SolarPro. Visit to join the conversation.

Original post from john.ciempa: Many of the questions raised in the “SCADA Versus Web-Based Monitoring” article are good to ask while evaluating your monitoring and control provider. However, many of the generalizations were not well explored or explained. Supervisory control and data acquisition (SCADA) is a growing trend in the ever-evolving and fast-moving PV industry. Many monitoring providers are working with utilities, EPCs and owner/operators to define and meet changing needs and to continue to set the bar for industry standards in reporting and monitoring. Below are comments from Draker’s ( applications engineering team related to generalizations made in the article. These comments are organized based on the themes explored in the original publication.

Differences between SCADA and web-based monitoring. As the article highlights, the traditional difference between SCADA and cloud-based monitoring DAS systems relates to the supervisory control capabilities (often remote via the Internet) of multiple devices on a project site. However, this scenario is quickly changing, since many monitoring providers have evolved and offer supervisory control as part of their product offering. In fact, of the 64 web-monitoring DAS companies interviewed for the Greentech Media report, “Global PV Monitoring: Technologies, Markets and Leading Players, 2014–2018,” 40 offer SCADA solutions. Many of the companies, including Draker, incorporate and deploy industry-proven products from companies like Schweitzer Engineering Laboratories to meet supervisory control requirements as part of their product offering.

The author stated: “Commercial plant operation requires such a high level of reliability that a firmware-based device—such as a programmable logic controller (PLC) or a similar type of smart relay—is necessary for plant control.” The statement implies that web-based monitoring solutions are not as reliable. This is inaccurate: most PV DAS providers, including Draker, utilize highly reliable firmware-based devices for standard data collection and deploy PLCs for sites requiring the more robust operational functionality of a full SCADA solution.

The article describes web-based monitoring solutions as license based.  This is true; however, the article does not do a good job of communicating the details on how a SCADA solution handles communication, data storage, maintenance, and other associated factors and costs. An article exploring and describing these differences, and the specific pros and cons of different solutions, would be worthwhile.

The article also points to custom software functionality as a differentiator and to some degree an advantage. However, we could argue that customization is really a disadvantage, since traditional SCADA providers require software engineering to build out site-specific analysis tools, which adds tremendous cost during SCADA system development and requires ongoing in-house software engineering support to maintain.

Many web-based monitoring providers customize the software when customer requirements go beyond the standard feature sets. In addition, many providers offer portfolio management and O&M and asset management, including performance assessments, alarming, reporting (financial and technical), troubleshooting and service ticketing. Additionally, as providers develop customer-requested new analysis tools or enhanced feature sets, they deploy that functionality to all sites and to all customers within the web-based monitoring platform. This financially benefits site owners, operators and developers, as it eliminates the need to have an in-house software engineering team build such functionality.

A final difference outlined in the article relates to portfolio management solutions, which are more widely enabled with a web-based monitoring solution and not as easily enabled in a traditional SCADA solution. Traditional SCADA integration may require significant development efforts and costs beyond the individual plant SCADA deployment to achieve true portfolio management across multiple sites in different utility regions.

Choosing the right platform. The article asserts that project size should dictate the decision to choose traditional SCADA versus web-monitoring solutions. Size is quickly becoming a poor indicator for the type and extent of SCADA required for a project. Many small projects are now increasingly finding that utilities require supervisory control. At Draker, we have seen sites as small as 30 kW that need some form of control functionality. It is important to understand the requirements for these projects so that the client and developer can choose a cost-effective solution. In many cases, it would be more cost effective for these projects to use the supervisory control integrated into a web-based monitoring solution than to deploy a traditional SCADA solution.

Does the utility (or ISO) have control requirements? This is essentially the only distinction between SCADA and DAS. In addition to understanding whether control is required, defining the type and extent of control as well as the security requirements are equally critical when choosing an appropriate solution. It is also common to have a DAS system for the owner and a separate SCADA for the utility. Many utilities provide their own interface and just need secure access to the DAS. To comply with security issues while reducing overall costs with shared hardware, utilizing the owner’s preferred web-based monitoring provider to deploy SCADA as part of the full solution is often the best overall choice.

What is the makeup of the client’s labor force? Understanding the client’s labor force is important, both at the time of system deployment and also for future maintenance. Ease of use, customer support and training, and portfolio uniformity are often important factors when selecting a DAS system with or without control.

Where does the hardware reside? Both SCADA and web-based monitoring solutions include on-site hardware, and both can provide cloud-based backup as well as backup power and complex redundant systems on any utility-scale site.

Is the provider financially viable? Whether you are choosing a SCADA or DAS function set, viability is always important when choosing project partners. Draker is one of the oldest web-based monitoring providers in North America, with more than 1.5 GW of solar PV systems under management. Many web-based solution providers, including Draker, have put together third-party–assured business continuity solutions for their customers that protect customer data and access to the software in the cloud.

Who will manage O&M? It is important to consider who will manage the O&M today and over the lifetime of the project. Ease of use, adoption of industry standard functions and a strong customer support team are all important factors to consider. Maturing O&M trends in the PV industry will require more-open DAS platforms that continually changing O&M teams can easily transfer and access.

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Clients often ask PV system integrators and consulting engineers for recommendations on how best to monitor their assets and manage their portfolios. The variety of platforms available differ in cost and technical capabilities. However, most fall into two broad categories: supervisory control and data acquisition (SCADA) systems and web-based monitoring systems. Here we briefly consider the differences between these two platforms within the context of megawatt-scale PV systems. We also present 10 key questions to consider when selecting a platform.

Differences between Platforms

Many in the industry tend to use the terms SCADA and web-based monitoring interchangeably. However, there are important differences. On one hand, the traditional power sector has been using SCADA systems since the late 1980s, long before high-speed Internet connectivity became ubiquitous, and they provide active plant control. On the other, web-based monitoring systems are relatively new and generally focus more on data acquisition than on plant control and operation.

SCADA systems. Utility-scale power plants require not only large-scale data collection, but also a means of control. For example, a utility or independent system operator (ISO) may require a PV power plant to operate according to a contractually mandated schedule. In other cases, the utility or ISO may send commands directly to the on-site SCADA system via an energy control network. Traditionally, plant operators use SCADA systems with an on-board network historian server to meet plant control and data collection requirements like these.

SCADA platforms typically include software that is purchased up front. The purchaser owns the software licenses and the data collected. Providers generally do not sell SCADA packages as a service, but they do make annual updates available for a fee. The main difference between SCADA and web-based monitoring is that SCADA packages are typically designed to communicate with industrial automation controllers and provide enhanced control capabilities. As a result, the operator interface allows not only for monitoring and data collection, but also for direct control of plant operations, either locally or remotely.

Commercial plant operation requires such a high level of reliability that a firmware-based device—such as a programmable logic controller (PLC) or a similar type of smart relay—is necessary for plant control. Unlike a computer server, which is constantly executing many programs that are subject to interruption, a PLC runs only one application.

Web-based monitoring. The rapid growth of the solar industry over the last decade has spawned a multitude of companies that sell web-based PV monitoring software and services. Although some equipment manufacturers and system integrators offer their own monitoring platforms, lending institutions often impose independent monitoring requirements. Therefore, third-party companies typically provide data collection software and services optimized for PV applications. AlsoEnergy, Draker, Locus Energy and Solar-Log are a few of the vendors in this category. Providers typically sell web-based monitoring according to a software-as-a-service delivery model. The client pays up front for the site communications software and then pays a monthly fee for data storage and maintenance.

Choosing the Right Platform

When deciding between SCADA and web-based monitoring platforms, consider the following ten questions.

What is the size of your project? For projects of more than 10 MW in capacity, which typically have control requirements mandated by the utility or ISO, we recommend looking into a SCADA system. A web-based monitoring platform is good for individual projects of less than 10 MW in capacity and also for distributed generation sites.

What is the size of the overall portfolio? Some web-based monitoring systems are sufficient for site-level monitoring but do not manage multiple-site portfolios. In other cases, the client may have different monitoring platforms at different sites and may be looking to consolidate. If the client has a multiple-vendor portfolio, we recommend consolidating at a corporate level rather than changing equipment at the site level.

Does the utility have control requirements? If the utility requires plant or tracker control or the ability to allow operators to manually change setpoints, a SCADA package is preferable because you can customize it. Some web-based monitoring companies now provide limited control capabilities.

What level of data granularity do you need? Utility-scale plant operations require more in-depth data analysis than smaller PV systems need. With a SCADA system, the client owns and has easy access to all the data. A software developer can provide custom data analysis tools. Web-based monitoring systems provide a basic data analysis tool; they also typically allow clients to download data in comma-separated value (CSV) format, which they can manipulate in Microsoft Excel or other software.

How are monitoring costs amortized? Providers often customize SCADA systems for particular projects, so the software engineering costs are site specific. However, the project’s EPC budget usually includes the cost of SCADA licenses and software development. With a web-based monitoring platform, after buying the communications software the owner must pay a monthly subscription fee once construction is completed. Terms vary from provider to provider, depending on who owns the site hardware and the data.

 What is the makeup of the client’s labor force? Sophisticated clients with in-house engineering resources are likely to benefit greatly from a SCADA system because of the flexibility and granularity of data it can collect. Clients without in-house engineering resources can contract with a SCADA integrator or use a web-based monitoring platform if the inherent system limitations are acceptable.

Is a customizable solution required? SCADA systems are generally customizable and are well suited to complex reporting. Web-based monitoring systems generally come equipped with standard, off-the-shelf features.

Where does the hardware reside? Web-based monitoring systems require minimal site hardware but have few levels of redundancy, which could be a problem in the event of a power or network outage. SCADA systems can employ local servers with remote backup and can be integrated with complex redundant systems on a utility scale.

Is the provider financially viable? The solar industry is relatively young, and many providers of web-based monitoring systems are less than 5 years old. As the industry matures, the sector will likely experience consolidation, and some of these companies may not survive. In contrast, mature companies—such as ABB, GE, Invensys, OSIsoft, Rockwell Automation and Siemens—provide most utility-scale SCADA systems. These mature companies are more likely to remain viable in the longer term as compared to start-up companies backed by venture capital. Long-term viability is important, given that many PV power plants have 20-year power purchase agreements.

Who will manage O&M? If clients perform all of their own maintenance, it is advantageous to have a single platform monitor all sites and have this platform tie into a computerized maintenance management system (CMMS) that can centralize functions such as work order management, scheduling and trouble tickets. Web-based monitoring and SCADA systems have varying levels of support for CMMS systems. If CMMS integration is a client’s goal, take a close look at these feature sets when selecting a monitoring platform.

Tom Schreck and Prerit Agarwal / Ausenco / Concord, CA /

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[Portland, OR] DECK Monitoring now offers a competitively priced residential PV monitoring solution. The system utilizes a socket meter that is connected to the web via a cellular modem, eliminating the need to connect the monitoring system to the customer’s network. DECK includes a 5-year cellular data plan with the monitoring package. The residential monitor includes two web-based displays: a public dashboard and a secure admin panel. The public dashboard provides an easy-to-understand snapshot of the system’s production, along with historical graphs and custom project details. The admin panel is designed for project developers. It allows users to view detailed analytic data of all monitored systems and includes user-defined alarms and notifications, as well as raw system data downloads.

DECK Monitoring / 503.224.5546 /

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[Portland, TN] BOS equipment from Shoals Technologies Group includes combiner boxes, disconnecting combiners, custom wire harnesses, junction boxes, PV wire, in-line fuses, racking and PV monitoring solutions. As module prices fall and projects scale, BOS cost savings become increasingly important. This is especially true on thin-film projects with high-voltage, low-current modules that incur higher BOS costs. Shoals’ custom wire harnesses provide an innovative method of utilizing material and labor efficiencies on these larger, cost-sensitive projects. Each harness is factory built to the specified length, configured with the desired terminations and prelabeled. Shoals employs a patented Interconnect System that is more reliable and durable than standard splices. Wire harnesses can be purchased separately or preinstalled in combiner boxes. An inline fuse option is available for select thin-film applications to allow some parallel connections to be made in the array field, optimizing conductor usage and reducing the total number of combiner boxes.

Shoals Technologies Group / 615.451.1400 /

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Sizing and specifying a system for off-grid clients can be the hardest challenge a designer ever faces. Most stand-alone systems are inherently more complex, with more complicated interactions between components, than standard gridtied systems. Good stand-alone system design is based on careful interaction with the clients. Essential steps in creating an efficient and reliable system that meets the clients’ expectations include understanding their motivations and requirements, helping them determine their needs and desires, tailoring the design to match the hard realities of their site and budget and turning the results of this soul searching into hardware and components. Fifteen years ago, when my wife and I built a home in New Mexico and moved off the grid, these were our own challenges.

While the US solar industry has undergone amazing transformation in the past 15 years, the key steps to designing effective and durable stand-alone systems have remained consistent. In this article, I do not present a comprehensive design guide, but rather I introduce the critical decision points in the design and installation of high-quality stand-alone residential power systems.

The Art Of Load Analysis

Without drawing too fine a line, off-grid customers can be generally divided into two types: sailors and motorboaters. Sailors travel within the limits of what the wind provides, tacking and trimming their sails to best fit their intended path. Motorboaters expect to maintain their desired speed and direction, regardless of the weather. Neither mode of travel is right or wrong, but you need to take different system design approaches to match the lifestyle and needs of these disparate clients. When it comes to off-grid customers, sailors can usually live within the limits of a smaller, budget-constrained system, whereas systems designed for motorboaters should contain a higher level of automation and self-protection.

A comprehensive load analysis is the most important step in designing an off-grid system for three main reasons. First, determining the total electrical load is critical to choosing the correct battery bank and PV array. Second, this analysis also determines the inverter capacity required to efficiently power all connected loads. Third, by exploring the load analysis with the clients, you gain a clearer understanding of what energy demands they consider critical and what they consider expendable.

At its simplest level, a load analysis is a detailed examination of what household equipment the clients want to operate, how much they use it and how much energy it consumes. A critical need to one person may be a luxury to the next, so it is important to examine the clients’ requirements rather than apply a one-size-fits-all approach. One of the best ways to start a load analysis is to have the clients walk through their home and evaluate each object that consumes electricity to determine how much energy it draws and how often they use it.

While large systems can be challenging to design due to the complex level of interaction between the various components, the very smallest systems benefit the most from good design practices. In a large system, errors of omission or miscalculations are often glossed over by increased generator run-time. Large systems are sophisticated enough to self-protect, and the client may never be aware of any oversight in the design process. In a microsystem, however, there is no room for error. Any miscalculation or overlooked load can result in substandard performance and shortened battery life. Conversely, overestimating the load may needlessly increase PV array capacity and cost.


Veteran integrators serving off-grid markets often develop in-house sizing tools. For those new to stand-alone systems, the available design resources range from simple worksheets, such as “Stand-Alone Sizing Worksheet” in Appendix D of SEI’s Photovoltaics: Design and Installation Manual, to powerful software tools capable of modeling annual system performance, including required generator input, using hourly weather data for specific locations. Maui Solar Energy Software, for example, offers PV-DesignPro-S for stand-alone system design and analysis as part of its $250 Solar Design Studio software suite. Somewhere between these options is “Simple Stand-Alone PV System Worksheet” available with this online version of this article (CLICK HERE). This Microsoft Excel spreadsheet was first developed by Windy Dankoff and is provided in its current format by Conergy. Whatever sizing tool you use, every load needs to be assigned an estimated energy consumption value.

Calculating energy use. For most simple loads, daily energy use is a quick and easy calculation:

average daily energy (Wh) = (quantity x watts x hours/day x days/week) ÷ 7

For instance, two 15 W compact fluorescent lamps used 4 hours a day, 5 days a week consume 86 Wh on average per day.

However, not all loads are simple. Many loads, such as washing machines and dishwashers, are dynamic. In these cases you need to know the energy consumed per cycle. Other loads, such as refrigerators, cycle randomly throughout the day based on temperature. Electronic equipment such as stereos or computers have electrical ratings that indicate how much power they draw under peak conditions, but their actual power draw is variable.

Measuring energy use. For dynamic, cycling or variable loads, I recommend quantifying energy use with a simple load meter, such as the Brand Digital Power Meter or the Kill A Watt meter from P3 International. These devices are easy to use and provide both instantaneous power measurements and energy consumed over a given time. For dynamic loads, measure energy consumption per cycle and calculate energy use based on the average number of cycles per day. For random cycling or variable loads, measure for a 24-hour period. For new appliances, daily energy consumption can be estimated by dividing the yearly energy consumption rating on the yellow Energy Guide label by 365. For refrigerators and many other major household appliances, the efficiency gains to be had by investing in the most recent Energy Star appliances are so great that it pays to upgrade.


The hardest aspect of doing a load analysis is mastering the art of hitting a moving target. Our energy consumption is dynamic. Our lives grow and requirements change, if not daily or weekly, then certainly seasonally and through the years. So how do you distill your clients’ needs down to a concrete number?

These five rules can help.

Rule #1: Do not be sidetracked by superficial details. In many of the systems I have designed, the client has returned a load analysis with a painstakingly detailed summary of every light in the house. For your purposes, however, illumination can often be reduced to broad strokes. For example, two or three lights per person, 4 or 5 hours a day, is usually sufficient for most families. Lighting loads, after all, can be kept under control.

Rule #2: Seek out loads that cannot be controlled. Very few clients are willing to unplug the refrigerator just because the PV system’s batteries are low. This is an example of a load that cannot be controlled. If there is a howling Northeaster with days on end without sun, the client can decide whether to watch a movie or read a book. The thermostat, however, will almost certainly call for heat. You need to account for this energy consumption.

Rule #3: Never stop searching for a better way. In the context of stand-alone power system design, some lifestyles are better than others. For example, off-grid customers should use a clothesline instead of a dryer, and a laptop instead of a desktop computer. Instead of a coffee pot with a 900 W heating element, how about a thermal carafe instead? The key is to approach this not as a matter of doing without, but rather as a challenge to see how it can be done better. My general rule is that any load with a run-time greater than 1 hour or a power draw greater than 900 W needs to prove its worth.

Rule #4: Provide your clients with a feedback mechanism. No load analysis is perfect. A simple system monitor provides valuable information on how the system performs over time. More important, it can provide instantaneous and historical feedback concerning inputs and outputs. Clients make better decisions when they can see the relationship between generation and demand on an hourly, daily or weekly basis.

Rule #5: Plan for the future. Sometimes the future can be anticipated, such as appliances the clients wish to have, but either cannot afford or do not need now. Sometimes the future is a shot in the dark. One thing is certain, however: load creep. I have yet to see one family whose energy requirements have decreased over time. My wife and I started with a 300 W array and had an energy surplus. When our children were born, our system grew, along with our home, to 1.5 kW. As I cast an eye toward their teenage years, I am planning another expansion to 2.7 kW. This is not to suggest that you front-load your clients and install a larger array than they need. However, leaving conduit in the ground and breaker space in the panel is a valuable service.


Regardless of the sizing tool you use, keep in mind that some loads are more important than others—and some are easily overlooked. Consider as well that each customer’s needs and priorities are different.

Water. An important consideration during the load analysis is how the clients get their water. Since most off-grid residences rely on a pump rather than the city water mains, this is probably the single largest driver in system design.

If the clients have a well with a large ac submersible pump, then the inverter and related BOS components need to be sized to start that load. They must also be able to support all background loads without overcurrent tripping or dimming the lights. Conversely, if the clients’ primary water source is a rainwater cistern with a small dc pressurization pump, it has little overall impact on system size.

With a few exceptions, such as the Grundfos SQ line of pumps, ac centrifugal pumps are not very efficient. You can expect the pump to draw approximately 1 kW per horsepower when running. Dividing the client’s daily expected water needs by the pump flow rate provides the daily expected run-time. A useful guide for sizing inverters to power ac submersible pumps is that they require at least 2.5 kW of inverter capacity per horsepower for starting. Remember, the inverter has to start the pump while the washing machine is running as well.

What is missing? When reviewing a load analysis, it is important to consider what is not included in the client’s list. It is surprising, but clients often do not notice the things that draw a significant amount of energy in their home. Many clients are concerned about their microwave oven, for example, whereas you need to worry about cell phone chargers and the like.

Doorbells and thermostat transformers, heating system zone valves, cordless phones, electric clocks, smoke detectors and security systems require constant ac power. If not accounted for, these loads can drag down a system, causing it to run a constant deficit. I try to eliminate such loads by recommending alternative products that do not require constant power. For example, clients can use a knocker in place of a doorbell, choose a gas stove with piezoelectric ignition instead of glow bars or use clocks that run on batteries. Coordinating with the contractor and electrician to add switched outlets wherever appropriate can help conveniently eliminate standby loads for televisions, DVD players and other consumer electronics.

Prioritize. Once you have evaluated a household’s appliances and quantified their energy use, the true design work begins. I start by asking the clients to group their loads into three categories: must haves, like to haves and nonessentials. Very few people have the budget to power everything they desire. This simple task helps me gauge what is critical to them to ensure the system meets their needs.

If the client’s budget is constrained, you may design the system to expand over time. For example, a young couple might live easily within the scope of a small system but need additional power as the family grows. The system design should support this growth without major reconstruction.

Invest in efficiency. One of the most effective ways to reduce stand-alone power system size and, therefore, cost is to invest in energy efficiency. Every dollar invested reduces the home’s energy profile, which considerably decreases PV system cost, while providing equal or better quality of life. Investments in thermal efficiency are especially beneficial. It is far more economical to design a home with minimal heating and cooling requirements than to throw energy at forcing hot or cold air through the house.


After the load analysis has identified the power and energy requirements, you need to account for all conversion, efficiency and tare losses.

Conversion losses. The daily energy requirement of all ac loads must be adjusted to account for dc-to-ac conversion an inverter consumes versus the connected load. For the load analysis, an 85%–90% average dc-to-ac conversion factor is reasonable. A highly efficient inverter makes the most of every electron and wastes very little energy in the process of conversion. In theory, you would simply choose the most efficient inverter on the market. In practice, however, the peak efficiency point of stand-alone inverters rarely coincides with the loads in a home.

Inverter efficiency. Efficiency is described by a curve that varies with inverter loading. Know the shape of the efficiency curve and how it relates to the primary loads. Since the load profile can change drastically and continuously throughout the day, inverter choice may not be so straightforward.

For example, consider a 5 kW inverter with a peak efficiency of 95% at 1 kW. The inverter is specified for an application where there is a continuous 100 W background load and occasional spikes of short duration to 4 kW. The inverter is generously sized to handle the peak loads without strain, but the primary 100 W load is well below the inverter’s peak efficiency point. As a result, the inverter may run at 60%–70% efficiency throughout the day. A better alternative would be a 2.5 kW inverter with 93% peak efficiency. While the peak efficiency might be lower, the inverter operates more efficiently at the primary operating point, as determined by the background load. Since most stand-alone inverters can surge well beyond their rated capacity, handling the 4 kW spikes are not problematic.

Tare losses. Also referred to as idle or standby losses, tare losses are a measure of the energy the inverter consumes to power its internal electronics and magnetics. This is critical to include in system sizing. For instance, a typical off-grid residential system might employ a single Magnum MS4448-AE inverter, which draws approximately 25 W continuously when in idle. Over the course of a day, the inverter consumes 0.6 kWh (0.025 kW x 24 hours = 0.6 kWh). This consumption must be added to the daily energy requirement.

I have seen poorly designed installations where the inverter’s standby power draw was greater than the energy consumption for all of the loads combined. In one case, it was even greater than the output of the entire PV array. Effective tare loss management becomes especially critical as system size increases. Generally, the larger the inverter or greater the number of inverters, the greater the potential tare losses. Knowledgeable manufacturers take pains to decrease inverter tare losses by careful design of the electronics and magnetics, and they integrate sophisticated schemes to minimize losses in multi-inverter installations.

Inverter Selection and Configuration

In the early days of off-grid solar, inverters were notoriously unreliable and, as a result, multiple inverter use was common. When one failed, a backup inverter was wired into the system while the first went out for service; meanwhile you hoped that the first inverter returned before the backup failed. For ultimate reliability, specifying dc appliances that could run directly off the battery pack was considered advisable to meet critical needs, such as refrigeration, lighting and water pumping. Modern inverters, however, are not only reliable, but they are also continually increasing in power, flexibility and sophistication.

The choice of inverter is another aspect where standalone systems differ greatly from grid-direct systems. With an off-grid system, the inverter must provide high-quality stable power, operate around the clock for decades without failure, be capable of surging well beyond its rated capacity to power reactive loads and sensitive loads simultaneously and charge from generators with less-than-ideal waveforms— all while managing its own idle current to maximize system efficiency. When you are choosing an inverter for stand-alone operation, you must consider reliability, flexibility, ease of installation and programming, charging capacity, serviceability and surge capability. Surge capability is often touted foremost, but it arguably is the least important factor.


Although inverters are often thought of as simply converting dc to ac, in stand-alone systems the inverter frequently operates in a bidirectional mode. In addition to powering ac loads, the device can also charge the batteries from an ac engine generator. How well the inverter can function as a battery charger is critical.

Charging performance often takes the most time to adjust and get operating correctly. The wider the inverter’s acceptable voltage and frequency window, the better; and the easier it is to access these set points, the better. This is especially true with lower-cost generators often used in smaller systems. I was recently surprised to find an inverter with charging set points that could be adjusted only via a proprietary computer program and interface dongle. Unfortunately, these are neither shipped with the inverter nor mentioned in the user’s manual.

Another aspect to consider is whether the inverter has a power-factor–corrected charger or whether the charger appears as a reactive load to the generator. Reactive loads waste much of the generator’s capacity as heat. Since neither the generator nor the inverter have the stability of the grid, lagging or leading power factor from the charger circuit can cause extreme instability and harmonics, which also affect loads in the house.


For many residential off-grid systems, a single inverter is sufficient to power all desired loads. Adding an additional inverter or inverters to provide split-phase power, often simply to provide 240 Vac for the well pump, only serves to increase costs and complexity. However, 120 Vac stand-alone systems can present their own challenges when interfacing with components or wiring designed for split-phase power.

Generator input. The vast majority of off-grid systems rely on backup generators during extended periods of inclement weather. Most generators are designed to provide full output at 240 Vac. Attempting to use a single 120 Vac inverter to charge batteries with generators configured for 240 Vac output utilizes, at best, only half of the generator’s rated capacity. Worse yet, the generator is unbalanced: one phase is heavily loaded while the other has little or no load. This causes stress on the generator’s components and can significantly shorten its lifespan.

If a single inverter with 120 Vac output is specified, consider using a higher-quality generator that can provide full output at 120 Vac. Alternatively, you could add a step-down balancing transformer to the system. These approaches not only spare the generator from unbalanced operation, but they can also cut generator run-time in half by effectively doubling the current available for battery charging.

Multi-wire branch circuits. A somewhat common ac wiring practice, where one neutral conductor is shared between two hot conductors, could present a challenge when interfacing a battery-based system with an existing ac service. Normally, the waveforms of the two ungrounded currentcarrying conductors are in opposition— 180° out of phase with one another—and the neutral grounded current-carrying conductor carries the difference in current between the two. In this scenario, there is no risk of the neutral becoming overloaded. However, when the system is powered by a single 120 Vac inverter, the neutral carries the sum of the currents on both legs, presenting a dangerous overload potential. Possible solutions for dwellings with shared neutral wiring include rerunning the ac circuits, combining the two hot conductors into one circuit powered by a single 120 volt circuit breaker, adding a second inverter or a transformer to provide 120/240 system output and specifying a single inverter that outputs split-phase ac.

Split-phase inverters. Recently, manufacturers have introduced products with integrated split-phase 120/240 Vac output. They can greatly streamline installations, and, more importantly, they match traditional US standards and expectations. Magnum Energy was the first to market with a battery-based inverter with split-phase output. Xantrex’s line of XW inverters also incorporates this design feature. As currently implemented by both Magnum and Xantrex, one possible pitfall of this inverter design is that the inverter may not be fully capable of supporting unequal loads on the two phases. The ideal splitphase inverter would be capable of providing a high percentage of its full rated output into one phase for extended periods of time, without allowing the voltage on the unloaded leg to spike.


Until recently, all battery-based inverters available in the US had 120 Vac output from line to neutral. Installations requiring 120/240 Vac split-phase or 120/208 Vac 3-phase power required multiple inverters synced to provide the opposite phases. A common design approach in larger stand-alone systems is to utilize multiple inverters. The ability to stagger or tier the inverters allows only those that are required to power the current loads to be active.

Inverter stacking. How you specify the system affects the energy that the inverters consume due to tare losses. For example, a typical system with two 3.6 kW OutBack VFX3648 inverters could employ one of three possible configurations:

  • Classic stack mode. Each inverter powers one leg of a 120/240 split-phase distribution panel, and a load on either inverter causes both to switch from sleep to idle mode. Each inverter draws approximately 23 W continuously. Over the course of the day the inverters consume roughly 1.1 kWh.
  • OutBack stack mode, with an autoformer. The second inverter drops into sleep mode when not required. Even with the additional 12 W of power that the autoformer consumes, the tare loss drops to 0.84 kWh/day, because the second inverter has an idle draw of 0 W.
  • Parallel stack. With full output at 120 Vac, the consumption drops to 0.55 kWh/day.

The benefit of a staggered approach becomes evident as system size increases. For example, it is possible to have a 36 kW OutBack inverter system with 10 inverters and an idle draw of less than 50 W when loads are light. Of course, the speed at which the system can react to changes in the loads by waking up additional inverters affects how well it can support spikes, such as motor-starting inrush currents, without overloading or allowing voltage to sag excessively.

Battery Selection and Configuration

The battery bank is one of the most challenging, confusing and misunderstood components of stand-alone PV systems. Part of the reason is that batteries can perform in what appears to be a nonlinear manner. The key to understanding batteries is to realize that they are chemical machines. One of your jobs as a designer is to ensure that the system as a whole operates within the ideal parameters for the specific batteries that you chose, as much of the time as possible.

With any chemical reaction, there is an ideal range of conditions within which the agents can react fully. For example, as temperature increases, the chemical reactions within the battery become more aggressive. If you speed up the reaction beyond the ideal range, the reaction is incomplete. As temperature decreases, the chemical reaction is slowed and reduces the effective battery capacity.

Capacity. Batteries are rated in amp-hours (Ah) at a given discharge rate. The discharge rate for a battery is denoted by capacity (C) divided by time, or C/X, where X equals the duration of the discharge cycle. For our purposes, the C/20 rate is considered the industry standard, and this is the rate that should be used when comparing batteries.

Effective battery capacity decreases as rate of discharge increases and vice versa. For example, a Surrette S460 has a capacity of 360 Ah at C/24, meaning it would take a 15 A load 24 hours (15 A x 24 h = 360 Ah) to discharge the battery from full (100% state of charge) to empty (100% depth of discharge). Decrease to a C/100 discharge rate, and the same battery has a capacity of 466 Ah, as there is more time for the active materials to participate in the chemical reaction. Conversely, if you increase the discharge rate to 4 hours, a very high rate of discharge for a deep-cycle battery, the capacity drops to 228 Ah. The chemical reaction is happening too fast to fully utilize the battery’s active materials.

Days of autonomy. The number of days that the battery bank can support the design load without solar or generator input defines its days of autonomy. This is an important consideration when sizing energy storage systems. In practical terms, a reasonable target is 2 to 3 days of autonomy. Designing for less than that provides insufficient reserves during inclement weather. However, attempting to achieve excessive days of autonomy can result in a battery bank that is too large to effectively charge—and this negatively affects battery longevity.

Total energy storage. To determine the desired energy storage, prior to cycling or temperature considerations, multiply daily energy consumption by the number of days of autonomy. For instance, consider a small stand-alone lighting system intended to power four 12 Vdc, 20 W LED lamps for 8 hours every evening.

average daily energy (Wh)
   = (4 x 20 W x 8 hours/day x 7 days/week) ÷ 7 days/week
   = 640 Wh

Three days of autonomy would therefore require 1,920 Wh of stored energy.

Deep-cycle batteries can be discharged without harm to 20% of their C/20 rated capacity—an 80% depth of discharge— as long as they are routinely recharged back to full. Therefore, to determine the minimum total energy storage, divide the desired energy storage prior to cycling by 80%:

minimum energy storage
  = 1,920 Wh ÷ 80% = 2,400 Wh

Because batteries are seldom rated in watt-hours, you need to convert energy to amp-hours by dividing the minimum energy storage by the system’s nominal battery voltage:

minimum battery capacity
  = 2,400 Wh ÷ 12 V
  = 200 Ah

Batteries are designed to operate at room temperature. If they are in an unconditioned environment below room temperature, the chemical reaction slows down, reducing the effective capacity. Storage capacity must be corrected upward for conditions of use. Most battery manufacturers publish temperature coefficients for their products, but a generic 1% reduction per °C below 25°C can be used when they are not known.

For the small lighting system under consideration, assume the specifications call for an outdoor enclosure, with winter temperatures commonly dropping to -5°C. This is a 30°C delta from the temperature that the battery is rated at according to its published specifications, which corresponds with a 30% reduction in battery capacity. At -5°C, when only 70% of its nameplate capacity remains, the battery still needs to supply the equivalent of 200 Ah at 25°C. This adjustment can be made as follows:

T-corrected minimum battery capacity
  = 200 Ah (at -5°C) ÷ 70%
  = 286 Ah (at 25°C)

It is easy to verify that this is correct: the battery has a 286 Ah capacity at 25°C; 30% of 286 Ah equals 86 Ah. When 86 Ah are removed from the total capacity because the temperature is -5°C, there is still 200 Ah capacity available to serve the load.

Charge and discharge rates. After sizing a battery, you would be prudent to compare its Ah capacity to the current available from charging sources to ensure that the design optimizes battery longevity. The correct rate of charge is critical. Too fast, and excess energy is dissipated as heat, which can damage a battery. Too slow, and the charge rate may be insufficient. What this commonly means in a stand-alone PV system is that the battery simply cannot reach a full state of charge before the sun sets.

For best performance, the desired target charging current for a deep-cycle battery is equal to the battery capacity divided by a value between 10 and 20. For the example lighting system, the target array charge current should be in the range of 14 to 28 amps (between 286 Ah ÷ 10 hours and 286 Ah ÷ 20 hours). When calculating the charge rate, take into account any daytime loads. Due to budgetary constraints, I may choose to target a daily C/20 rate with the PV array, for example, and achieve a weekly or monthly C/10 rate with generator charging. This might require a larger generator and additional inverters beyond what would otherwise be needed to power the loads, but the incremental expenses are generally more cost effective than substantially increasing the PV array.


Batteries are available in a staggering range of sizes, styles, capacities and qualities. I find that the most cost-effective solution for most residential applications is specifying high-quality industrial flooded lead acid (FLA) batteries from a reputable manufacturer. For small, budget-constrained systems, I consider golf cart batteries from a reputable manufacturer—but the short-term savings of lower-cost batteries are usually offset by the costs of poor performance and shortened lifespan.

Wiring configuration. Much like modules, batteries are connected in series strings to obtain the desired system voltage. Additional identical strings are added in parallel to increase capacity. Each battery cell provides a nominal 2 V, meaning that for a 48 Vdc nominal system, 24 cells are strung in series.

Unlike modules, there are practical limits to how many battery strings you can connect in parallel. If you think of a string of cells as a chain, then the chain is only as strong as the weakest link. Due to variances in manufacturing, internal resistance and interconnections, as the number of parallel strings increases, so does the likelihood of having a weak link. In this case, the weak link is the one cell that resists charging more than its neighbors. This diverts current through the other strings, leaving the weak string undercharged. To make things worse, an undercharged string not only draws down the performance of the other batteries, but it also continues to weaken unless you take corrective measures.

A battery consisting of a single string of cells theoretically provides the best performance; however, in practice many designers prefer two strings for redundancy. If two strings are used, the failure of a single cell or battery is not debilitating. The system can continue to operate on half the battery capacity while a replacement is on its way. The general industry recommendation is not to exceed three parallel strings. If more capacity is required, you should look at increasing the system voltage or choosing a cell with a greater amp-hour capacity.

Wire sizing. Another challenging aspect of building a battery bank is sizing the battery interconnect and batteryto- inverter cables. In the case of a single string of batteries connected to a single inverter, the determination is easy: Size the cables based on the amperage rating of the main breaker. If a second inverter is connected to the batteries through a second parallel main breaker, install parallel conductors of the same ampacity.

However, what happens as the system grows in scale? If there are eight inverters in the system, do you need to install eight paralleled sets of conductors, assuming they could all fit on the battery terminals? Typically, the approach is to sum the eight paralleled breakers and provide cabling of sufficient capacity to handle this current. For example, consider eight OutBack VFX3648 inverters, each with a 175 A breaker. The breaker rating calls for 2/0 cable from the breakers to each inverter. However, can you economize on the cabling to the battery, which needs to be sized for 1,400 A (8 x 175 A)?

Referring to Table 310.17 in the NEC, 2/0 THW cable has an allowable ampacity of 265 A in free air; 4/0 THW can handle 360 A. Therefore, in this application, you could use four paralleled 4/0 conductors from the battery breakers down to the battery.


Series String Fusing for Batteries?

NEC Article 690.71(C) requires that a listed current-limiting overcurrent device be installed in each circuit where the available short-circuit current from the battery exceeds the interrupting ratings of equipment in that circuit. Unfortunately, few battery manufacturers provide short-circuit current ratings for their products, so you may need to do additional research to ensure that you meet this requirement.

One notable exception is Northwest Energy Storage’s HuP Solar-One series. For instance, its SO-6-85-21/48 series battery is rated for 1,055 Ah at a 20-hour rate, with a short-circuit current rating of 12,000 amps. The 175 A or 250 A Carling Technologies F series circuit breaker is a typical overcurrent device used by many battery-based inverter manufacturers. This device is listed by CSA to UL 489 for dc applications up to 125 Vdc and has an amps interrupting capacity (AI C) rating of 50,000 amps. In this case, the available fault current from the battery bank is less than the AI C rating of the inverter breaker, so no additional current-limiting devices are required.

Not all breakers used in solar applications have such a high AI C rating. The Carling Technologies C series circuit breaker, for example, has an AI C rating of only 5,000 amps. If there were a fault condition downstream of this device, the short-circuit current available from this battery could overwhelm its ability to interrupt the flow of current. Therefore, under these conditions the manufacturer’s data sheet requires that a K5 or RK5 fuse rated no more than four times the full load amps be used to back up the breaker. The installation of these fuses should comply with Article 690.16, which states that disconnecting means must be provided for all sources of supply if the fuse is accessible to other than qualified persons. A fuse holder with a bolted connection could be utilized if a tool is required to access the fuse.

PV Array Selection and Configuration

The operating voltage is the primary difference between a PV array for a residential grid-tied application and a PV array for an off-grid residence. The vast majority of charge controllers currently used in battery-based applications are designed to function with an array voltage somewhere between the nominal battery voltage and a 150 Vdc maximum open-circuit voltage. Grid-direct systems typically have a maximum potential of 600 Vdc. For the same array capacity, a stand-alone system has more source circuits in parallel; these series strings operate at lower voltages than you may be accustomed to.

In addition, the battery in a stand-alone power system can supply a hazardous and potentially damaging amount of current into a fault. Therefore, the overcurrent protection exception in NEC Article 690.9(A) cannot be applied to the array wiring in an off-grid system. Series fusing is required for every string of modules. Fortunately, 150 Vdc-rated circuit breakers and array combiners are available from numerous sources in a range of sizes.


Determining the array capacity for a stand-alone application is relatively straightforward and, in many ways, comparable to calculating the estimated production of a grid-direct PV system. There are, however, a few notable exceptions.

Peak sun hours. Unlike a grid-tied system where any deficit is seamlessly met by the utility company and any surplus is carried forward, a stand-alone system must provide for the entirety of the clients’ needs at all times. Any energy deficit must be made up by generator run-time or load reduction. Most designers size off-grid systems based on the season of heaviest demand, which for most clients is wintertime, when the days are short and insolation is limited. The winter daily average peak sun hour values used for stand-alone system design purposes are much lower than the year-round averages commonly used in grid-tied calculations. In addition, when you specify array-mounting systems in standalone applications, use higher array tilt angles to maximize wintertime production.

System losses. Stand-alone system designs need to account for additional losses involved in charging batteries. As an example, calculate the array required for a client outside Albuquerque, New Mexico, whose load analysis indicates a daily 5.4 kWh ac load requirement before inverter tare losses and other system losses are considered.

Assuming that the inverter is 90% efficient on average, the customer’s array needs to deliver 6 kWh as a daily average (5.4 kWh/day ÷ 90% = 6 kWh/day). Accounting for 3% wire losses, this number increases to nearly 6.2 kWh per day (6 kWh/day ÷ 0.97 = 6.19 kWh/day). Storing energy in a battery for later use entails additional energy conversion. These round-trip losses are generally accounted for using an additional 80% derate factor; if the majority of ac loads coincide with daytime peak charging, however, this factor could be closer to 90%. Since the client works away from home, peak loads are not expected to coincide with PV generation, so the total average daily energy input is estimated at 7.7 kWh per day (6.19 kWh/day ÷ 80% = 7.7 kWh/day). This is the average amount of energy the client requires on a daily basis. Your job is to design a charging system that returns that much energy to the batteries every day.

A common source for daily peak sun hour data for a variety of locations and conditions is the “Solar Radiation Data Manual for Flat-Plate and Concentrating Collectors,” published by NREL (see Resources). This volume is often referred to as the NREL Red Book, due the color of its cover.

According to the NREL Red Book data for a typical meteorological year in Albuquerque, New Mexico, which has a latitude of 35°N, the client’s site receives an average insolation of 5.5 kW/m2/day in December for an array tilted at latitude plus 15°. The resulting 50° tilt is a far more severe tilt angle than usually encountered in grid-tied applications. In this case, the system design driver is meeting the average daily load in the worst-case scenario at the winter solstice. Because a peak sun hour is equivalent to 1,000 W/ m2 for 1 hour, system designers routinely refer to average insolation values simply as peak sun hours—in this case, 5.5 peak sun hours.

The minimum PV array required for this example is calculated as follows:

Minimum PV capacity
  = daily avg. energy required ÷ daily avg. peak sun hours
  = 7.7 kWh ÷ 5.5 peak sun hours
  = 1.4 kW

In order to achieve the daily energy harvest required in real-world conditions, you should specify a 1.4 kW PTC-rated array rather than a 1.4 kW array at STC.

Diminishing returns. It is difficult to meet 100% of your clients’ needs with solar 100% of the time. Due to the changing nature of both the weather and the clients’ loads, there is a point of diminishing returns. No matter what the historical data shows for insolation averages, some periods of inclement weather will exceed the average. Similarly, while you can account for every watt-hour the client intends to consume, guests will come to visit and the carefully calculated load profile goes out the window.

The budget defines the effect of diminishing returns in a stand-alone PV system design. For example, while it might be relatively affordable to meet 80% of the household energy needs with renewables, meeting 90% might double the system costs. Reaching for 95% might double the cost again. Therefore, every stand-alone system needs to have some sort of energy source that can be activated on demand. Usually, this is a generator powered by fossil fuel. While this might run counter to some clients’ desires to decrease their carbon footprint, the alternate choice is to shed loads in times of inclement weather or to risk damage to the batteries. You need to ensure that the clients’ needs are covered, that their investment is protected and that generator run-time is minimized. In order to minimize generator run-times and fuel consumption, extracting as much energy as possible out of every gallon of fuel burned is important.

One way to achieve this is to make the generator do the heavy lifting. Often, there is one large load—an ac submersible pump, perhaps—that is forcing the system to be larger than is otherwise needed to cover the basic loads. In this case, if you add aboveground water storage and a small booster pump, you can run the generator to power the pump to fill the storage tank. Best of all, if the generator is sized large enough to start the pump, it also has sufficient reserves to run other loads, such as charging the batteries.

Charge Controller Selection

Charge controllers have two main functions in stand-alone PV power systems: optimizing PV array performance and providing optimal battery charging while protecting the batteries from overcharging. With the possible exception of extremely small systems, most stand-alone systems utilize advanced MPPT charge controllers, which greatly increase the energy harvested.

MPPT controllers allow the array voltage to be independent of the battery nominal voltage, which means that you are not limited to working in 36-cell modules and multiples thereof. This is an increasingly important benefit, because many modules are available with different cell counts and varying maximum power voltages.

Sizing an array with an MPPT controller follows many of the same calculations as sizing an array with a string inverter. Invariably, however, the array voltages are lower and the current higher. Some charge controller manufacturers provide online sizing tools equivalent to string inverter-sizing tools, but these are not as fully developed as inverter-sizing tools. You should perform design calculations to confirm the electrical design. (For more information, see the “PV Array Matching to Charge Controller and Battery Bank” sidebar in “Grid Down Power Up,” February/March 2009, SolarPro magazine.) The goal of these calculations is to ensure the following three requirements are met:

1. Under the lowest expected temperatures, the maximum open-circuit voltage does not exceed the rating of the components.

2. Under the hottest conditions, the lowest MPP voltage is sufficiently higher than the battery equalization voltage.

3. The power throughput capacity of the controller is not exceeded under peak operating conditions.

Controller capacity is calculated by multiplying the controller-rated output current by battery nominal voltage. I prefer that the maximum array wattage not exceed the controller capacity. This results in a relatively conservative number, but it should be noted that the controller often operates at its highest capacity during winter conditions, when the array is cold and the battery voltage low. You want to ensure that you can adequately harvest all the potential energy at this time. I therefore recommend a conservative design to prevent conditions in which the array is capable of putting out more power than the controller can process. (More information on optimizing the array for MPPT controllers is available in “Optimizing Array Voltage for Battery-Based Systems,” in this issue of SolarPro.)

Putting It All Together

Integration hardware—which includes components used to house and protect overcurrent protection devices, cabling and secondary equipment—is now available from multiple manufacturers. These products coordinate with a wide array of inverter and BOS components. It is your responsibility to select the proper integration hardware and to ensure that the ratings and capabilities match the requirements of the components. You must also confirm that the physical location provides working clearance for the equipment. It is always advisable to accommodate future system expansion as well.

Probably the hardest part of integrating a stand-alone PV system is making sure you have all the required components on hand. These systems are highly customizable, far more so than grid-direct PV systems. Components may include dc load breakers, ac load breakers, battery cable busbars, current shunts, system monitoring components, a generator balancing transformer and an ac output transformer for split-phase loads.

Inverter bypass switch. One component may need to be ordered separately, but should not be left off any battery-based inverter system: the inverter bypass switch. This switch is essential to the safe operation and maintenance of the system in the event of an inverter failure or service call. In many systems, the inverter bypass switch is a ganged-breaker assembly that is integrated into the sheet metal enclosure on the ac side of the power panel. Larger systems often require an external double-pole, double-throw transfer switch.

Either way, the bypass ideally has three positions: normal, bypass and off. In the normal position, the inverter supplies ac power to the residence. In the bypass position, the generator supplies ac power to the residence, but it does so without energizing any terminals at the inverter. This means that the inverter can safely be serviced or removed for repair without loss of power at the ac loads. In the off position, neither power source is connected to the ac loads. Perhaps the best resource on how to specify and install the right bypass switch is the eight-page “AC Input Output Bypass Switches” technical note available at the OutBack Power Systems Web site (see Resources). In addition to providing a safe and convenient way to service an inverter, the bypass switch also gives you a first course of action when remote customers call because they have lost power. Simply have them throw the bypass switch and start the generator.

Power panel integration. There are three main design and specification resources for integrators: equipment installation manuals, technical service representatives at wholesale renewable energy equipment distributors and applications engineers or technical support representatives for the OEM.

Both the OEM and its distribution partners may offer value-added services whereby dozens of components are preassembled and prewired into an integrated power panel. The power panel is crated and shipped on a pallet to either the job site or your warehouse. This assembly is more or less ready to hang on the wall and wire. It is not quite, but almost, as easy as wiring a grid-direct system: Land the dc in from the array and battery pack; wire the ac out to the loads and in from the generator.

While experienced off-grid installers often forego this option, preassembly in your warehouse may create efficiencies. In many cases, assembling components on a workbench in a conditioned space is easier and faster than integrating components in the field after the back panel and enclosures are mounted to the wall. Preassembly may also reduce the likelihood of rolling a truck to a remote site only to discover that an essential component is missing. Not all projects lend themselves to preassembly or the use of value-added integration services, but for smaller or first-time projects, they may save considerable time and money.


No stand-alone PV system is complete without a system monitor. This feedback mechanism allows the homeowners to keep track of the system’s health and performance. Was today’s charging sufficient for the batteries to recover from last night’s loads? How long has it been since the batteries were equalized? System monitoring answers these questions and gathers a whole host of other essential information. Think of a monitoring system like the instruments in your car’s dashboard: The engine will run and the wheels will turn without it, but you are also highly likely to run out of gas or get pulled over for speeding.

Many different manufacturers offer good system monitors, each with their own advantages and disadvantages. The perfect system monitor would be easy to understand, provide state-of-charge at a glance, indicate whether the batteries are charging or discharging and how fast this is occurring compared to battery size, display meaningful historical information in an intuitive manner and provide reminders when service is due. At this point, no one product on the market does all of this, but the field is progressing.

Regardless of the product selected, the most important thing is that the system monitor is installed where all who live in the home can see it, perhaps in the kitchen or near the television or computer. Ideally, it should be part of the clients’ daily life.

CLICK HERE TO Download Conergy’s Simple Stand-Alone PV System Worksheet.


Phil Undercuffler / Conergy USA / Denver, CO /


Brand Electronics / 269.365.7744 /

Carling Technologies / 860.793.9281 /

Grundfos / 913.227.3400 /

Magnum Energy / 425.353.8833 /

Maui Solar Energy Software /

Northwest Energy Storage /

OutBack Power Systems / 360.435.6030 /

P3 International / 212.346.7979 /

Rolls Battery / 800.681.9914 /

Xantrex/Schneider Electric / 604.422.8595 /

Photovoltaics: Design and Installation Manual by Solar Energy International, 2007, paperback, US $60 from Publisher / 970-963-8855/

“Solar Radiation Data Manual for Flat-Plate and Concentrating Collectors” by W. Marion and S. Wilcox, 1994, NREL Report No. TP-463-5607 /

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

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

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

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


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

Advanced Energy / 800.446.9167 /

DPW SOLAR  Booth 1133

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

DPW Solar / 505.889.3585 /

EATON  Booth 3701

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

Eaton / 800.386.1911 /


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

Ecolibrium Solar / 740.249.1877 /

FRONIUS USA  Booth 1957

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

Fronius USA / 810.220.4414 /


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

KACO new energy / 415.931.2046 /


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

OMG Roofing Products / 800.633.3800 /


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

OutBack Power / 360.435.6030 /

PANELCLAW  Booth 3331

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

PanelClaw / 978.688.4900 /

POWER-ONE  Booth 1749

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

Power-One / 805.987.8741 /

QUICK MOUNT PV  Booth 3062

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

Quick Mount PV / 925.478.8269 /

REFUSOL  Booth 1721

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

REFUsol / 866.774.6643 /


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

Renusol America / 877.847.8919 /

S-5!  Booth 1277

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

S-5! / 888.825.3432 /

SCHLETTER  Booth 1323

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

Schletter / 520.289.8700 /

SMA AMERICA  Booth 2010

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

SMA America / 888.476.2872 /

SNAPNRACK  Booth 2737

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

SnapNrack / 877.732.2860 /


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

SolarBridge Technologies / 877.848.0708 /


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

Solar Data Systems / 203.702.7189 /

SOLAREDGE  Booth 3901

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

SolarEdge / 530.273.3096 /

SOLARWORLD  Booth 1301

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

SolarWorld / 855.467.6527 /


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

Solectria Renewables / 978.683.9700 /


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

Stiebel Eltron / 800.582.8423 /

SUNLINK  Booth 2435

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

SunLink / 415.925.9650 /

TIGO ENERGY  Booth 3133

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

Tigo Energy / 408.402.0802 /

TMEIC  Booth 4025

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

TMEIC / 540.283.2000 /


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

Trojan Battery / 800.423.6569 /


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

Westinghouse Solar / 888.395.2248 /


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[Eugene, OR] DECK Monitoring has added two commercial solar thermal system monitoring packages to its existing suite of PV monitoring solutions. The new web-based products are configured for systems with either 2-inch or smaller inlet and outlet piping or with 2.5-inch or larger piping. Both packages include a BTU meter and revenue-grade monitoring of six data points: two temperature probes (cold water inlet and hot water storage tank outlet), one flow-rate meter (cold water inlet), and three current transformers (CTs) for monitoring energy use for up to two pumps and one backup electric water heater. A data acquisition and logging gateway comes standard with each package. Optional add-on components consist of energy monitoring equipment for natural gas and fuel oil backup water heaters, weather stations, display devices and interactive kiosks. Data point monitoring for additional CTs and temperature probes is also available.

DECK Monitoring / 503.224.5546 /


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