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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.

PROGRESS IN THE WEST
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.

PLANT CONTROL SYSTEM
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.

STRATEGIES FOR SUCCESS
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.

CONTACT:

Bill Reaugh / Blue Oak Energy / Davis, CA / blueoakenergy.com

Rowan Beckensten / Blue Oak Energy / Davis, CA / blueoakenergy.com

Debbie Gross / Blue Oak Energy / Davis, CA / blueoakenergy.com

David Brearley / SolarPro / Ashland, OR / solarprofessional.com

Resources

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

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

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

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

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

SCADA Providers

AlsoEnergy / 866.303.5668 / alsoenergy.com

Draker / 866.486.2717 / drakerenergy.com

Nor-Cal Controls / 530.621.1255 / norcalcontrols.net

Trimark Associates / 916.357.5970 / trimarkassoc.com

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

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

CONTACT:

Joe Schwartz / SolarPro / Ashland, OR / solarprofessional.com

PV Manufacturer Contact:

Astronergy / 415.802.7399 / astronergy.com

Auxin Solar / 408.868.4380 / auxinsolar.com

AXITEC / 856.254.9057 / axitecsolar.com/us

Boviet Solar / 877.253.2858 / boviet.com

Canadian Solar / 888.998.7739 / canadiansolar.com

Centrosolar America / 877.348.2555 / centrosolaramerica.com

ET Solar / 925.460.9898 / etsolar.com

Hanwha Q Cells / 949.748.5996 / q-cells.com

Itek Energy / 360.647.9531 / itekenergy.com

Jinko Solar / 415.402.0502 / jinkosolar.com

Kyocera Solar / 800.223.9580 / kyocerasolar.com

LG / 888.865.3026 / lgsolarusa.com

Mission Solar Energy / 210.531.8600 / missionsolar.com

Panasonic / business.panasonic.com/solarpanels

Phono Solar / 855.408.9528 / phonosolar.com

REC Group / 877.890.8930 / recgroup.com

Silfab Solar / 905.255.2501 / silfab.ca

Solaria / 510.270.2500 / solaria.com

SolarTech Universal / 561.440.8000 / solartechuniversal.com

SolarWorld / 503.844.3400 / solarworld-usa.com

Sonali Solar / 888.587.6527 / sonalisolar.com

Suniva / 404.477.2700 / suniva.com

SunPower / 408.240.5500 / us.sunpower.com

Ten K Solar / 877.432.1010 / tenksolar.com

Trina Solar / 800.696.7114 / trinasolar.com/us

Upsolar / 415.263.9920 / upsolar.com/usa

Vikram Solar / vikramsolar.com

WINAICO / 844.946.2426 / winaico.com

Yingli Solar / yinglisolar.com/us

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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 / aurorasolar.com

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While the US solar industry fielded systems at an unprecedented rate of 1 MW every 32 minutes in Q3 2016, SEIA and GTM Research will undoubtedly announce a new record pace for Q4. At the same time, average system prices are falling quarter-over-quarter and year-over-year. These data suggest that profitable solar installation companies are continually finding ways to work more efficiently and effectively. We asked business operations experts at four successful solar companies to share their strategies for working smarter rather than harder.

Lean Management Systems Address Need for Speed

By Chris Anderson, Borrego Solar

Borrego Solar is an EPC firm with operations in California, Massachusetts and New York that focuses on commercial and utility applications. The company added O&M services in 2015 and an energy storage division the following year. Since co-founding Borrego Solar in 2003, Chris Anderson has served in a variety of operations, engineering and executive leadership roles. As senior vice president, he works to drive down operational costs without sacrificing quality.

Borrego Solar is one of the oldest solar installers in the country and prides itself on responsible, sustained growth. The ever-changing market dynamics that define the solar industry, which industry insiders refer to as the solar coaster, make it challenging to achieve sustained growth on both a company and a market level. However, 2016 marked Borrego’s eighth consecutive year of profitable growth.

Shifting regulations are the largest hindrance to solar business growth, as they can quickly change project economics or create market gaps while programs transition from one regulatory structure to the next. While this reality is not ideal, management- and operations-level improvements have allowed us to maintain profitability, even when faced with declining incentives. We also work hard to identify new business opportunities and value streams. A recent example is the rise of virtual net energy metering (VNEM) and community ownership models, which are driving solar adoption in a massive way in some key markets.

Incentive Program Challenges

Utility incentives, tariff structures and policies—most notably, net energy metering—have been instrumental in the growth of the solar industry. But it is challenging for solar EPCs and developers to navigate and track program changes, incentive declines and policy differences from state to state and utility to utility. When administrators change incentive programs or regulators change tariffs, it is akin to a referee moving the goalposts.

Borrego Solar has successfully navigated changing market conditions by focusing on the projects furthest along in our pipeline, taking a disciplined approach to the projects that we aggressively invest in, and understanding how investors can best monetize incentives. We are also always adapting to the environment. Our development team might be pursuing 6 MW ground mounts one year and 650 kW midscale utility projects the next. Then it might move on to commercial rooftops, municipal landfills or school carports before cycling back to large-scale ground mounts.

Gaps between incentive programs affect both the front and the back end of the project cycle. Once a program goes live, there is typically a rush to secure the incentive funds or project capacity in the interconnection queue. On the back end, there is invariably pressure to achieve mechanical completion or obtain formal permission to operate prior to a certain deadline.

Arguably, declining incentives are a good thing because these force us to look for more cost-effective ways to deploy PV systems. However, this also means that everyone is rushing to get as many projects installed as possible prior to the program deadline. This tends to increase the risk for error and raises safety concerns. As deadlines approach, greater competition for engineering or construction resources means that the industry suffers from a shortfall of experienced companies to do the work, which increases prices from those companies that can execute. Partially completed projects often need reworking later, which is not an ideal workflow.

Management-Level Improvements

To navigate the regulatory environment in each market separately while working to scale the business, we’ve turned to the lean management approach and 4DX principles outlined in the book The 4 Disciplines of Execution: Achieving Your Wildly Important Goals by Chris McChesney, Sean Covey and Jim Huling. Specifically, we’ve incorporated the lean management method of value stream mapping (VSM) to define our current state and design a future state for the process of moving from site identification to closeout with the various customers.

VSM has proven critical in aligning our staff on the project flow, key milestones, process and lead times required to bring a project to fruition. The maps enable our company leadership and frontline execution teams to more efficiently discuss the strategic direction of projects, as well as to identify the real problems we need to solve to move projects forward quickly. We create maps for greenfield development, on-site power purchase agreements and on-site EPC projects, and then overlay the associated critical IT tools and high-level authority matrixes.

In addition to utilizing VSM, we’ve implemented parts of the A3 problem-solving process, which seeks to identify, frame and act on problems. Our managers and executives participate in an annual strategic planning process to clearly identify the most pressing initiatives for the coming year. We use the A3 process to better understand the problems associated with each initiative and to communicate both the current state and the desired future state of initiatives to stakeholders. Since many employees are not experienced in lean-management principles, we also train our managers to coach rather than participate as player coaches.

The four disciplines of execution that make up the 4DX system include focusing on a wildly important goal, acting on lead measures, keeping a compelling scorecard and creating a cadence of accountability. These 4DX management principles have helped us apply countermeasures and execute on identified goals. They provide a team-approach structure that we can use to implement changes identified during our A3 problem-solving sessions.

Managing our portfolio and target markets in response to incentive changes is a major focus for our development team. Therefore, we need to provide our developers with a clear path for advancing projects internally. The process blocks in our value-stream maps provide this structure, which incorporates key “go or no-go” reviews. As a project matures, our finance, engineering, operations and, eventually, contracts committees review it. This disciplined approach is how we make timely decisions about where to invest resources.

Operations-Level Improvements

Borrego Solar is not a manufacturer. We need to source modules, inverters, racking, combiner boxes and data-acquisition system equipment for our projects. We use a cross-departmental product approval process to expand our product mix over time. This process allows us to sort through commercially available products and identify those that fill a gap in our offerings, address a changing code requirement or provide a better value for our customers while meeting our standards for quality. As part of this process, our engineering and operation teams work closely with our partners and prospective vendors to highlight and push for value-added features within these products.

To combat an increased risk of error on the project level in both design and execution, we have created and implemented design standards, a design review process and an engineering site inspection process. We have also identified our preferred set of design applications. Design and applications engineers use these standards and guidelines to quickly develop and iterate designs, while controlling and maintaining high standards for quality set by our professional engineers.

Several software platforms are key to our operational improvements. HelioScope (helioscope.com) allows us to quickly generate preliminary production models and designs. We use Helios 3D (helios3d.com) in conjunction with other CAD software to develop our plan sets. PVsyst (pvsyst.com) generates our final production models. Bluebeam (bluebeam.com) supports our design review collaborations. We use Smartsheet (smartsheet.com) to coordinate the release of plan sets, schedule design reviews or site inspections, and otherwise manage collaborations and workflow. Over time, we have set up and refined internal procedures and standards around these software tools.

Standardizing our designs and the tools we use has also been beneficial for our outside partners. When we need to use third-party engineering services, we can control for quality and ensure that there aren’t disparities between in-house and third-party designs. This allows us to scale when demand swells. Given the dynamic nature of project schedules, we want to keep everyone’s schedule aligned. Therefore, we are starting to use Smartsheet to share our project schedules with subcontractors in real time. Our investors also appreciate that our design and production modeling process is transparent and consistent, as this gives them confidence in their projected returns.

One issue we have found with our model of acting as the EPC firm and hiring subcontractors is a lag in incorporating labor savings into bids. Manufacturers are value-engineering their products to reduce the overall installed cost. In some cases, this means they add features that reduce field labor by speeding up installation. Despite these changes, and our value-engineering efforts in design, we find that most electrical subcontractors rely heavily on past performance when bidding and use dollars per watt as the metric for measuring their bid. We have had some success reducing field labor costs by taking time to meet with prospective estimators, foremen and project managers as part of the subcontractor bid process. We let these stakeholders review our designs, call out product changes and discuss revised design standards; we also point out certain installation items that might scale based on dollars per module rather than dollars per watt.

In some cases, we have tried shifting work from electrical subcontractors to our racking vendors to capture potential savings associated with new products. Where labor rules allow nonelectricians to build mounting systems and hang modules, racking vendors can provide their own crews and laborers to perform this work. Where the rules require electricians, racking vendors can take on the task of hiring electrical subcontractors to perform the work and meet the predicted installation timelines. In some cases, racking manufacturers have had success installing their own products per our contractual expectations. In other cases, they have significantly underestimated the difficulty of the work, and we have had to rely on our master subcontract agreement to insulate us from their cost overruns.

VNEM and Community Solar

The advent of virtual or remote net metering and community solar is a welcome contrast to declining incentives. These programs allow us to optimize projects, host customers and owners by siting projects in locations that result in the most favorable rates and overall economics. It requires many different skill sets to identify host sites and off-takers, to understand and communicate the value proposition, and to negotiate terms.

To address the challenge of working with three different customers—project owner, host and off-taker—we have compartmentalized who takes the lead in each of the transactions. For example, some project developers exclusively look for sites, while others look for off-takers. As our team has gained experience and we have refined our processes, our project developers have become proficient in handling these three customers and their associated transactions. We have also established a vetted group of affiliates and partners who bring us sites and off-takers.

Since working through EPC and O&M contracts is a significant legal investment, we have focused on building out the relevant teams to strengthen relationships and foster expertise. Our project finance group manages relationships with the investment community and negotiates the EPC and O&M contracts. Our finance group focuses on the owners to understand the way they model project risk and returns, as well as establishes the personal relationships it sometimes takes to get deals done. Meeting our contract obligations and delivering a quality product allows us to leverage that investment and transact again with the same buyer.

As we move forward in 2017 and continue to scale our business, we are continuing to analyze our performance, modify our value stream maps and find ways to reduce costs. In our development work, we are identifying areas where we can obtain site discovery without running a considerable risk of overspending. In engineering, we are working to reduce our process and lead times for generating plan sets. In operations, we are trying out a model with some of our trusted electrical subcontractors in which we award the project early and work collaboratively to incorporate their constructability feedback into our design. Our hope is to design easier-to-build systems and reduce the contingencies that our subcontractors carry in their bids by folding them into the planning process. Across the organization, we are focused on driving down our cost per first-year megawatt hour.

While our maps, processes and software provide a foundation for our business and help us quickly meet changing market dynamics, these systems remain works in progress. At the end of the day, it is people who apply these tools and principles. We are successful because our employees strive to meet policy-driven deadlines, improve continuously, deliver a quality product and accelerate the adoption of renewable energy.

Biomimicry and Meeting Rhythms Promote PEACE

By T.J. Kanczuzewski, Inovateus Solar

Inovateus Solar has become one of the leading solar development, design, engineering, procurement, construction and supply companies in the Midwest. Headquartered in South Bend, Indiana, the company has developed and built solar projects for utility, rural electric cooperative, commercial, industrial, governmental, educational and microgrid customers in the US, the Caribbean and Latin America. A founding staff member of the company, T.J. Kanczuzewski has been with Inovateus Solar since 2007 and serves as its president.

Like many solar companies, Inovateus has experienced remarkable growth over the last few years. We have recently completed or are close to completing more than 100 MW of commercial and utility projects, have become the part owner of a solar power plant that we helped develop and build, and have seen our supply and distribution business flourish. However, along with experiencing rapid growth, we’ve learned some hard lessons about managing our increasing responsibilities while properly serving our customers and remaining profitable.

To accomplish what we have recently achieved and successfully meet our ambitious goal of becoming a leading national developer, we have had to change our organizational and operational structures. As a people-first workplace that is adding new as well as veteran solar industry staff, we face the challenge of maintaining our friendly corporate culture while adapting our company to competitive new market realities.

By continually looking to improve our organization, we are not only more effective but also more cooperative and focused on our day-to-day goals for building projects as well as our long-term goals of sustainably and profitably expanding our business during the ups and downs of the solar coaster. A variety of sources have inspired or led to the development of the following business management tactics. These include lessons that we have adapted from invited speakers at our weekly solar “think tank” sessions, books that I have read, examples from the natural world, and seminars that I and other team members have attended.

Truly Believing Our Core Values

Inovateus has won two “Best Place to Work” awards in Indiana, and one of the reasons we’ve earned these honors is that our team truly believes in our core values. Having everyone remember those values and act in alignment with them keeps us all focused on the long term when short-term problems get in the way.

We like to use acronyms at Inovateus. First, there’s PEACE, which stands for passion, engagement, ambition, creativity and esprit de corps. We’ve also adopted a rallying cry: building a brilliant tomorrow. These company mantras are not just something we pay lip service to—we live them. They’re truly a part of our business mindset with customers and within our internal Inovateus culture.

For example, in 2015 we landed our first large-scale contracts, including a 58 MW project, currently in its final construction phases, in Lapeer, Michigan. We had a successful sales-centric operation, but feedback from some customers and our own staff informed us that we could make our processes more efficient. We realized that we needed to create structures that largely did away with departmental silos and to implement an organizational plan that encouraged participation and greased the wheels of internal communication. And, importantly, we had to tighten up our execution.

Because our team members believe in PEACE, it was a lot easier for us to step back and avoid pointing fingers. Instead, we focused on fresh ideas to increase cooperation and efficiency.

Business Biomimicry

One of the things we’ve done is create what we call PODs for each project. These are unified, inclusive cross-disciplinary teams. Our inspiration for PODs came from diverse sources. For one, we applied a feature from the natural world, namely how dolphins and other wild creatures live and work together (hence the name). We also borrowed ideas from retired US Army General Stanley McChrystal’s book Team of Teams and his experience with breaking down operational structure gaps in the military and making groups “faster, flatter and more flexible.” In a sense, the POD is our biomimicry-influenced team of teams.

Although we didn’t originally intend to do so, we’ve embraced biomimicry as a way to rethink processes. We consider Inovateus a living organism that is in continuous growth and improvement mode. As a result, the PODs have evolved. We’ve recently implemented POD 2.0, which strengthens and adapts the POD structure to be more inclusive of other personnel in project execution. In addition to using more concise and easily measurable agendas for each POD’s weekly meetings, we saw the value of adding more input from finance and business development folks on the front end of projects, more participation from purchasing and logistics during primary construction periods, and more robust closeout management between substantial progress and final completion.

Utilizing Consistent Communication

We also use the concept of meeting rhythms at Inovateus, something we picked up from one of our mentors, Verne Harnish, who wrote the book Mastering the Rockefeller Habits. He stresses the importance of maintaining consistent patterns and structure, and of creating a “habit platform” for consistent communications within an organization. In this way, everyone can get in tune with each other. (We also use musical terms and slang in our company, as many of us—myself included—are musicians.)

The meeting rhythms at Inovateus include the weekly POD meetings, daily huddles among the three core internal corporate groups (projects, strategy and capital), weekly 30-minute leadership team meetings and monthly company meetings. The daily huddles each take about 10 minutes and focus on the top five goals for the week and other issues. They offer an opportunity for anyone to ask for help, provide updates on a project and so forth. The huddles take place first thing in the morning so that by 9am everyone has communicated whatever they need to with all the team members who need to know.

Growing Efficiently

We understood that we had to grow efficiently if we were going to meet our goals and fulfill our vision. We realized that not every solar project was right for our company, so we developed another acronymic and biomimicry process we call TREE, which stands for the renewable energy engine. TREE is our mechanism for identifying, vetting and bidding on new projects for our pipeline. After all, project proposals are the seeds for the company’s future, and we want to plant as many healthy seeds as we can while weeding out the unhealthy ones that could hamper our growth.

TREE has five stages or branches, starting with an “RFP machine” concept. From the beginning of project evaluation all the way through the project proposal submission process, we use a “go or no-go” filtering method to continually assess the opportunities at every stage. The first TREE evaluation step identifies potential projects and then adds data inputs in our proprietary software to establish the initial go or no-go status. Then we conduct a preliminary EPC evaluation and go or no-go analysis, followed by a sales step in which senior account executives analyze the vetted projects and initiate conversations with customers. If it’s a go at this point, we take a deeper dive with the customers and complete the preliminary engineering designs and budgets. Finally, if the green light is still shining bright, we put together and deliver our project proposals.

These tactics and strategies may seem simple or perhaps unconventional for your solar business. However, I urge you to examine your own organizational structures and consider adapting these or other creative practices to take your company to the next level.

Cooperative Approach Transforms Energy and Business

By Amanda Bybee, Namasté Solar

Namasté Solar is an employee-owned cooperative (with offices in Colorado, New York and California) that designs, installs and maintains solar electric systems throughout the US for commercial, nonprofit, government and residential customers. Amanda Bybee has worked in the solar industry since 2003, first promoting renewable energy policies at Public Citizen’s Texas office, then with Meridian Solar and now with Namasté Solar. Today, Bybee devotes her energy to strategic planning, corporate governance and incubating new start-up cooperatives.

In 2016, Namasté Solar installed nearly five times the number of megawatts as in 2013. In the same time frame, our revenue tripled and our head count doubled. We have expanded our geographic footprint beyond the borders of Colorado to the Northeastern US and Southern California, and pursued creative solutions to some of the challenges by incubating new cooperative enterprises. Some positive trends have buoyed our progress, including falling equipment prices, state incentive programs, easier access to capital, amazing new team members and the demand generated by the threatened ITC expiration. Other challenging market conditions have hampered us, including increased competition, especially from large national companies; decreasing utility incentives; an unstable legislative and regulatory environment; decreasing average selling prices; and shifting trends in project finance.

Specific Strategies

Throughout our growth, we have developed strategies around financing, labor, procurement, operational processes and safety.

Financing. We have cultivated partnerships with commercial financiers who have both the capacity and the expertise to make projects run smoothly. We are co-founding a new financial institution, the Clean Energy Federal Credit Union, entirely dedicated to funding clean energy by providing affordable loans to its members on the residential scale for all forms of clean energy and energy efficiency.

Labor. Attracting and retaining the right staff is critical to our success, and we put a lot of effort into this area. When the construction market rebounded in 2013–14, it put a strain on the workforce, and we found it more difficult to hire qualified labor. Competition for good workers drove up wages, especially for licensed electricians, which in turn necessitated an overall recalibration of pay rates throughout the company. In addition, as we have branched out into new states, we have encountered state-specific labor laws that require different compliance. We have developed comprehensive internal training programs, holding in-house NABCEP classes and on-the-job training, to build up our farm team, so to speak. Developing our workforce in-house helps with succession planning for crew leads, project management and other roles.

Procurement. We have found certain benefits in operating at scale: redundancy, resilience, more internal growth opportunities and greater purchasing power. We have sought to further scale our purchasing power via the Amicus Solar Cooperative. Through it, we aggregate our buying power with 40 other member companies in North America and leverage that volume to achieve lower prices on major equipment. Amicus has also evolved into a helpful peer group, where we share best practices, partner on new business endeavors and find support in addressing business challenges.

Operational processes. To scale efficiently, we have focused on refining our internal processes and making them replicable. For example, when we want to add another residential crew, we know exactly what to do, including what vehicle we need, how we will build it out and how to stock it. We know which people are ready to assume leadership of that crew and how long it will take the crew to reach full productivity. The process of adding a crew now follows a well-known formula, which makes planning for expansion a less daunting task.

We look to better processes, improved technology and new providers to make our work flow more easily. On the commercial side of our business, we continue to refine our remote site management and build strong relationships with subcontractors while leveraging relationships with other members of the Amicus Solar Cooperative. On the residential side, we employ a kaizen mentality of constant improvement, making small adjustments to our processes so they are ever easier to accomplish. For example, in Colorado alone, we work in more than 50 different jurisdictions, each with its own requirements and code interpretations. Given that complexity, we want to build more automation into our IT tools to streamline our compliance.

Safety. Safety has become a companywide focal point, both as a function of training so many new employees and as a result of increased scrutiny from OSHA and inspectors. We now have a dedicated safety team that maintains vigilance over our practices, provides more-professional documentation, procures all safety-related equipment and generally deepens the company’s commitment to an abiding culture of safety. Over the coming years, we will continue to seek the right balance between pushing for efficiency and ensuring that our crews can perform work safely.

Employee-Owned Model

It bears mentioning that Namasté Solar is an employee-owned cooperative. We believe strongly in the employee ownership model, as it creates a deep sense of caring and investment in the work that we do. It also raises the confidence of our customers that the people responsible for their projects have a true stake in the outcome. We have seen many advantages to this model—and some disadvantages—as we’ve scaled and streamlined through the years.

With regard to decision making, for smaller-scale decisions that fall within a person’s job scope, we generally empower co-owners to make decisions on their own. We expect them to take initiative where needed, think long-term and require minimal management. For instance, commercial project managers have visibility into the big picture of a project (financial, relationships and so on), and can execute change orders with minimal bureaucracy. We have seen throughout the organization that this creates a sense of empowerment and trust that raises morale and increases loyalty, ultimately leading to lower attrition. That said, it sometimes takes us longer to make companywide decisions, because we strive to include as many voices as possible along the way.

We also accept certain trade-offs based on our corporate model. After all, the time we spend in meetings is time we’re not on the roof installing panels. However, we believe that the holistic benefits outweigh the costs. As a result of our discussions, co-owners are more educated about the state of the industry, more engaged in the outcomes of our decisions and generally feel more connected to each other. This leads to deeper job knowledge and general empathy for fellow co-workers. It’s all about balance, and we strive to find the right level of engagement and involvement without sacrificing efficiency and productivity along the way.

At Namasté Solar, we pay as much attention to how we do it as to what we do. We’re here not only to transform energy, but also to transform business. And the more effective we are in one arena, through achieving greater scale and having an impact on more people, the more effective we will be in the other.

Leveraging Technology to Fulfill a Shared Mission

By James Hasselbeck, ReVision Energy

ReVision Energy, founded in 2003, installs more solar in Maine and New Hampshire than any other integrator. The company designs, engineers and installs all of its systems using in-house solar specialists with proper licensure and an equity stake in the company. James Hasselbeck joined ReVision Energy in 2013, and oversees design, project management and commissioning for all construction operations for the Maine and New Hampshire installation teams. Hasselbeck is a NABCEP Certified Installation Professional and a member of the NABCEP PVIP Technical Committee.

In most of the years since its founding, ReVision Energy has seen a year-over-year growth of 20% or more. As all solar veterans understand, achieving a 20% revenue growth in an environment where costs are declining rapidly actually means that everything else—such as project volume and capacity—is scaling even faster. Sustained rapid growth is typically a good problem to have, but it comes with its share of challenges. Along with that growth comes the need to hire exceptional talent for sales, installation and support roles. Growth also forces installation companies to purchase new trucks and equipment and to increase warehouse capacity.

At ReVision, the fact that we’ve grown to operate out of five offices in three states has amplified these scaling challenges. Our business does more than just install rooftop PV. Our basic mission and challenge is to provide comprehensive, carbon-free and cost-effective energy solutions to diverse clients, which include residential, commercial, industrial and community solar customers, as well as those requiring energy storage, electric vehicle charging infrastructures, or the installation of solar-powered heat pumps for heating, cooling or domestic hot water systems.

Shared Mission, Values and Goals

As a Certified B Corp, ReVision Energy has always considered its explicit commitment to multiple groups of stakeholders an asset, not a liability. While many view B Corps or socially responsible business practices as inherently concessionary in terms of financial success, we explicitly reject this view and believe that we succeed because of our values, not in spite of them. As a result, one of the first and most critical components of managing our growth has been to ensure that we never dilute the shared sense of mission and values that binds the company together. Ensuring that we maintain our company culture of respect, legendary customer service and technical excellence while physically spreading across five offices and expanding the size of the team 30% or more in a single year can be a real challenge and certainly doesn’t happen on its own.

Our first strategy to manage this scenario is simple: hire only exceptional people who share our values. By hiring and retaining extraordinary individuals, we have kept employee turnover near zero, which creates a solid institutional memory and foundation upon which to scale and build additional crews.

A second strategy is to deliberately and consistently articulate the company’s shared mission, vision and values. We use every opportunity that we can, internally and externally, to discuss our broader mission and to demonstrate our values. This is the lens through which we approach and discuss everything that we do. Having that language and belief in common creates a strong sense of cohesion for the rapidly expanding group.

Using Technology to Stay in Touch

Beyond taking a very deliberate approach to maintaining a strong and coherent company culture and targeted business goals, we employ several more-concrete tactics to manage the growing business. Many of them relate to leveraging technology to ensure that our team can stay connected and on the same page while running in opposite directions across multiple states.

salesElement. Like many small local solar companies, we started out using a customized Microsoft Excel spreadsheet for pricing projects, and then transferred these prices and key project details into a Microsoft Word template to generate customer proposals. As we achieved some scale, we found that system unsustainable and investigated the proposal generation software platforms specifically targeting the solar installer market. While many had some impressive features, none was capable of pricing and producing proposals for the broad variety of project types that we design and install across a range of different markets. In addition, we were skeptical about giving up design control of the proposal document and ending up with a result that would look more or less like every other solar proposal our clients might see.

The solution we landed on was salesElement (saleselement.com), a cloud-based pricing and proposal generation platform with a specific implementation that we highly customized for our business. The software interfaces with our customer relationship management (CRM) and inventory software to capture customer and component pricing information; this allows the platform to work as both a pricing engine and a proposal generation tool. It is capable of generating highly customized proposals. Though building this custom tool required a substantial financial and labor investment, it has proven to be amazingly flexible and scalable as our business has grown and our product mix has evolved.

Basecamp. Another tool we use to facilitate communications and information sharing is Basecamp (basecamp.com), a cloud-based project management and internal communications platform. We have a number of Basecamp projects geared toward different departments, employee groups and goals. We also utilize Basecamp’s to-do list functionality to maximize productivity for our different teams. For example, we have a centralized system for designing and estimating commercial projects. Using Basecamp, a commercial sales representative can assign a new project to the engineering team. Depending on the desired turnaround time, that design may or may not come from the branch where the sales person is physically located. From our perspective, this system provides the benefits of both centralized and decentralized engineering team approaches. On the one hand, our engineering team can share the workload for maximum productivity; on the other, our branches all benefit from local engineering support, which requires in-person communications.

Egnyte. With so many crews and projects going on, the ability to quickly find relevant information—be it a system proposal or job photograph—is important. For this functionality, we rely on Egnyte Enterprise File Sharing (egnyte.com), which provides access to our server data from anywhere. The platform is easy to use and navigate via smartphone or laptop and is a great way to search for, upload or download information. One benefit of this platform is that it enables our installation crews to immediately upload job photos or permit signatures to the server while on-site; this allows the operations team back in the office to submit utility paperwork the same day we complete an installation, without getting bogged down by the need to physically transfer data.

Company wiki. We use a wiki in Basecamp to outline our internal resources and share process diagrams and flowcharts. A key part of streamlining operations is enabling different people and departments, potentially in different locations, to work together, while ensuring that they accomplish all critical steps with minimal overlap. While we have worked hard to standardize processes and streamline installations, we also needed to maintain a degree of flexibility that would allow for a regionally specific focus. In other words, our back-end systems and processes are critical, but just as important is the ability of those systems and processes to match the unique local demands and requirements of each of our market segments.

A key advantage of using a wiki is that it allows us to embed links in our diagrams. For example, our commercial, institutional and industrial teams consist of representatives from multiple departments. To provide a clear path of responsibilities as our projects progress, we have developed flowcharts that not only outline the step-by-step process, but also provide hyperlinks for some milestones that take users to relevant Basecamp or wiki resources.

Weekly newsletter. Our multiple-location operational structure makes it difficult to maintain group culture and connectivity, as well as share success stories. Therefore, we have instituted shop-specific weekly newsletters with the goal of sharing our many victories, however small they may seem. In addition to letting everyone know what is going on, we strive to use this forum as another opportunity to highlight our mission and values, to inspire conversations about best practices and to recognize team excellence publicly.

Performance metrics. The final, and perhaps most critical, piece of our company initiatives for efficient streamlined growth is identifying and leveraging key performance metrics. ReVision Energy is a data-driven company. All of our system design, installation and business decisions are fact- and science-based. We pull metrics from our CRM database and use these to generate customizable charts and reports. At any given moment, we can review our new project leads for the month; conversion efficiency; sales closing ratios; projects under contract, awaiting design, permit and interconnection approval; procurement; and ultimately scheduling status. Measuring, reviewing and acting upon these and other metrics is crucial, as it can show—in no uncertain terms—where we need to put additional focus.

CONTACT:

Chris Anderson / Borrego Solar / Lowell, MA / borregosolar.com

Amanda Bybee / Namasté Solar / Boulder, CO / namastesolar.com

James Hasselbeck / ReVision Energy / Exeter, NH / revisionenergy.com

T.J. Kanczuzewski / Inovateus Solar / South Bend, IN / inovateus.com

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[San Francisco] Spruce is expanding its national network of solar integrators, building contractors and other channel partners to provide consumer financing for residential PV systems and home efficiency improvements. The firm was founded in 2015 with the merger of Clean Power Finance and Kilowatt Financial. Spruce offers white-label products that include solar leases and power purchase agreements as well as solar loans. It currently offers its Spruce Solar Loan product in 25 states and makes it available for single-family residences as well as townhomes, condos and duplexes. The online SpruceFlow portal is designed for mobile devices and allows outside sales teams to generate a proposal, run e-credit and get an e-signature from the homeowner on-site. To further support residential solar integrators, Spruce offers its SourceDirect equipment-purchasing program, which provides integrators with an alternative to carrying the up-front equipment cost for financed projects.

Spruce Finance / 866.525.2123 / sprucefinance.com

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[Clifton Park, NY] The North American Board of Certified Energy Practitioners (NABCEP) is hosting its annual Continuing Education Conference March 21–23 at the InterContinental Dallas hotel in Dallas, Texas. Attendees can earn up to 20 hours of continuing education credits. This year’s event schedule includes 32 technical training sessions, 16 panel sessions and over 60 solar equipment and service exhibitors. Sponsors of the 2017 event include BayWa r.e., ProSight, APsystems, Intersolar, Mitsubishi Electric, Rolls Battery Engineering, CertainTeed, Fronius USA, OutBack Power, Trojan Battery, Unirac and Yaskawa–Solectria Solar.

NABCEP / 800.654.0021 / nabcep.org

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Though life is never boring on the Solarcoaster, the start of SolarPro’s tenth calendar year seems especially eventful. It is the start of a new year, of course, as well as the start of a new administration in Washington, DC. Adding to the excitement, the 4-year presidential term just happens to coincide with the 3-year National Electrical Code development cycle. This means California has finally adopted NEC 2014, and Massachusetts and others have leapt boldly into NEC 2017.

To celebrate and reflect upon the confluence of all of these milestones and transitions, we decided to reach out to some of the solar industry’s best advocates and brightest stars to get their take on the current state of the solar industry. Against a backdrop of what at times may feel like an ever-revolving series of new challenges, many of these experts project that the US solar industry will continue to make big gains. As a Nobel Laureate in literature once said: “For the loser now will be later to win, for the times they are a-changin’.”

Solar Energy Industries Association (SEIA at seia.org)
Dan Whitten, vice president of communications

As the national trade association in the US, SEIA represents all organizations that promote, manufacture, install and support the development of solar energy. SEIA works with its 1,000 member companies to expand markets, remove market barriers, strengthen the industry and educate the public on the benefits of solar energy. Dan Whitten was previously an energy reporter for Bloomberg News and Platts, and is now SEIA’s vice president of communications, overseeing all of its internal and external communication efforts.

Which developments or events in 2016 had noteworthy positive impacts on the US solar industry?

This was a landmark year for the solar industry on a number of fronts. We celebrated policy successes in several states, from Massachusetts in the north to Colorado in the west and Florida in the south. In each of those states, voters or policy makers took action to expand potential markets for the solar industry. We also marked an incredible milestone—1 million solar systems installed in the US—and we’re already rapidly accelerating toward 2 million. In 2016, prices continued to decline, making solar a cost-effective option for a growing number of Americans. We also saw solar jobs grow to an impressive 209,000 strong.

What event stands out as having had a negative impact on the industry?

The Nevada Public Utilities Commission’s decision in early 2016, which changed the state’s net-metering rules and rates, was a tough pill to swallow. We saw thousands of people lose their jobs and rooftop solar applications plummet due to a dismal policy decision. In September, the commission reversed its initial stance on grandfathering and adopted regulations that protect the investments of NV Energy customers who installed a solar system or submitted an interconnection request prior to December 31, 2015

What are SEIA’s priorities as we move into the new year?

It’s vital that we continue our education efforts so those in office fully understand the benefits—both economic and environmental—that solar energy provides our nation. You will see us continue to push for pro-solar policies in a number of states. We expect to work in close collaboration with state affiliates and other interested groups toward priorities that make a difference to all of our members.

In Washington, DC, there will be a large number of new policy makers in the executive and legislative branches. It’s going to be increasingly important that we expand our education efforts and demonstrate that communities all over America are seeing increased jobs and more economic activity, thanks to the burgeoning solar industry.

We also will continue to advance and expand our efforts in codes and standards, PV recycling, consumer protection and solar energy finance. We are aiming these particular efforts at establishing a strong base on which to grow the solar industry.

What is SEIA’s current membership profile? Has it changed notably in recent years?

As the industry has matured, our membership has grown increasingly diverse. Our member companies consist of installers, project developers, manufacturers, contractors, financiers and nonprofits. Going forward, lines are going to start to blur, especially as community solar and commercial projects expand.

How does SEIA balance initiatives to support what may be competing interests among its various member groups?

SEIA represents all sectors of the solar industry, whether they be utility scale or distributed generation, and those lines are starting to blur. It’s true that there is intense competition in our industry among companies.

However, we are stronger together than apart, and we will continue to fight vigorously for policies that advance the entire solar industry, to the benefit of all of our members.

What recent state-level solar policy efforts have been particularly effective or notable?

California’s January 2016 decision extending net-energy metering (NEM) through at least 2019 was a big step for us, and we were proud of the role we played in providing expert witness testimony and advocacy. In New York, we have worked with a coalition to maintain net metering for rooftop customers until 2020; establish fair, value-based compensation for larger solar projects; and establish a community solar market in the state.

The defeat of the deceptive utility-backed Amendment 1 in Florida was also extremely notable. It let our detractors across the country know that while we might not have their bottomless bank accounts, public support is on our side. The resounding rejection of Amendment 1 should send a message across all states that you cannot curtail solar choice.

Smart Electric Power Alliance (SEPA at sepapower.org)
Julia Hamm, president and CEO

Created in 1992, SEPA is an educational nonprofit founded to help utilities deploy and integrate solar, storage, demand response and other distributed energy resources. Its current 1,000 members include utilities, independent system operators, large energy users, corporations and nonprofits. As the president and CEO of SEPA since 2004, Julia Hamm has 15 years’ experience advising and collaborating with utilities, manufacturers and government agencies on renewable energy and energy efficiency strategies and programs.

What recent developments have had positive or negative impacts on the US solar industry?

Certainly, a core issue that has dominated the news and minds of many in our industry has been the ongoing state-level discussions about rate reform and net metering. On the negative side, some of these discussions continue to be framed as a basic conflict between the solar industry and utilities, and some utilities continue to be viewed as anti-solar, even as they interconnect thousands of new solar rooftops and add new utility-scale or community-shared solar projects to the grid. On the plus side, we are also seeing more negotiated settlements in these cases—for example, in Colorado, Minnesota and Montana—as a result of active efforts to engage all industry stakeholders in the process. And in some instances—most notably in Hawaii—we are seeing that, given specific market economics, a change from retail rate net metering does not automatically mean that the solar market nosedives. The fact is, solar has become a mainstream source of power generation that when smartly deployed will increasingly offer benefits to customers, utilities and the grid; prices will continue to drop; and rate reform will be part of that evolution.

As we enter 2017, what initiatives is SEPA prioritizing?

In the past year, SEPA has rebranded from the Solar Electric Power Association to the Smart Electric Power Alliance. This reflects our expanded mission to echo the evolution of the solar industry itself, from its initial focus on solar deployment and market growth, to a wider view encompassing a range of distributed energy technologies, such as storage, demand response and electric vehicles. We have also stepped up our research with our Beyond the Meter series, which focuses on the grid integration of distributed technologies. In the coming months, we will release reports on microgrids, distributed resource planning and electric vehicle charging. Our 51st State Initiative has produced strategies and a recognized, effective process for market transformation. In the coming year, we hope to see one or more states adopt this model as the foundation for their own market evolution.

How has SEPA’s mission evolved over time?

Our most recent rebranding is not our first. We were originally called the Utility Photovoltaic Group, or UPVG. Our new name, Smart Electric Power Alliance, allows us to build on a brand with wide recognition in the industry and continue to grow. We are proud of our history and remain dedicated to helping utilities make smart solar decisions. We want to become a platform for all industry stakeholders, a place where they can share diverse views and ideas, and find the collaborative new solutions that are needed to reframe the narrative of our industry. The expanded scope of our mission directly addresses the challenges of solar integration on the grid and the role of distributed technologies in ensuring that solar continues to thrive.

The growth of community solar is in part a result of the industry’s customer-centric focus, and SEPA continues to play an active role in helping utilities design these shared solar programs. However, the process of change is uneven and uncomfortable; both utility and solar industry business models will likely continue to evolve. The research, collaborative processes and market transformation models SEPA has developed and supports are all aimed at ensuring that even as these important and necessary changes unfold, our energy markets remain vital and provide real benefit— economic, environmental and social—for all.

Many of your members are utilities. How would you compare utility perspectives on energy storage versus solar assets?

In the bigger picture, utilities are increasingly seeing solar, storage and other distributed technologies as potential grid assets. We are seeing many utilities launching solar-plus-storage pilots to test out how to optimize these technologies to provide both customer and grid benefits. At the other end of the spectrum, rooftop solar has been a challenge for some utilities primarily because they cannot see or control behind-the-meter assets and the impacts these technologies may have on local distribution systems. Cross-industry collaboration and partnerships are beginning to offer potential solutions to this challenge. For example, SEPA recently partnered with Nexant on a report laying out a practical model for calculating the locational value of solar and other distributed technologies, which is a critical need for integrating distributed energy resources in utilities’ distribution resource planning processes.

As the industry scales, how would SEPA like to see rate design and market opportunities for DERs evolve? What changes might best align our policies to ensure maximum stakeholder benefit?

As an educational nonprofit, SEPA does not promote or endorse any one approach or strategy for rate design, but we have laid out basic doctrines, structures and concepts for market transformation that actively involves all stakeholders. As detailed in our recent report, Blueprints for Electricity Market Reform, the four basic doctrines are: promote efficiencies; clearly define roles; identify principles of rate making; and foster customer choice. The four concepts that grow out of those doctrines are flexibility, incrementality, affordability and transparency, or FIAT. FIAT can be an extremely effective tool in helping ensure that stakeholders are focusing on real, actionable and meaningful transitions for the industry.

Amicus Solar Cooperative (amicussolar.com)
Stephen Irvin, president

Amicus Solar Cooperative, founded in 2011, is a jointly owned and democratically managed purchasing cooperative of PV installers, integrators, EPC firms and developers who benefit by collaborating to lower customer acquisition costs, streamline project financing and drastically improve operational efficiencies. Stephen Irvin moved from Namasté Solar, where he was CFO, to serve as president of Amicus. Irvin has a background in environmental economics.

Which developments or events in 2016 stand out as having had notably positive or negative impacts on the US solar industry?

Two major positive influences were the extension of the federal investment tax credit and the significant decrease in module pricing due to the overcapacity of module supply in the second half of 2016. These two developments sustained the growth and prosperity of our member companies. We also saw some impactful negative influences, such as some state-level policy changes regarding net-metering laws and community solar rules that represented challenges to the solar industry. Further, the SunEdison bankruptcy had a ripple effect resulting in lower investor confidence, which directly impacted sources of project financing. We saw more-stringent underwriting criteria that put downward pressure on EPC pricing and necessitated additional guarantees, such as system uptime and warranty wraps.

As we move into 2017, what initiatives is Amicus prioritizing?

Amicus plans to invest heavily in creating more opportunities to share best practices and learn from each other. We’ll also add new members to expand our coverage across the US.

For the last 2 years, several member companies have been working to charter a proposed Clean Energy Credit Union, which will be an independent entity, to provide financing for products and services such as residential solar, electric vehicles and energy-efficiency home improvements. Credit unions are financial cooperatives, backed by the federal government, and are thus very safe places to deposit funds. As we continue to see more customers seeking loans over leases, this is a timely entrant to the marketplace. Clean Energy Credit Union (cleanenergycreditunion.org) expects to receive its federal charter and begin operations in early 2017.

Lastly, Amicus received an award through the Department of Energy’s (DOE’s) SunShot Initiative to form the Amicus O&M Cooperative, which will support the O&M needs of commercial and utility PV systems across the US by identifying co-op members who are located in close proximity to system sites for rapid response, with all members operating under standardized services, pricing and contract terms. We will require all member technicians to complete our certified training programs to ensure a standard quality of work.

Amicus Solar is a member-owned cooperative. Why did Amicus opt for this business structure? Are any of Amicus Solar’s individual members employee owned?

Three of our member companies, including one of the founding companies, are employee-owned cooperatives. What makes cooperatives unique is that the members are also the owners. Rather than rewarding outside investors with its profits, a cooperative returns its surplus earnings in proportion to how much members use the cooperative. This democratic approach to business results in a powerful economic force that benefits cooperative members and the communities they serve.

Amicus Solar and some of its members are Certified B Corporations. What is a B Corporation and what value does the certification offer?

B Corporations are certified by the nonprofit organization B Lab (bcorporation.net) that their business practices genuinely create social good for employees, customers, the community and the environment. The certification represents a rigorous, third-party assessment, and it is a powerful sales tool for customers who believe in voting with their dollars. It helps companies attract and retain talent. The B Corp brand is well known within the socially responsible investor community and helps attract funding. Additionally, it brings these companies into another community of forward-thinking business leaders, where people work together to bring about meaningful change. We are proud to say that 14 of our members (34%) are currently B Corps, including Amicus itself, with several other members now interested in the certification.

Many Amicus members point to the information exchange that the group facilitates as one of its most valuable aspects. How is this exchange facilitated, and why do members feel comfortable sharing business information that may be considered proprietary?

We provide several ways to facilitate information sharing among members: we hold two in-person retreats per year, we manage an online communication tool where people pose questions and the brain trust answers, and we have monthly conference calls on dedicated topics such as marketing practices and general business questions. We carefully manage individual member information to preserve confidentiality, and when we share it, we always present it in aggregate form.

The Solar Foundation (thesolarfoundation.org)
Andrea Luecke, president and executive director

The Solar Foundation is a nonprofit organization with a reputation for impartiality and high-quality, objective research on solar markets, economic impacts and the workforce. The foundation works with decision makers in the government, business and nonprofit arenas. Founded in 1977, it relaunched in its current form in 2010. As president and executive director since the relaunch, Andrea Luecke is the lead on The Solar Foundation’s annual National Solar Jobs Census report series and frequently presents on practical solar best practices.

What recent developments is The Solar Foundation most excited about?

Just in the last year, we’ve seen solar take off at an unprecedented pace. The sharp drop in the cost of solar modules and related components, combined with the growth of both corporate renewables procurement and wholesale distributed generation, has provided new life to the small utility-scale and large commercial and industrial sectors. On the residential side, we’re seeing more and more homeowners looking to finance their solar installations with loans and other products that allow them to keep more of the financial benefits of the system.

All of these developments represent the evolution of an increasingly healthy and mature solar market. Of course, a big wild card will be the impact of the 2016 election on US energy and climate policy. The bottom line, though, is that solar provides a clean and abundant energy source that is increasingly popular and very cost competitive. I’m very optimistic that these trends will continue into 2017 and beyond.

What are your priorities as we enter the new year?

Early in the year, we’ll be releasing the annual National Solar Jobs Census. We first released our National Solar Jobs Census in 2010, so this is our seventh annual jobs census report. We will also be ramping up several programs funded by the US DOE SunShot Initiative, including two major initiatives to strengthen the solar workforce. One is the Solar Training Network, which will build connections between solar job seekers, employers and training providers. Another is Solar Ready Vets, which helps transitioning military personnel gain access to solar training and employment opportunities.

Another one of our priorities will be to help the solar industry reduce soft costs, which now represent up to two-thirds of the cost of an installed residential system. We lead a program called SolSmart, which provides no-cost technical assistance and national recognition to help cities and counties cut red tape and demonstrate that they are open for solar business. That’s a way to create jobs and economic development at the local level, and at the same time provide more residents and businesses with the opportunity to go solar.

We will also be moving forward with the CivicPACE program, which supports expanded solar energy deployment by bringing property assessed clean energy (PACE) financing to tax-exempt organizations, including affordable housing, schools, nonprofits and faith-based institutions.

Are there results from the 2015 Solar Jobs Census that might surprise US solar industry professionals?

Solar employment in the United States reached 209,000 workers as of 2015, having grown at least 20% for each of the last 3 years. This job growth is happening nationwide. In 2015, states that saw their solar workforce grow by 30% or more included not only California and Massachusetts, but also Florida, Maryland, Tennessee, Oregon, Nevada, Michigan and Utah.

Are there specific areas within the industry that offer more job opportunities than others?

Project installation is the industry’s largest employment sector, with 119,931 solar workers as of 2015. However, other jobs are available in sales, marketing, project management, engineering and much more. Solar industry jobs come with relatively few barriers to entry and many opportunities for advancement. In some cases, individuals can start out in an entry-level installation position and then, with a lot of hard work and the right attitude, double their salary when they are promoted a year later. The Interstate Renewable Energy Council’s Solar Career Map (irecsolarcareermap.org), which outlines career opportunities based on job category and education level, is a useful resource for job seekers.

What is The Solar Foundation’s Solar Training Network?

In our Solar Jobs Census, we found that one in five solar employers reported it was “very difficult” to find qualified employees. The Solar Training Network, which we launched in 2016, aims to bridge the gap between supply and demand in the solar workforce. It will strengthen connections between job seekers, training providers, workforce development boards and solar employers. It will also facilitate new research to better understand the solar workforce and the benefits of solar training for employers.

North American Board of Certified Energy Practitioners (NABCEP at nabcep.org)
Rebekah Hren, NABCEP Board of Directors

Since its founding in 2012, NABCEP has developed and administered the most widely known and respected personnel certifications for the solar and small wind industries. Rebekah Hren started her solar career as a “wrench,” an electrician installing solar. She is a licensed electrical contractor, as well as an instructor and curriculum developer for Solar Energy International (SEI) and a technical consultant for SEI Professional Services. In December 2015, NABCEP appointed Hren to its board of directors.

From your perspective, what were the most notable developments in 2016?

As reported by The Solar Foundation in its 2015 National Solar Jobs Census, the solar industry is already three times larger than the coal mining industry. A development related to solar jobs growth is an increase in training programs targeted specifically to veterans transitioning to careers in the solar industry. For example, the DOE launched the Solar Ready Vets program as a pilot program in 2014, and The Solar Foundation took over the administration of this program in 2016, under the Solar Training and Education for Professionals (STEP) funding program. As a separate initiative, Solar Energy International (SEI) and the Midwest Renewable Energy Association (MREA), both nonprofit training organizations, received US Department of Veterans Affairs approval for training courses in 2016. Both organizations now offer solar training to transitioning vets through the use of GI Bill education benefits and are actively recruiting vets for solar training.

What initiative is NABCEP prioritizing as we move into 2017?

NABCEP is developing PV Specialty credentials—sometimes called micro-credentials—in design, installation, and commissioning and maintenance. NABCEP has also developed a PV System Inspector credential intended for individuals performing system inspections for AHJs, utilities, incentive programs, investors or others responsible for photovoltaic quality assurance and code compliance.

In May 2016, the US DOE SunShot Initiative awarded NABCEP a $1.1 million cooperative agreement. As one of the DOE STEP awardees, NABCEP has been updating and expanding upon its personnel certification programs to address the changing needs of solar professionals and their employers and stakeholders.

As the industry scales, is the role of certification and training more or less important?

The days of the solar generalist are drawing to a close, and the days of the solar specialist are here. Solar specialists have particular skill sets: financial analysis, sales, legal, PV system design and engineering, construction and project management, performance modeling and analysis, or O&M. However, every solar specialist needs a base upon which to stand, and that base is solid training in PV fundamentals. Certification allows employers to hire educated generalists and confidently invest in more-specialized training and advanced certifications. This is why NABCEP is rolling out specialty credentials, including one for the quickly growing field of solar O&M.

Do you have any advice on how students can qualify training providers, whether to meet NABCEP continuing education requirements or to improve job prospects?

The Interstate Renewable Energy Council (IREC) sets the bar for accreditation for solar training providers. Always look for IREC-accredited training providers and certified instructors when choosing solar training. Each year, NABCEP holds an industry-leading continuing education conference targeted towards certified PV Installation Professionals. The next conference is scheduled for March 21–23 in Dallas, Texas, and will consist of an excellent mix of industry expert panels, equipment-manufacturer technical trainings and day-long in-depth seminars.

Solar Energy International (SEI at solarenergy.org)
Kathryn Swartz, executive director

SEI was founded in 1991 as a nonprofit educational organization to provide industry-leading technical training and expertise in renewable energy. SEI offers hands-on workshops and online courses in solar PV, microhydro and solar hot water. One of the more than 50,000 alumni of SEI, Kathryn Swartz has been its executive director since 2012. She has a background in environmental education.

What recent developments stand out as especially good news for the US solar industry?

From a policy perspective, the Federal Energy Regulatory Commission (FERC) ruling in support of rural electric co-ops was one of the most important events. FERC affirmed the right of Delta-Montrose Electric Association—which happens to be SEI’s electric co-op—to buy electricity outside the Tri-State Generation and Transmission Association. FERC’s ruling in support of cooperatives’ ability to buy electricity from qualified facilities significantly increases the prospects for distributed energy in rural America, which has over 900 electric co-ops. In Delta County, Colorado, where SEI is based, this ruling creates the opportunity for large-scale local renewable energy systems, including PV, microhydro, biogas and coal-mine methane.

Additionally, Tesla Motors CEO and founder Elon Musk has brought much attention to the potential of energy storage and roofing tiles, which other companies have tried to do for years. The general public, although sometimes misinformed from a technical perspective, is actively discussing renewable energy and storage, and it’s incredibly exciting. Regardless of what happens with Tesla, Musk’s announcements have spurred innovation and growth within the industry.

Lastly, the National Fire Protection Association put PV modules on the cover of NEC 2017, which is a testament to how far we have come as an industry. Regardless of what one thinks about the major rapid-shutdown overhaul, the industry is working more closely than ever with stakeholder groups, such as firefighters, and that benefits all of us.

Moving into 2017, what initiatives is SEI prioritizing?

This year, SEI is prioritizing the expansion of our international outreach efforts, including expanding our scholarship funds so that no person is denied the opportunity for quality technical PV training. In 2016, SEI gave over 80 scholarships to people from around the world, including members of the Masai tribe in Kenya; refugees from Syria and Sudan; students from India, Iraq, Nigeria, Ecuador, Belize and Colombia; and US veterans who no longer had access to GI Bill funding for training. We are also in the process of developing international hands-on training centers, which we will model off SEI’s flagship campus in Paonia, Colorado. People from around the world take our online courses. However, there’s no substitute for in-person, hands-on training. By developing international satellite training locations, we can bring our hands-on quality training to even more people.

SEI has more than 50,000 alumni of its training programs. How has the profile of SEI’s training participants changed?

To date, we have provided training to people from all 50 states and 190 different countries through our online campus and in-person trainings. When we founded SEI more than 25 years ago, we mostly trained homeowners who were seeking energy independence through off-grid living. As the industry has changed, so too have our participants. They come to SEI for solar training for a multitude of reasons. Some are driven by a desire for energy independence—that hasn’t changed—or are seeking financial opportunities and career development. Others are concerned about geopolitical and global conflict pressures or fascinated with the technologies driving the clean energy sector. We’ve seen a significant increase in the number of veterans we are serving. Though we’ve always been an international training nonprofit, we’ve seen a major increase in the number of students from both the developing world and emerging markets.

Has the focus of SEI’s training programs evolved in recent years?

Though grid-connected applications obviously make up the bulk of the US solar market, SEI has always maintained a comprehensive energy storage program. We now have over 175 hours of energy storage curriculum that we continue to change as new technologies emerge. We’ve also spent a lot of time on our O&M trainings, and we will be launching an online O&M course in the spring of 2017. Geographically we’ve expanded with the addition of our Programa Hispano training for Latin America and our new Middle East Program. We have a team of ten people working on not only updating our online and in-person trainings, but also developing new courses.

What training opportunities does SEI offer for solar professionals?

SEI offers a variety of high-level trainings for professionals already working in the solar industry, from hands-on O&M, to advanced one-day conference trainings, to on-demand online continuing education courses. All of SEI’s training provides NABCEP education hours for certification or continuing education credits for recertification. We also offer the SEI Solar Professionals Certificate Program (SPCP), which creates a pathway to graduation requiring more than 200 hours of training and multiple tracks of emphasis. Many of our SPCP graduates go on to get NABCEP certification.

SEI launched SEI Professional Services and SEI Engineering in 2015 and 2016, respectively. What technical services is SEI offering and what businesses or groups could leverage and benefit from these services?

SEI launched these two for-profit entities because of the many requests from our alumni, who wanted additional support as they began businesses or took on more complicated projects. Not only are we supporting our alumni and their business growth, but we are also providing professional growth opportunities for SEI staff and instructors who work on a wide variety of projects, and that feeds back into keeping our curriculum cutting-edge. In addition, the profits support SEI’s nonprofit mission and fund our scholarship program.

SEI Professional Services offers third-party commissioning, performance verification, design, consulting and feasibility services. SEI Engineering provides electrical and civil permitting and construction documents for projects ranging from residential to microgrids to utility scale. We’ve worked with companies from around the world, from start-ups to established multinational corporations, to provide them with the tools they need to implement successful projects, and we’ve only just begun.

Blue Oak Energy (blueoakenergy.com)
Bill Reaugh, director of engineering

Blue Oak Energy is a Davis, California–based engineering and construction firm that has fielded more than 1 GW of solar capacity across more than 900 sites since its founding in 2003. Bill Reaugh, the company’s director of engineering, has worked in the PV industry since 2002, specializing in technology development and regulatory policy.

How does the future of the US solar industry look from Blue Oak Energy’s perspective?

The 2018–2020 business outlook is staggering. We owe that to the extension of the Investment Tax Credit (ITC). The ITC provides a stable tax incentive framework for projects, which helps ensure long-term industry stability and growth. As an engineering and construction firm that supports developers, financiers, contractors and product manufacturers, we see firsthand how the ITC extension has improved the outlook for all of our partners.

How has Blue Oak Energy adapted its business model and services over time?

One of the primary adaptations we have made is the addition of a full-service civil engineering team. Utility-scale solar projects have taken over a large percentage of our engineering capacity. Getting the civil aspects of a project right from the very beginning of a development effort is essential to delivering a successful project on schedule and within budget. We have also seen project schedules compress as the industry matures. Having a full-service civil engineering team in-house working closely with our electrical and mechanical team members creates a cohesive system design across all boundaries. As a result, we can now fully engineer, permit and begin construction on very complex utility solar projects in a matter of a few weeks.

What products or services are coming to market that are potentially game changing or particularly important incremental advances for the US solar industry?

From both a design and an O&M perspective, we like using tracker systems that operate without the need for drive shafts or external power supplies. In terms of plant design, this provides significantly more flexibility, particularly in areas challenged by terrain, wetlands or other obstacles that prevent regular power block shapes. The efficiency of O&M activities improves because the O&M team can drive module-washing and weed-control equipment straight through the row without having to turn around in the middle, which also allows for tighter spacing between rows and improves ground cover ratio. Other incremental improvements include steel pile product and wire harness advances, increased string inverter capacity and 1,500 Vdc utilization voltages.

You have some experience with tile- and roof-integrated solar products from your tenure at OCR Solar & Roofing, which PetersenDean acquired in 2009. What lessons did you learn about the residential new construction market? What do you make of Tesla’s new Solar Roof products?

Many media reports about the October 28 announcement are inaccurate. Tesla introduced Solar Roof tiles, not shingles as many outlets reported. Roof tiles, on one hand, are typically made of concrete, clay or slate. Even trained roofers have a difficult time handling roof tiles as they are heavy and brittle. Shingles, on the other, are made of asphalt and other petroleum byproducts, so they are exceptionally inexpensive to manufacture, durable and easy to install.

Elon Musk’s claim that his solar roof tiles will be cheaper to produce and install than traditional roofing materials may be accurate—with a very large emphasis on may— but much depends on the details. When I worked with a roofing contractor doing solar roofs integrated with traditional roofing tiles, we used a product manufactured by BP Solar precisely because it installed identically to roofing tiles. What many have observed, but not necessarily thought about, is that while roofing tiles are nearly uniform, roofs are not. Therefore, roof tile installation needs to be flexible to accommodate changes in roof shape and pitch. To integrate easily with roofing tiles, solar roof tile installation must also provide flexibility. While the BP Solar tiles were flexible, a competing product at the time was not, which led to some compromises that could cause long-term issues with the roof.

Elon Musk and his team have proven to be incredible innovators and have disrupted multiple industries with technologies that achieve economic scale. It is also true that venerable companies such as BP Solar, Dow Solar, SunPower, Unisolar and many others have ventured into this particular solar niche with varying degrees of success. Based on that history, it will be difficult for Tesla to achieve the level of success it has attained in other areas. We will simply have to wait to see what comes out of Buffalo.

Before joining Blue Oak Energy, you represented KACO new energy in some of the Rule 21 proceedings. What was that process like and where do things stand?

According to the California Public Utilities Commission, Rule 21 is “a tariff that describes the interconnection, operating and metering requirements for generation facilities to be connected to a utility’s distribution system, over which the California Public Utilities Commission (CPUC) has jurisdiction.” The process of creating Rule 21 started in 2011 and is ongoing in 2017. During the development process, stakeholders decided to break the rulemaking into three phases: Phase 1 deals with autonomous functions, Phase 2 deals with communication requirements, and Phase 3 deals with advanced features. Prior to the creation and adoption of Rule 21, inverters were required to trip offline when the grid became unstable for any reason. Outside the US, countries with large penetrations of renewable generation sources—such as Germany and Denmark—decided that the flexibility inverters provided was beneficial to the grid, and those countries developed standards for when and how inverters could support the grid. In the event of an abnormal voltage condition, for example, you might want interactive inverters to ride through the event rather than disconnecting from the grid and exacerbating those conditions, which could potentially lead to a blackout.

Rule 21 is among the first efforts in the US to develop and follow similar standards on a grid-wide basis. Prior to implementation of Rule 21, it was possible to allow the additional flexibility, but only on a case-by-case basis and only through special operating agreements between the plant operators and utilities, which limits these functions to large-scale solar projects. Rule 21 now pushes those options down to systems as small as 15 kW.

As of December 2014, the investor-owned utilities in California (PG&E, SCE and SDG&E) had adopted Phase 1 of Rule 21 statewide. As of September 2016, UL developed testing standards to certify inverters as having “advanced inverter functionality.” Inverter manufacturers are now getting equipment certified to the new Advanced Inverter Standard and will have commercially available products soon. Inverter manufacturers are required to complete the certification process no later than September 2017.

California Solar Energy Industries Association (CALSEIA at calseia.org)
Bernadette Del Chiaro, executive director

CALSEIA is a California nonprofit organization created to promote the growth of the solar industry and expand the use of all solar technologies in the state through policy development, advocacy, education, networking and business services. Since 2013, Bernadette Del Chiaro has served as the executive director, coming to CALSEIA with more than a decade of policy and advocacy experience on renewable energy issues in California.

What was the good news out of California in 2016?

The biggest policy event of 2016 was the strong NEM 2.0 decision issued by the CPUC. Despite fierce opposition from California’s large and powerful utilities, and in the face of a three-to-two vote of the Governor Brown–appointed board, the CPUC adopted a strong successor program that will allow customer-sited solar to continue to grow over the next several years.

Did the California solar industry lose any fights this year?

The state suffered market losses in utility territories governed by local municipal utilities and irrigation districts. Alameda, Imperial, Modesto and Palo Alto are just some of the local utilities that have turned their back on rooftop solar, essentially killing the solar market going forward by effectively eliminating net metering.

What are CALSEIA’s top priorities this year?

Our number one priority in 2017 is our Storage and Smart Grid Project, which aims to usher in Grid 2.0, enabling high levels of distributed solar and ensuring that the customer-sited solar market continues to grow. Specifically, we will work to improve interconnection processes, create new tariffs for grid support services, launch a market transformation initiative for storage, and ensure that the next generation of NEM tariffs clears the way for continued growth of distributed solar.

How will these initiatives benefit your members, customers or the industry as a whole?

Making storage paired with rooftop solar a reality for everyday consumers is the single most important thing we can do to promote the future growth of the solar industry. This vision will come about through a combination of storage-friendly rate structures that give market value to smart inverters and storage systems, such as rebates to drive up demand and drive down prices, as well as consumer and contractor training and information to build the knowledge base to take this next big step into a clean energy future.

What is CALSEIA’s current membership profile and has it changed notably in recent years?

CALSEIA is in a major growth phase. Over the last 3 years, we’ve quadrupled our membership, and we show no signs of slowing down. We’ll start 2017 with over 430 members, and we aim to exceed 500 by the middle of the coming year. Our membership is broad, with contractors and developers making up about half of our companies. The other half is a mix of manufacturers, financiers, software developers and other support service providers. Given this growth, we are able to represent the industry in every major decision-making forum from the CPUC to the state legislature to OSHA. We are also able to help our members with more day-to-day business, such as local permitting and HOA battles that can add up and become quite the thorn in the industry’s side.

What is the status of California’s Self-Generation Incentive Program?

Extending the Self-Generation Incentive Program was an important accomplishment of the 2016 legislative session, as it effectively kept the lights on for distributed storage projects. However, the program is not big enough, and the new funds are likely to be subscribed by mid-2017, leaving a gap in funding for an industry that is trying to get off the ground. Rate structures that truly value storage, along with other grid-support services such as smart inverters, are still a ways away. Without a stand-alone incentive program to give the industry and consumers alike consistent support to drive up demand and drive down prices, California’s emerging storage market will remain expensive, serving only a niche market. This is exactly what happened to the solar PV market in the early 2000s, before adoption of the California Solar Initiative in 2006. Creating a market-transformational initiative for California’s storage industry in the next 3 years is critical.

California has always been a leader in solar policy and market development. As individual states work to develop or expand their solar industries, do you have suggestions for areas of focus?

The most important thing this industry can do is build up our outside game. Having and mobilizing strong public and coalition support, to match strong advocacy and regulatory work, is critical. Money still talks, and this industry, despite our recent growth, cannot match the resources of our opponents. Our number one resource, besides the sun itself, is people power. It is what delivered a strong NEM 2.0 decision in California, and it is what will always be the foundation of successful policy outcomes. Just look at Florida and Amendment 1. The utilities understood the power of public support for solar and tried to harness it for their own deceitful self-interests. It looked like we were going to lose until the utilities were caught in their lie and the public was made aware with the help of the media. This recent story demonstrates the importance of the outside game.

Vote Solar (votesolar.org)
Adam Browning, executive director

Since 2002, the nonprofit organization Vote Solar has worked to remove regulatory barriers and implement key policies needed to bring solar to scale. It works at the state level across the country, with staff in California, Colorado, Massachusetts, Maryland and Washington, DC. Adam Browning co-founded Vote Solar in 2002 and serves as its executive director. He previously worked for the EPA.

Were there any big wins for team solar in 2016?

There are now more than a million solar installations in the US. The fact that we will double the number of installations over the next 2 years is a bellwether of where we are going. Reaching 1 million solar installations this year was largely thanks to market-building policies at state levels in addition to declining costs and solar’s broad, bipartisan support.

We made major strides in market-building policies this year, helping drive solar progress in more than a dozen state legislatures and regulatory forums nationwide. In California, we defended and won fair net metering credit for solar customers, and we carried the torch forward for net metering across the country, including notable wins in Arizona, Colorado and Massachusetts.

2016 saw more support for expanding access to solar in low-income communities than ever before, with dedicated programs and policies taking shape in California, Colorado, Maryland, New York and elsewhere. We partnered with GRID Alternatives and the Center for Social Inclusion to launch the Low-Income Solar Policies Guide and our own low-income solar access program aimed at growing this critical market segment for the industry.

Community-shared solar made headway all year, with dedicated programs from coast to coast and nearly 100 MW in installed capacity. We worked toward building community solar policies in half a dozen states this year, including Colorado, Georgia and Maryland.

Finally, we’re neck-deep in utility reform, both in New York’s Reforming the Energy Vision proceeding and in California in multiple regulatory proceedings to craft modern grid policies. Transitioning away from the fossil-based infrastructure we rely on today will require intentional planning and investment, and it’s a tremendous opportunity to optimize solar, storage and other distributed energy resources integration onto the grid.

What about the challenges facing the US solar industry?

There were more utility-led attacks on solar in 2016 than ever before. In Nevada, NV Energy took aim and fired on solar last year by implementing punitive fees and curtailing net metering, which eliminated thousands of local jobs overnight and undermined customers’ rights to energy choices and clean generation. Our coalition successfully reinstated net metering for 30,000 existing customers, but we’re still working through the legislative, regulatory and legal avenues to bring solar back to future customers and rebuild Nevada’s once thriving clean energy industry.

Another emerging trend this year was the rise in the number of utilities that sought to penalize ratepayers—and especially solar customers—with demand charges and other unjust rate hikes. We’ve defeated demand charge proposals in Arizona, Illinois, Massachusetts, New Mexico and elsewhere, and we will continue to fight unfair rate increases in 2017.

Utilities across the country also launched attacks on the Public Utility Regulatory Policies Act (PURPA), a 1978 federal law that requires utilities to purchase renewables when they’re available at cost-competitive rates. PURPA is more relevant than ever for community and utility-scale development in both mature markets such as North Carolina and emerging markets in the Northwest. We petitioned the Montana Public Service Commission and FERC to protect PURPA in Montana and to seek to prevent future utility attempts to undermine this important market-building policy.

As we move into 2017, what initiatives will Vote Solar be prioritizing?

In 2017, we’ll tackle net metering and fair rate design, low-income solar access policies, community-shared solar programs, solar market drivers and building a modern grid. We’ll also ramp up our geographical reach in 2017, expanding into the Midwest in addition to our ongoing campaigns in the Northeast, Southeast, Intermountain West and Coastal West. We also plan to double down in the Southeast with a dedicated rates expert to support our legislative advocate.

Are there specific states or utilities that you think have implemented model or equitable rate designs for distributed solar?

Regulators and lawmakers in both California and New York have launched initiatives to establish equitable rate design for distributed energy resources, including solar. Importantly, both states have taken steps to ensure broad stakeholder participation and availability of the full suite of facts and data. In a recent report, the National Association of Regulatory Utility Commissioners validated this approach to rate design, acknowledging the value of distributing energy on the grid.

Vote Solar is a vocal advocate in favor of net metering. As distributed generation scales, are there structural limitations to net metering? Are there other rate design structures that might better serve stakeholders in high-penetration scenarios?

Net metering remains the gold standard policy as a fair and simple way to credit solar customers for the clean, homegrown power that they send back to the grid. The fact is, study after study in nearly a dozen states has found that net metering provides a net benefit to the grid and customers.

While net metering is a simple and straightforward compensation mechanism, like most residential rates, it doesn’t account for the time value of electricity on the grid. Thus, regulators and stakeholders are investigating how the industry can move beyond net metering to a rate design that better ties the value of excess generation to the value of electricity to the utility at any given time. The goal is to structure a far more sophisticated—and complicated—rate design. California, New York and a handful of other states have undertaken the ambitious task of utility business model reform.

Solar consistently performs well in public opinion polls, with roughly 90% of respondents indicating that they are in favor of expanding solar generation capacity. What can we do as an industry to leverage this broad support?

Get engaged in policy, especially in states where your company operates. Democracy is a contact sport, and representatives need to hear from local businesses. Businesses and individuals should proactively develop relationships with their state and federal representatives. Companies should also join national and state industry associations that are dedicated to protecting and opening solar markets.

On an individual level, becoming a free member of Vote Solar is the lowest barrier to entry to engaging in solar advocacy. We simply let you know when you can participate in campaigns or policy actions—such as signing a letter, sending your legislator an email or joining a rally—in your state. We especially rely on solar workers to speak out about threats to solar markets and opportunities to make them even stronger.

We’re up against industries and business models with powerful lobbies—not to mention deep pockets—that a 21st-century clean energy economy threatens. Now more than ever, the solar industry needs all hands on deck to build and protect markets and defend against charges, fees and other attacks that undermine the competitiveness of solar. Unlike sunshine, solar policies don’t fall from the sky.

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How much revenue is a soiled PV array losing, and at what point does it make sense to wash the array?

Owners, developers, bankers and O&M providers all want to know when it makes sense to clean a PV array to recapture revenue that it would otherwise lose due to soiled modules. On the one hand, an overly soiled array represents a loss of money. On the other, a premature cleaning represents a waste of money. While you must consider many variables to reach a definitive washing decision, the economics of module washing are not complex: If having a clean array saves more money than it costs to wash the array, then washing it probably makes sense.

This article shares some of our analyses and observations on array soiling drawn from many years of operational experience. We have had successes and failures, which have led to interesting discoveries and some dead ends. We have based most of our research on utility-scale PV plants with high dc-to-ac ratios in sunny, arid locations. These plants are subject to a unique set of circumstances: They spend a lot of time at full power, have relatively steady soiling rates and are rarely exposed to enough rain to significantly clean the modules.

Energy Recapture

It is difficult to assess soiling and to determine when to wash an array because doing so requires a multi-variable equation. Every analysis is unique, based on a host of project-specific mitigating factors such as technology choices, racking configuration, inverter loading, PPA rates, time-of-day profiles, interconnection agreements and so forth. This means that there is no single right answer when it comes to the economics of washing. The methods for soiling analysis are as varied as the business model behind the PV plant, so each solution uses a unique combination of people, tools and number crunching. What all effective soiling analyses have in common, however, is that they distinguish between percent soiling and percent energy loss due to soiling. While the former is easier to quantify, it may not correlate to unrealized revenue.

For the purposes of this article, we define percent soiling as the reduction of expected output power between soiled dc source circuits (modules, strings, arrays) compared to the same source circuits under clean conditions. In field terms, percent soiling describes the ratio of dirty to clean IV-curve traces, extrapolated to nameplate power under standard test conditions (STC). Meanwhile, we define percent energy loss due to soiling as the difference between the metered energy for a given time period compared to the energy that could have been harvested over the same time period with a fully clean array. This term describes the energy that is available for recapture, which correlates directly to unrealized revenue. To differentiate between these two concepts, we need to quantify the amount of time that a PV power plant spends at or near full power.

Power limiting in PV arrays. It is common practice to deploy PV systems with a high array-to-inverter power ratio in an attempt to capture more energy and revenue. As a result of these high dc-to-ac loading ratios, many inverters spend a lot of time operating at full power, which forces the array off its maximum power point.

Extended periods of power limiting result in a characteristic flat-topped power curve, which people commonly refer to as power clipping. The more time a PV system operates at full power, the less concern is warranted over soiling. Soiling abatement is effective only if you can recapture the lost energy, which requires unused inverter capacity. The returns are diminished in PV systems with chronically clipped power profiles, because an inverter operating at full power cannot increase its output power based on an incremental increase in irradiance. If soiling is viewed as an effective reduction in plane-of-array (POA) irradiance, then a 5% increase in irradiance can overcome a 5% soiling level. For example, if a given inverter hits maximum output at a POA irradiance of 800 W/m2 under clean array conditions, then it follows that power clipping will start at 840 W/m2 in the 5% soiled case. Above 840 W/m2, the percent soiling literally becomes a moot point.

Figure 1 illustrates this point by comparing seasonal POA irradiance and plant production curves for the same PV system. The flat-topped curves on the left, labeled “Day 1 (August),” illustrate how the plant operates at full power for extended periods of time under high POA irradiance typical of summer. The curves on the right, labeled “Day 2 (November),” illustrate how the array operates below full power all day long under partially overcast conditions in the autumn. To compare the percent energy loss due to soiling for Day 1 versus Day 2, we first have to filter out the time spent at full power, as no energy is available for recapture during these hours.

Table 1 presents these filtered results. Compared to baseline values for a clean array, the percent soiling is roughly the same on Day 1 and Day 2 (3.7% versus 3.6%). However, we can recapture energy only during hours when the PV plant is not power limiting. This leads to a slightly counterintuitive result: Even though the incident energy on Day 1 is nearly twice that on Day 2 (10.4 kWh/m2 versus 5.3 kWh/m2), the percent energy lost and the net energy lost due to soiling are greater on Day 2. This means that Day 2 presents the better opportunity for revenue recapture via washing, even though the available solar resource value is lower.

The challenge associated with soiling assessment is that we need to extrapolate this analysis to the near operational future for a PV power plant. The estimate concerning the future mix of clear, cloudy or overcast days is what determines the economics of module washing. A host of models and methods are available to predict and back-calculate the energy available for recapture, including hourly energy models, exceedance probability calculations and regression analyses. Regardless of the methodology used, you must account for inverter power limiting and have an accurate estimate of percent soiling.

Direct Soiling Measurements

The best way to estimate percent soiling is to measure it directly: Test the array, wash it, and test it again. While the process is time-consuming, there is no disputing the results. Soiling sensors and IV-curve tracers are proven tools for getting an accurate answer to the question “How dirty are my modules?” It is also possible to use other devices, such as short-circuit testers, to get a general estimate of soiling levels. Just keep in mind that additional data analysis and filtering is required to extrapolate from percent soiling to percent energy loss due to soiling.

Soiling sensors. Soiling sensors are essentially stand-alone evaluation tools that compare the actual output of a naturally soiled PV reference module to the expected output of a clean PV reference device. Some soiling sensors use short-circuit current (Isc) as the basis of comparison; others incorporate a microinverter and compare maximum power point values (Vmp, Imp, Pmp); some devices use a hybrid technique that compensates for temperature and normalizes results to STC. All of these approaches yield a high-quality data stream that you can easily use to assess the soiling level of the modules in the test rig.

IV-curve tracers. To get the best possible in situ soiling measurements, put a good IV-curve tracer in the hands of a competent technician. Curve tracing is slow but definitive. You can compare PV source-circuit curve traces to STC or use a dirty versus clean approach. As long as technicians capture a representative set of IV-curve traces under roughly the same conditions, the results of the study will be accurate and useful. While it is quick and easy to analyze these IV-curve data, it is incumbent on the technicians to choose representative strings to test in the field.

Other devices. Another option that works well is to use instruments that measure short-circuit current or operating current, or that can extrapolate measured data to a baseline condition—such as PVUSA Test Conditions (PTC) or STC—to estimate percent soiling. Since these devices are not explicitly intended to perform soiling measurements, the correlation process is left to you. However, the process does not need to be complex. A simple multimeter with a current loop sensor is sufficient to get a general idea of soiling conditions. If necessary, you can assess soiling with a Fluke meter, a few gallons of water and a squeegee.

SOILING TRANSFER FUNCTION

Soiling stations, IV-curve traces and other assessments that compare “before” (dirty) and “after” (clean) conditions give an excellent indication of the soiling conditions on a specific set of modules or test array. The trick is to take data from these devices and extrapolate it twice: once to generalize the entire plant’s soiling condition, and once more to infer how much the measured soiling will affect energy production or performance. We call this the soiling transfer function. Direct soiling measurement is a great start, but it is a rare instance where the estimated percent soiling value will reflect an equal (or even proportional) percent decrease in production. As illustrated in Table 1, percent soiling does not correlate directly to energy lost due to soiling when PV plants spend a lot of time operating at maximum power.

To complete the soiling transfer function from percent soiling to percent energy loss due to soiling, you need to filter the operational data strategically. The data filtering process can be as simple as removing power clipping points, which has the effect of constraining the evaluation to periods of MPPT operation. You can also apply additional filters to remove spurious data points that may muddy the results, such as measurements associated with low POA irradiance, unstable irradiance or excessive wind speeds. Once you have obtained field measurements and filtered the operational data, you just need something with which to compare these to estimate percent energy loss due to soiling.

PLANT BASLINE

The best way to estimate the impact of soiling is to compare operational data to plant performance under clean conditions, which we refer to as the plant baseline. Obtaining a performance baseline is a process of characterizing the electrical performance of source circuits, combiners, inverters or an entire plant and isolating these data for frequent comparison. The goal of establishing a baseline is to understand how the system or subsystem performs under known operating conditions when the array is free of faults and unsoiled. Generally speaking, a rough plant baseline is good enough.

Establishing a clean plant baseline is more of a process than an event. The logical opportunity to obtain a baseline for an entire plant is at the time of initial back-feed, testing and commissioning. If you want to get two detailed answers at once, you can perform a full-plant baseline characterization in parallel with performance testing, which is ideal. However, you can establish a baseline at any system level, over any duration of time and under any operating conditions. Nothing is lost if you are unable to characterize some parts and pieces at commissioning. You can always revisit and recalibrate these parts later and make sure that they fit the general performance trend once they are up and running. As long as you restore malfunctioning blocks to operation and characterize their performance using the same measurement methods, the baseline will be accurate and useful despite its piecemeal assembly.

There are various means of applying the baseline. The simplest form—comparing dirty versus clean performance—is effective for both long- and short-term analyses. By characterizing the plant according to its big pieces, such as inverters, skids or ac collection circuits, you can compare these results to one another, normalize dirty results against the clean baseline and make informed decisions about soil abatement. You can express the baseline in whatever terms best suit your goals, such as specific yield (kWh/kW) or energy output in relation to POA irradiance. The latter is useful if you need to tie actual performance back to expected performance based on an energy model.

Since assumptions, data resolution and as-built conditions constrain energy models, we strongly recommend that you use operational data rather than modeled plant behavior as the basis of comparison. Whereas an energy model describes how the plant is supposed to behave, measured data describe how the plant actually behaves. In broad terms, energy modeling software applies soiling assumptions as an effective monthly reduction in POA irradiance and essentially stops there. One-month averages for soiling levels can shore up production and revenue models, but they have little to say about soiling events, differential energy impacts or soiling rates in general. As a result, the input/output resolution for an energy model is far less precise than it is for most operational datasets.

ACCURACY

End use and accuracy drive the baseline characterization method. Production losses can be very subtle, typically only a few percentage points, before they become noticeable, so accuracy is vitally important to tying production losses specifically to soiling.

The simplest characterization method is to catalog plant production at the meter as well as measured irradiance in the plane of array. Since this obviously ignores thermal differences within the array, for increased accuracy you may need to apply a temperature compensation to account for deviations from weather station conditions. You also need to remove or ignore performance issues that are not related to soiling, such as module degradation, equipment failures and configuration differences. Soiling analysis has to quantify or transcend these factors to reach a reasonable conclusion.

To illustrate the challenge: A POA irradiance sensor might have an accuracy of ±1.0%; ac power measurement transducers are typically accurate within ±0.2%; dc transducers are rarely better than ±1.0% accurate; secondary measurements, such as temperature and wind speed, have ±2% accuracies at best. These measurement errors typically compound rather than cancel one other. Compounded, these uncertainties suggest that isolating a few percentage points of performance loss using gear with measurement errors of a few percent can produce dubious results.

The net result is that a thorough soiling analysis could very well estimate that modules are 4.5% soiled, plus or minus 2%. Given these uncertainties, module washing may or may not be cost effective. While no one likes this type of answer, it is often the case that soiling analysis results have a high degree of uncertainty.

Practical Application

We recommend a relatively simple five-step approach for isolating the effects of soiling on energy production based on measured data from operating PV plants. The methodology uses a comparison to a baseline as a means of assessing the production that the array might have achieved if it had been completely clean and operating perfectly. The specific implementation of this methodology depends on plant type, capacity and the monitoring solution. However, you can apply this method at almost any plant level using similar techniques.

Step 1: Catalog all IV-curve traces and other string-level commissioning tests to establish source-circuit behavior with respect to nameplate power. This step provides a consistent reference dataset that you can revisit when using periodic string testing for performance assessments.

Step 2: When commissioning the array and conducting energy performance tests, establish plant-level and inverter-level baselines using high-resolution data. These baselines should isolate trend data for clipping and nonclipping production as a function of POA irradiance and should be normalized to dc capacity by inverter. You can complete this step in pieces, if need be, updating the baselines as more datasets become available. The key is to characterize a clean, fully operational plant.

Step 3: Track plant performance using trend data from the time of (clean) commissioning through operations. Using the same filters employed to establish the baseline, determine approximate soiling levels while the plant operates (as time, data and weather allow). 

Step 4: If you suspect excessive soiling, perform a series of string-level field measurements before and after washing, and compare these results to the commissioning data. Next, compare these measured results to the soiling estimates generated from trend data with the appropriate clipping filters applied. Establish the correlation between the measured and modeled results for future use.

Step 5: When field measurements and data analysis align—and when the comparison to baseline indicates that energy recapture will be cost effective—then it is time to schedule a wash. Over time, take advantage of these full-array washing opportunities to recalibrate the baseline, the energy model and so forth.

EXAMPLE ANALYSES

The following examples illustrate how you can use baseline comparisons to isolate soiling conditions. We have taken all examples from utility-scale plants with multiple central inverters in sunny, arid locations. We have summarized and annotated each case to show how you can apply the same methodology at various scales.

Plant level. Figure 2 shows an example of a long-duration soiling analysis. We cataloged these data over an 8-month period, and they capture a few isolated rain events as well as a complete array cleaning. We have filtered the datasets from each for clipping and reported them as percent of baseline. Although these daily values have quite a bit of variance and error, the soiling accumulation trend is undeniable. While the rain events mitigated soiling only marginally, the wash effectively rehabilitated the arrays to full potential. 

With any macro-level assessment, especially on larger plants, you must level out or ignore some asymmetries and performance issues with strategic math. The end result is an accurate model of how the plant turns photons at the modules into energy at the meter. You can parse this type of baseline into subsections, perhaps by combiner, inverter, skid or ac collection circuit. Regardless of the scale, the concept is the same and provides an adequate assessment of performance in an ongoing manner. You can employ and repeat this dirty versus clean comparison to baseline under any circumstance and recalibrate the whole process after a full array cleaning.

Inverter level. Inverter-level assessments are a subset of whole-plant characterization but with higher data resolution. The key to this level of analysis is to establish a unique baseline for each inverter under clean and fully operational conditions. Inverter-level comparisons are useful for identifying the impacts of differential soiling across the whole plant.

For example, Table 2 compares inverter-level data, reported as “percent inverter-specific energy compared to baseline,” for a large-scale PV plant with differential soiling. Most, but not all, of the arrays at this site are subject to rapid soiling from an adjacent road and farm field. By tracking inverter-level data, we can isolate soiling by location or overall contribution to lost energy. In this particular case, the soiling was profound enough to trigger a full wash cycle. If the differential soiling analysis had indicated that soiling affected less of the plant overall, we could have focused our maintenance activities more selectively, perhaps electing to wash only arrays associated with specific inverters.

Combiner level. We can further increase data granularity and resolution by evaluating dc input current at the subarray level, which effectively facilitates combiner-level assessments. While this approach makes it easy to diagnose the effects of differential soiling on an individual inverter, the real beauty of combiner analysis is that it provides a built-in method of validation. If all of the subarray inputs are showing the same thing, as in Figure 3, our confidence in soiling assessments improves. The increased granularity also makes it easier to track incremental changes from the baseline.

String level. Because it provides the highest-resolution data possible, string-level analysis is the alpha and the omega—the first step and the final step—of an effective performance assessment. Since most large-scale PV systems do not have string-level monitoring, cataloging source-circuit performance generally requires field tests. Though string-level testing demands high-quality tools and competent technicians, the data produced are effective for establishing a baseline or calibrating the energy metrics and assumptions used at all other levels of analysis.

You can use these string-level data to calibrate independent soiling sensors. You can also apply string-level dirty versus clean results, such as those shown in Figure 4, to historical data or to a before-and-after cleaning analysis. In this figure, the raw trace data, based on in situ irradiance, are shown in green; the curves in red correct these field measurements to STC; the blue curves, meanwhile, show the ideal I-V curve for the source circuit at STC. These dirty versus clean traces provide a good indication of the energy available for recapture at the string level, which we can extrapolate to larger performance blocks.

An ideal use for field measurements is to calibrate soiling analyses in relation to operational data. This process involves comparing IV-curves to soiling station data and other soiling metrics. To the extent that we can draw correlations, we can triangulate these datasets and better inform our washing decisions. This process of continuous improvement is essential to effective soiling assessment.

SPECIAL CASES

Dust storms, intermittent construction activity, unusually heavy traffic and sporadic agricultural activity are examples of event-based soiling. When soiling gets very bad—or when it gets a lot worse in a hurry due to a soiling event—strange things start to happen in terms of plant behavior. Module soiling can reach a point where the fundamental electrical characteristics of the dc array change dramatically, so much so that it sometimes forces inverters out of maximum power point tracking. These results are most common in neglected PV plants where extreme soiling causes blocking diodes in the modules to engage, which can completely confuse the inverter.

Really bad soiling almost precludes analysis. The electrical behavior of a PV plant becomes less predictable and performance suffers, but it can be difficult to quantify how bad the problem is and how much energy the plant is losing. Such conditions combine significant energy shortfall with chaotic behavior. While we can measure the lost energy, we cannot directly discern the reasons for the loss. This complicates the process of troubleshooting any problems not related to soiling.

Soiling events are a constant source of panic. Everyone wants to know how bad the problem is, but making even a rough estimate takes at least a day. Rather than rushing to get a washing crew in place based on incomplete information, the best approach to soiling events is to send technicians to the site to assess the problem via dirty versus clean testing. These strategic test results will quickly provide the answers needed and frequently trigger a wash cycle.

Soiling events can also be localized, a situation we call asymmetrical soiling. This occurs when some arrays get a lot dirtier than others. Exterior arrays next to dirt roads or agricultural activity are the most common culprits. Differential soiling across the whole plant skews bulk numbers, especially when you take the soiling assessment measurements from a relatively clean or dirty array.

Since soil detection is intended to generalize soiling conditions, you cannot trust the numbers it yields when you are adapting a general model to an asymmetrical problem. We call this phenomenon forced mismatch, meaning that uneven soil deposition creates an imbalanced electrical condition. Here again, the best response is to send out a crew to assess the situation, and then back up the findings by comparing filtered operational data to a clean baseline. Asymmetrical soiling may make selective module washing a viable option.

ANOMALOUS RESULTS

The next case studies represent rigorous analyses using high-resolution data applied to fully operational plants that all ended up with dubious results. Some may call these war stories; we call them analytical head-scratchers. We present them here to illustrate the chaotic nature of soiling measurements and the unpredictability of the results.

Case 1. After measuring overall soiling of a PV plant at around 4%, the owner scheduled washing. Before the wash, a short-duration rain event occurred, so the owner asked us to investigate to see whether the rain had cleaned the modules enough to justify delaying the capital expense of a full wash. By our calculations, the rain event actually increased soiling to more than 5%, calling the entire chain of decisions, as well as our analytical approach, into question.

Case 2. In an attempt to quantify soiling, we conducted a series of before-and-after IV-curve traces across a plant. Our strategic plan called for washing selected strings of modules across a representative set of arrays on assorted inverters to quantify a measurable difference. The curve traces showed less than 1% soiling on some strings and more than 7% on others, with a relatively even distribution between these extremes. We recommended a full cleaning, and the net performance results after washing showed a similar distribution of results. However, the overall performance increase was only about 33% of the expected result, netting a 1.9% increase in production. We had a hard time trusting the results, the analysis approach and the wisdom of our recommendation to wash.

Case 3. Cleaners fully washed a plant at night to prevent production losses, which is a reasonable approach. The next morning, while the modules were still cool and wet, the farmer on the upwind side of the plant starting tilling fields, which spread a thick dust cloud onto an otherwise clean array. In this case, unforeseen farmwork forced another wash cycle.

These case studies illustrate that attempts to isolate the effects of soiling can be elusive. Soiling effects are design dependent; geographically varied; simultaneously localized and vastly different between arrays; dependent on geometry, orientation and array racking configuration; and variable based on the weather or off-site activities. In addition, rain does not necessarily clean modules very well, if at all. These factors are not necessarily bad news. Rather, they are limiting assumptions that you need to categorize, isolate, quantify and remove from the analysis to begin a valid assessment. Once you accept that soiling is a chaotic phenomenon, you can begin to see patterns and to learn from the more predictable parts of the problem.

CONTACT:

Sanjay Shrestha / SOLV Performance Team / San Diego, CA / swinertonrenewable.com/solv

Mat Taylor / SOLV Performance Team (retired) / San Diego, CA / swinertonrenewable.com/solv

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Next-generation solar farms are utilizing 1,500 V plant architectures to drive down BOS costs and improve system performance.

By all accounts, the PV power plant of the near future is here today and poised for widespread adoption in 2017. In this article, I provide a brief overview of the history of 1,500 Vdc PV systems. After providing an update on applicable codes and standards, I consider the state of the supply chain and detail the benefits and tradeoffs associated with 1,500 V designs. Finally, I identify some potential challenges associated with early field deployments.

BRIEF HISTORY OF 1,500 VDC SYSTEMS

EPCs in Europe pioneered 1,500 V plant architectures, just as they were first to market with 1,000 V PV systems. Belectric, for example, is an international solar project developer headquartered in Germany, with a long history of innovation and market firsts such as the construction of the first thin-film PV system in Europe (2001). According to a company press release, in June 2012 Belectric constructed and commissioned the world’s first utility-interactive 1,500 Vdc solar power plant. Power Conversion, a Berlin-based division of GE Energy, supplied the liquid-cooled inverters used to connect the 1,500 Vdc system to the utility grid.

Though the Belectric press release does not mention the manufacturer’s module technology, context and timing suggests this was likely a pilot project featuring Nanosolar’s Utility Panel, as this was the first PV module certified to 1,500 Vdc. Nanosolar famously hyped its now-defunct CIGS thin-film product as the technology of choice to dethrone First Solar. Today, Nanosolar has gone the way of Solyndra, and First Solar remains the world’s leading thin-film module manufacturer, in part due to its aggressive and successful development of 1,500 V thin-film modules and pre-engineered power plant solutions.

In conjunction with GE Power Conversion, First Solar began publicly touting the benefits of 1,500 Vdc solar arrays in early 2014. According to a technical brief published later that year in PV-Tech Power (see Resources), First Solar commissioned its first 1,500 Vdc AC Power Block at the 52 MW Macho Springs Solar Facility in Deming, New Mexico, in the spring of 2014. After monitoring and comparing the performance of this 3.6 MWdc array alongside that of 34 other 1,000 Vdc array blocks, First Solar decided to prove the efficacy of the concept further with even larger AC Power Blocks. Later the same year, First Solar deployed two additional 1,500 Vdc array blocks at the Barilla Solar Farm in Texas, pushing the power block capacity to 5 MWdc/4 MWac. Based on the results of these pilot projects, First Solar proceeded to shift the vast majority of its projects to 1,500 V plant architectures in just two years.

When you consider the broader development and deployment of 1,500 Vdc systems, the rest of the utility-scale solar industry is not far behind First Solar’s lead. At the risk of oversimplification, 2015 was most notable for the widespread release of 1,500 Vdc–rated components—modules, inverters, combiners, fuses and so forth—certified to UL standards. In 2016, a second wave of large-scale project developers, including Recurrent Energy, began selectively deploying 1,500 Vdc PV systems as a way of testing the waters and building a knowledge base for the widespread adoption of 1,500 Vdc systems in 2017.

According to 1,500-Volt PV Systems and Components 2016–2020 (see Resources), a GTM Research report, 1,500 Vdc systems will account for 4.6 GW of global utility-scale solar installations in 2016. Though GTM Research analysts estimate that the US market will account for roughly 60% of the 1,500 Vdc field deployments worldwide in 2016, they expect that demand in the rest of the world will dwarf that in North America from 2017 forward. In other words, once early adopters have proven the technology benefits in the field, analysts expect to see a steady transition from 1,000 Vdc to 1,500 Vdc.

My own informal market survey, conducted at Solar Power International (SPI) 2016 in Las Vegas, reinforces these projections. For example, Stephen Giguere, solar division engineering director at Power Electronics, notes: “The big shift is still one more buying cycle out. Customers booked a lot of the orders we are fulfilling now while there was still uncertainty about the future of the ITC [Investment Tax Credit]. Going forward, however, all of the large systems in our queue are designed around 1,500 V products.”

Brad Dore at SMA America concurs: “Currently, the overwhelming majority of new orders US customers are placing for PV plants expected to be built next year will utilize 1,500 V technology. Globally, the transition from 1,000 V to 1,500 V is happening a little slower, but we expect the same value proposition to win out elsewhere as it is here.”

AHJ ACCEPTANCE

Paralleling the earlier shift from 600 Vdc to 1,000 Vdc PV systems, the first 1,500 Vdc field deployments in the US utilized equipment certified to international rather than UL standards, as allowed at power generation facilities governed by the National Electrical Safety Code. Since that time, changes to product safety standards and the National Electrical Code  have made it even easier for AHJs to approve and inspect 1,500 Vdc PV power plants.

Product safety standards. The International Electrotechnical Commission (IEC), the standards-making entity that has jurisdiction over Europe as well as many countries around the world, defines 1,500 Vdc as the upper limit for low-voltage electrical systems. As a result, there was no technical reason why equipment vendors could not certify PV system components at 1,500 Vdc to IEC standards. The barrier to doing so was simply market based: Did the demand justify the investment?

As a vertically integrated module manufacturer and solar project developer, First Solar was uniquely positioned to answer this question in the affirmative. By certifying its Series 4 modules to IEC standards at 1,500 Vdc, the company was able to prove its next-generation solar farm concept in the US. Because demand for utility-scale solar is particularly strong in the US, this design evolution put pressure on UL to harmonize its product safety standards with those of the IEC to allow for UL certification of modules and inverters at 1,500 Vdc.

In October 2014, the authors of the technical brief on First Solar’s next-generation PV plant noted: “The regulatory challenges in many places, particularly outside of North America, are lower due to existing IEC standards, which address 1,500 Vdc design and safety. Greater challenges are faced in the US, where the lack of established standards that address 1,500 Vdc applications often make it challenging to obtain plant construction permits from local authorities having jurisdiction.”

In practice, the barriers to deploying 1,500 Vdc systems in the US had already begun to fall. In the summer of 2014, UL adopted ANSI/UL 62109-1 as the national safety standard for PV inverters, enabling certification to 1,500 Vdc. Just a few months later, in 2015, UL published requirements for the evaluation and certification of 1,500 Vdc PV modules. According to a post on the UL newsroom: “The requirements examine the construction of the PV module, junction box, cables and connectors as per the standard UL 1703 and address potential electrical hazards associated with the increased voltage. As a result, getting approval to design and deploy 1500 V systems is now easier, enabling the pursuit of new opportunities.”

Though some efforts to harmonize UL and IEC product safety standards are ongoing, equipment vendors have successfully certified modules and inverters to UL standards at 1,500 Vdc since 2015.

National Electrical Code. Around this same time, Code-making efforts were under way to expand and clarify the PV system voltage limits in the NEC as part of the 2017 cycle of revisions. Though attempts to raise the threshold between low- and high-voltage electrical systems, as defined in Article 490, from 1,000 V to 1,500 V or 2,000 V ultimately proved unsuccessful, NEC 2017 does include additional guidance regarding maximum voltage limits for commercial roof-mounted systems and ground-mounted solar farms.

Specifically, the Code-Making Panel (CMP) revised Section 690.7 as follows (emphasis added): “PV system dc circuits on or in one- and two-family dwellings shall be permitted to have a maximum voltage of 600 volts or less. PV system dc circuits on or in other types of buildings shall be permitted to have a maximum voltage of 1,000 volts or less. Where not located on or in buildings, listed dc PV equipment, rated at a maximum voltage of 1,500 volts or less, shall not be required to comply with Parts II and III of Article 490.

The CMP has provided 1,500 Vdc systems with a clear path to market in free-field applications, while closing the door on higher-voltage systems in commercial rooftop applications. In 2015, for example, Belectric was able to deploy the world’s first 1,500 Vdc rooftop system in Berlin, Germany. NEC 2017 specifically rules out this type of development in the US by limiting nonresidential rooftop systems to 1,000 Vdc.

Compared to the drawn-out process required to transition the US market from 600 Vdc to 1,000 Vdc system architectures, industry stakeholders effectively fast-tracked the changes to codes and standards needed to allow 1,500 Vdc UL-listed products and NEC-compliant systems. This underscores the fact that 1,500 Vdc systems have much in common with 1,000 Vdc or 600 Vdc systems. This is not a revolution in PV power plant design so much as it is a natural evolution.

Ryan LeBlanc, senior application engineer for SMA America, elaborates: “The transition from 1,000 Vdc to 1,500 Vdc systems is going to be a lot easier than getting from 600 Vdc to 1,000 Vdc was. In this case, AHJs and EPCs have a precedent to follow. All we really need is higher voltage–rated equipment, which is readily available. At the system level, the savings aren’t as significant as they are when going from 600 Vdc to 1,000 Vdc, but there are incremental savings associated with a shift to 1,500 Vdc.”

VALUE PROPOSITION AND SUPPLY CHAIN

The basic value proposition for increasing PV utilization voltages is that—all else being equal—doing so will reduce wire and BOS costs. At the string level, higher utilization voltages allow for more modules and greater power capacity per source circuit. Fewer source circuits in turn permit systems to use fewer overcurrent-protection devices and, at least on paper, fewer source-circuit combiners. Perhaps most importantly, higher voltage levels make it possible to transmit more power using the same conductor or collection system. As an added bonus, plant and inverter efficiency improve in accordance with Ohm’s law, which states in part that doubling voltage will reduce conduction losses (I2R) by one-quarter for the same power level.

The caveat, of course, is that there are standard voltage levels for electrical equipment. Generally speaking, going from 600 Vdc to 1,000 Vdc PV systems did not trigger a meaningful change at the component or subcomponent level. Prior to 2012, for example, modules intended for the US market were tested and certified at 600 Vdc because this was the standard low-voltage limit defined in the NEC. Manufacturers likely sold exactly the same module in the European market with a 1,000 Vdc certification. As a result, PV modules did not really change when the NEC started allowing 1,000 Vdc system architectures. Instead, Nationally Recognized Testing Laboratories in the US simply started to conduct tests at the same voltage levels as their counterparts in Europe and the rest of the world.

The same is not true of the shift to 1,500 Vdc. The components and subcomponents that make up a 1,500 Vdc PV power plant are often different from and more expensive than those used for a 1,000 Vdc plant. In some cases the differences are subtle; in others they are obvious.

Modules. You need look no further than the PV modules themselves for an illustration of these diminished returns. Module manufacturers invariably have to charge a small premium—on the order of $0.01 to $0.02 per watt—for 1,500 Vdc modules compared to 1,000 Vdc models. While initially low production volumes likely accounted for some portion of this price premium, the environmental packaging for the 1,500 Vdc module is inherently more expensive, precisely because it has to withstand a higher electrical potential.

Consider, as an example, the product design strategies that module manufacturers use to improve resistance to potential-induced degradation (PID) at higher operational voltages. One approach is to use a glass-on-glass package in place of the typical glass-on-plastic package. To stick with a glass-on-plastic package, manufacturers invariably need to use thicker encapsulation materials to withstand the higher voltage. Since the edge seal is particularly vulnerable to leakage currents, some module manufacturers eliminate the module frame, which means that the glass needs to provide this structural rigidity; others increase the distance between the cells and the frame, which results in a slightly larger and less efficient module. Each of these approaches results in a 1,500 Vdc module that is slightly more expensive than an equivalent 1,000 Vdc model.

The fact that First Solar is the market leader in the transition to 1,500 Vdc PV power plants is undoubtedly a function of the unique electrical characteristics of its thin-film solar modules. Compared to typical crystalline silicon (c-Si) modules, First Solar’s cadmium telluride modules have higher-voltage characteristics. As a result, designers can connect only about half as many First Solar modules in series per source circuit. In 1,000 Vdc applications, for example, 20-module source circuits of roughly 6,000 watts each are possible with c-Si technologies in some climates; the equivalent building block with First Solar Series 4 modules might be 10-module source circuits at 1,150 watts each. This means First Solar’s power plants are especially sensitive to BOS costs. As a side benefit, First Solar also discovered that the performance of its modules improved, in terms of efficiency and power level, at higher utilization voltages.

Since First Solar introduced its 1,500 Vdc–certified thin-film modules in 2014, other c-Si module manufacturers have followed suit. Today, many industry-leading manufacturers— including Canadian Solar, Hanwha Q CELLS, Jinko Solar, SolarWorld, Trina Solar and Yingli—offer 1,500 Vdc UL-certified modules. The list of companies offering IEC-certified 1,500 Vdc modules is even longer.

Inverters. Incentivized in part by its strategic partnership with First Solar, GE was the first inverter manufacturer to introduce an IEC-certified 1,500 Vdc inverter. According to a company newsletter (see Resources), GE Power Electronics initially developed its LV5 series inverter for offshore wind applications and later realized that the technology could also benefit solar farm operators. The availability of new power electronics allowed GE’s product engineering team to increase both inverter input voltage and output power by 50%, and these inverter-level improvements provide additional value at the plant level.

According to Vlatko Vlatkovic, chief engineering officer at GE Power Conversion: “The new design allows us to send much more power through the same amount of copper and get big economies of scale. You won’t need as many fans, filters, concrete pads and other components for the farm infrastructure. You can change the farm’s architecture.”

The most notable change in plant architecture is that PV plant building blocks get larger. Higher operating voltages not only improve inverter power density but also decrease wire losses within the dc collection system and allow longer transmission distances. GE estimates that its larger inverter block reduces capital expenditures on a 200 MW farm by approximately $5.8M while also decreasing operating expenditures by 30%.

The technical brief on First Solar drives this point home by comparing 20 MW plant layouts at 1,000 Vdc and 1,500 Vdc. As shown in Figure 1 (p. 40), the higher utilization voltage reduces the number of power stations by 60%, from ten 2 MWdc blocks to four 5 MWdc blocks. As a secondary benefit, the layout reduces the amount of land area dedicated to inverter pads and access roads.

In spite of these power density improvements, the inverter itself is little changed. The authors of the First Solar brief note: “By and large, 1,500 Vdc inverters have the same fundamental inverter topology as 1,000 Vdc inverters—with power semiconductors and dc power-circuit components appropriately rated for the higher dc voltage. These components are covered by the existing IEC standards and readily available as they are similar to those components used in wind converters and industrial drives. 1,500 Vdc inverters have the same ac grid interface circuits, controls, protection and grid management features as 1,000 Vdc inverters.”

Like GE, Eaton provides high-voltage inverters for wind farms that it is adapting for use in 1,500 Vdc solar applications. According to Chris Thompson, the company’s business unit manager for its global solar and storage product lines: “Eaton has been supplying high-voltage inverters for storage and wind for a long time and will likely release a 1,500 Vdc solar inverter in 2017. While the package will be similar to our 1,000 Vdc model, it’s not the same inverter. You have to upgrade all of the voltage-rated components. Though some of the internal components may cost more, you can get more power out of the inverter, so the net effect is beneficial. In general, volts are cheap whereas amps are expensive.”

LeBlanc at SMA America concurs: “Inverters are fundamentally current-limited devices, and a lot of money goes into those current-carrying components. If you drive up the voltage from 1,000 Vdc to 1,500 Vdc, the busbars get smaller and the inverter gets less expensive on a dollars-per-watt basis. In effect, you can get more watts out of the same box.”

“SMA has seen a rapid migration from 1,000 V to 1,500 V systems in US utility applications because the value is compelling,” adds SMA America’s Dore. “Developers, owners and EPCs all benefit from the resulting BOS savings. To capitalize on this market demand while mitigating the risk associated with field certification, SMA recently became the first company to certify a 1,500 Vdc inverter, the Sunny Central 2500-EV-US, to the new UL 62109 standard.”

Many other vendors are following this lead. The list of inverter manufacturers with 1,500 Vdc UL-certified central inverters includes ABB, Ingeteam, Power Electronics, Sungrow and TMEIC. Some of these companies are also developing 1,500 Vdc–rated string inverters.

At SPI 2016, for example, Sungrow unveiled a 1,500 Vdc 3-phase string inverter with a nameplate capacity of 125 kW; in terms of form factor, this new inverter is roughly the same size as the company’s 60 kW–rated 1,000 Vdc model. Though the NEC limits commercial roof-mounted PV systems to 1,000 Vdc, system designers may find 1,500 V string inverters useful in commercial ground-mount applications or for building distributed PV plants (<20 MW). On larger projects, 1,500 Vdc string inverters could also prove useful as a way to develop marginal land or property boundaries, areas not well suited for large, uniform power blocks.

Combiners. BOS vendors were relatively early to market with 1,500 Vdc UL-certified combiners. For example, Shoals Technologies Group introduced a 1,500 Vdc version of its SlimLine Combiner Box in the summer of 2015. Since then, AMtec Solar, Bentek, Eaton and SolarBOS have all announced similar product releases.

At first glance, combiners seem like a great opportunity for reducing costs. As illustrated in Table 1, increasing the voltage by 50% means that you can increase string lengths proportionally, which results in a 33% reduction in the number of source circuits. If you hold steady the number of inputs per combiner, you need only about 67% as many combiners at 1,500 Vdc as at 1,000 Vdc. Unfortunately, this type of analysis tends to oversimplify the situation.

Dustin Watson, vice president of sales at SolarBOS, explains: “At the moment, EPCs should expect to pay a 50% premium for 1,500 Vdc string combiners compared to 1,000 Vdc versions. We do expect this premium to come down over time, as we have already seen significant cost reductions on 1,500 V–rated components since the beginning of the year. We anticipate additional cost decreases in 2017 as more of our customers begin to adopt 1,500 Vdc designs and new components enter the market. This is comparable to what happened a few years ago when the markets transitioned from 600 Vdc to 1,000 Vdc.”

Though the premium for 1,500 Vdc combiners will undoubtedly come down and is offset somewhat by labor savings, Thompson at Eaton cautions: “Even with volume, these are always going to be more expensive components. Pound for pound, dc arcs are probably four times harder to break than ac arcs, because there isn’t a zero crossing. To increase the voltage rating for PV fuses by 50%, you need a different and more expensive fuse element; as a result, the physical package for the fuse and the fuseholder gets bigger and more expensive. The same is true for the dc disconnect; it gets bigger and more expensive. Now you need bigger and more expensive combiner-box enclosures, which means you can pack fewer combiners per pallet or truck. These little things ripple through the cost of the system.”

Tom Willis, director of sales at AMtec Industries, provides an example: “Whereas a typical 24-string 1,000 Vdc combiner box fits into a 24" x 24" x 8" enclosure, you need a 30" x 24" x 8" enclosure to handle the same number of circuits at 1,500 Vdc. While the cost premium is about 40%, this will come down as demand goes up.”

The alternative to using larger combiners is to aggregate fewer circuits per combiner. “To a certain extent, there is a convenience factor to dc block sizing,” elaborates Coel Schumacher, chief technical officer at SolarBOS. “If you are used to aggregating 400 or 500 modules per combiner at 1,000 Vdc, you may want to do the same thing at 1,500 Vdc, perhaps for monitoring and O&M purposes. So a customer who is accustomed to ordering 24-input 1,000 Vdc combiners might opt for 16-input combiners at 1,500 Vdc. That way the number of combiners stays about the same, as does the size of the combiner box and the number of modules aggregated per combiner.”

Collection systems. By all accounts, the real cost savings associated with 1,500 Vdc plant architectures comes from material and labor savings associated with the dc collection system and to a lesser extent the ac collection system. Though PV connector companies such as Multi-Contact had to certify their products for higher operating voltages to meet market demand, wire and cable suppliers already offered 2,000 V–rated single conductor solar cable, in both copper and aluminum. Since EPC firms can use the same cables, conduits and trenches for both 1,000 Vdc and 1,500 Vdc systems, any material and labor reductions due to the higher operating voltage are pure cost savings. GTM Research estimates that savings could be as high as $0.03 per watt within the dc collection system and $0.005 per watt within the ac collection system.

POTENTIAL CHALLENGES

However substantial the rewards associated with increasing PV plant voltage from 1,000 Vdc to 1,500 Vdc, there is clearly no free lunch. EPC firms have to spend money to save money. Moreover, higher operating voltages carry some technology risks, most notably PID. Early adopters could also run into challenges associated with dc arc-flash hazard levels and dc arc-fault protection requirements.

PID. Industry veterans will recall that instances of voltage-driven performance degradation increased after the widespread adoption of 1,000 Vdc plant architectures. In the wake of these problems, industry stakeholders developed new performance tests and enhanced module certifications relatively quickly. Though module manufacturers and testing laboratories have extrapolated these tests to qualify module resistance to PID at 1,500 Vdc, it remains to be seen how effective these laboratory tests prove in terms of identifying actual field failure mechanisms.

Thompson, who qualified inverters for First Solar before joining Eaton in 2010, notes that even modest PID effects can offset any plant-level savings associated with higher operational voltages. He predicts: “I bet we see some companies having premature degradation and warranty issues 5 years from now; it will be vendor specific and perhaps regionally specific. Though investors are comfortable with the risks, PID is a very complex phenomenon. Installations in hot, humid climates, of course, are the most vulnerable, but grounding is also a factor. It will be years before we understand the full implications of increasing operating voltages by 50%.”

Arc-flash hazard. The goal of an arc-flash hazard analysis is to protect workers from dangerous conditions associated with electrical arcs, such as intense releases of heat and pressure. Unfortunately, the arc-flash hazard levels on the dc side of a PV system are not well understood. Traditional arc-flash hazard calculations are applicable to ac rather than dc circuits; moreover, a PV power source is inherently current limited.

In the absence of empirical data that quantify actual dc arc-flash hazards in PV systems, engineers working on large-scale solar farms often rely on conservative calculation methodologies and assumptions. Some system and application engineers believe that this approach misrepresents the dc arc-flash hazards to personnel by making them appear worse than they may be in reality.

“From time to time, we see the aftereffects of dc arcing inside a SolarBOS combiner,” notes Schumacher, “and these are clearly not explosive arc-blast events. We see damage due to molten metal, for example, but no evidence of vaporized metals, such as you would expect to see with an ac arc flash. Of course, once you increase the array operating voltage by 50%, the calculated hazard levels go up even further. This could have the effect of making it more difficult for personnel to install, commission and maintain 1,500 Vdc PV systems—perhaps unnecessarily requiring arc-flash suits.”

Arc-fault protection. The goal of dc arc-fault detection and interruption is to prevent fire damage due to arcing faults in PV systems or components. The CMP first introduced dc arc-fault protection requirements to the NEC as part of the 2011 cycle of revisions by adding a new section, 690.11, “Arc Fault Circuit Protection (Direct Current).” It has modified these requirements with each successive Code edition.

Under NEC 2011, for example, dc arc-fault protection requirements apply specifically to PV systems on buildings. As part of the 2014 cycle of revisions, the CMP revised Section 690.11 so that it applies to all PV systems operating at 80 V or greater, regardless of whether the system is on a building or ground mounted. Though these basic requirements are unchanged under NEC 2017, the CMP added a new article—691, “Large-Scale PV Electric Power Production Facility”—that potentially exempts PV power plants with a capacity of 5 MW or greater from the requirements in Article 690. For example, 691.10 states: “PV systems that do not comply with the [dc arc-fault protection] requirements of 690.11 shall include details of fire mitigation plans to address dc arc faults in the documentation required in 691.6.”

The potential challenge here is that dc arc-fault protection requirements clearly do not apply to 1,500 Vdc solar farms deployed under NEC 2011. While the requirements appear to apply under NEC 2014, no 1,500 Vdc arc-fault protection equipment exists, leaving room for interpretation. Some AHJs may decide to waive these requirements, as is their prerogative under 690.4; others could object to 1,500 Vdc plant architecture, since it is possible to meet 690.11 at 1,000 Vdc. The most recent Code edition suggests a possible middle ground, which is to have an independent engineer design an alternative method of compliance.

CONTACT:

David Brearley / SolarPro  / Ashland, OR / solarprofessional.com

RESOURCES

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

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

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

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The aging fleet of fuse-grounded string inverters presents a potential challenge for service providers since the industry has largely transitioned to non-isolated inverters. Prior to 2012, the vast majority of interactive inverters fielded in North America utilized a traditional fuse-grounded isolation transformer–based topology. Since then, non-isolated string inverters have become the de facto industry standard in residential and commercial applications. This evolution is because transformerless inverters offer improved performance—in terms of both cost and efficiency—and improved safety relative to older transformer-based models.

As fuse-grounded inverters reach the end of their warranty term, which is typically between 5 and 10 years, end-of-life failures occur with increasing frequency. The challenge for service personnel is that direct replacement models are not available for any inverter that is more than 5 years old, unless you uncover new old stock via a secondary market such as eBay. As a result, service personnel generally need to install a non-isolated inverter in place of a failed transformer-isolated model. This new inverter is much more attractive than old stock, since it carries a valid manufacturer’s warranty and offers enhanced safety features, such as dc arc-fault detection and superior ground-fault protection. However, some AHJs could interpret the National Electrical Code in ways that effectively disallow this inverter upgrade.

In this article, I examine relevant Code requirements, including revisions introduced in NEC 2017, and provide recommendations about how solar companies and AHJs can move forward on this issue. Replacing legacy fuse-grounded PV inverters with currently available non-isolated inverters not only is consistent with the most recent Code revisions, but also is allowed under previous editions.

Brief History of PV System Grounding

The basic concern about retrofitting non-isolated inverters in legacy PV arrays arises from the conceptual issues surrounding PV system grounding in accordance with the NEC. Prior to approximately 2012, most PV systems in the US included transformers to isolate the grounded ac grid from the grounded dc conductors. These isolation transformers are expensive, inefficient and heavy. To eliminate the isolation transformer and still connect a PV system to the grounded utility grid, inverter manufacturers must remove the system grounding bond on the dc side, as shown in Figure 1.

Technically, a PV system that has had the isolation transformer removed is classified as non-isolated. However, many PV practitioners refer to these systems as ungrounded since the ground bond to the dc conductors is intentionally removed. This terminology use is unfortunate, as it is inaccurate to describe non-isolated PV systems interconnected to grounded ac services as ungrounded. Because most utility services in the US are grounded, and most non-isolated PV inverters require installation on a grounded ac service, typical non-isolated PV systems in the US are grounded via the ac service when operational; these systems are ungrounded only when nonoperational.

This ungrounded-when-non-operational state is no different from what occurs in a fuse-grounded PV system when the ground-fault fuse blows. According to NEC Section 690.5(B)(2) and interactive inverter certification standards, a PV system with a blown ground-fault fuse must “cease to supply power to output circuits.” After a ground fault is detected and interrupted in this manner, fuse-grounded PV systems are ungrounded and nonoperational. By comparison, PV systems with non-isolated inverters enter this ungrounded-when-nonoperational state every night after disconnecting from the utility grid. Most importantly, the non-isolated system does not present a fault or safety hazard, as its ground-fault detector is 50 times more sensitive than that of the fuse-grounded system.

Legacy vs. New Single-Phase Inverters

As legacy transformer-isolated inverters fail, O&M providers have two options for getting the PV system back on line. The first option is to find a transformer-isolated inverter that works with the array. The second option is to retrofit a non-isolated inverter, which is the preferred approach.

Transformer-isolated option. Inverter manufacturers have generally phased out the production of transformer-isolated inverters in favor of safer and cheaper non-isolated models. However, you can occasionally find new old stock or lightly used replacement inverters on eBay or in the dusty corner of someone’s warehouse. Unfortunately, any inverter that is more that 5 years old will not have dc arc-fault detection, which is a standard feature on new non-isolated string inverters since undetected dc arc faults present a potential fire hazard.

In addition, the older inverter has a very simple ground-fault protection system that uses a 1 A fuse, located in the grounded conductor-to-ground bond, to detect and interrupt dc ground faults. A ground fault with 1,500 mA of current will clear (open) this 1 A fuse in about one minute. By comparison, the ground-fault detector in a non-isolated string inverter will trip at 30 mA of ground current in less than one second. Based on these detection levels and clearing times, the fault energy required to clear a ground fault is 3,000 times greater in a legacy residential inverter system than in a system with a non-isolated string inverter.

Non-isolated inverter option. Newer non-isolated inverters clearly provide a far safer PV system. However, differing opinions about system grounding classifications and requirements may complicate this option. Since I regularly work with AHJs, I have posed the following question to them many times: “If an existing PV system experiences an inverter failure and a contractor pulls a permit that includes replacing the failed inverter, would you accept the installation of a safer inverter even though some engineers consider the repaired system ungrounded rather than solidly grounded?”

I get a fairly consistent response to this question. If the new PV system is safer, most AHJs will approve the proposed installation based on the following language in NEC Section 90.4: “By special permission, the authority having jurisdiction may waive specific requirements in this Code or permit alternative methods where it is assured that equivalent objectives can be achieved by establishing and maintaining effective safety.”

Via this allowance, even AHJs who believe that non-isolated inverters are subject to ungrounded PV system requirements can approve the use of non-isolated inverters for retrofit purposes. It is also possible to show that ungrounded requirements simply do not apply in this scenario.

Non-Isolated ≠ Ungrounded

In 2005, the Code-Making Panel (CMP) responsible for Article 690 introduced Section 690.35, “Ungrounded PV Power Systems.” A close reading of the language makes it clear that these ungrounded PV system requirements do not apply to systems deployed with non-isolated inverters: “Photovoltaic power systems shall be allowed to operate with ungrounded PV source and output circuits where the system complies with 690.35(A) through (G)” [emphasis added].

When you connect a non-isolated inverter to a grounded ac service, the system is grounded whenever the inverter is operating. Therefore, the proper application of the NEC does not require implementing 690.35 (A) through (G) for non-isolated PV systems connected to grounded ac services. Until recently, most engineers did not recognize this ac service–ground connection as a PV system ground.

As a result, PV systems deployed with non-isolated inverters are widely misidentified as ungrounded PV systems. This is a misnomer. Ungrounded systems operate without a connection to earth; non-isolated inverter systems are connected to earth when operating, but floating in reference to earth when not operating. Unfortunately, this misnomer is also ubiquitous. For several years, most solar professionals and AHJs have diligently, if mistakenly, applied 690.35(A) through (G) to non-isolated inverter systems.

Ungrounded system requirements. The practical requirements for ungrounded PV systems are well known to solar practitioners. Subsection 690.35(A) requires disconnecting means in both poles of the array for ungrounded PV source and output circuits; 690.35(B) likewise requires overcurrent protection in both poles of the array. Meanwhile, 690.35(D) mandates the use of PV Wire for exposed single conductors, which effectively rules out the use of USE-2 conductors in these systems.

This latter requirement had the effect of slowing the adoption of non-isolated inverters in the US. While nearly all PV modules sold today have PV Wire cable whips, this was not always the case. Prior to 2013, very few PV modules were manufactured with PV Wire cables. Since older PV modules are unlikely to have PV Wire cables, some jurisdictions have questioned whether they should allow retrofit installations of non-isolated inverters in legacy PV arrays.

Alternative means of compliance. The NEC has long addressed alternative methods of system grounding for PV power sources. Since the mid-1990s, Section 690.41 has allowed for the use of solidly grounded systems as well as systems that “use other methods that accomplish equivalent protection in accordance with 250.4(A).” Since non-isolated inverter systems fit this description, they are technically not subject to the ungrounded PV system requirements in 690.35. Therefore, it is fully acceptable to retrofit non-isolated inverters in legacy PV arrays, even those deployed using standard wiring methods for grounded PV systems. Since this was not clear to many AHJs and solar practitioners, Code-Making Panel 4 (CMP 4) addressed this as part of the 2017 cycle of revisions.

System grounding in NEC 2017. The most recent edition of the NEC resolves the confusion regarding grounded versus ungrounded system grounding designations. CMP 4 introduced a term used in Europe—functional grounded PV system—which NEC  690.2 defines as having “an electrical reference to ground that is not solidly grounded.” An informational note clarifies that both PV systems with fuse-grounded inverters and those with non-isolated inverters meet the definition of a functional grounded PV system. In addition to adding this new system grounding definition, CMP 4 eliminated Section 690.35, “Ungrounded PV Power Systems,” in its entirety.

These changes mean that all PV systems are subject to the same installation requirements under NEC 2017, regardless of inverter topology. As detailed in Figure 2, these unified installation standards are as follows: overcurrent protection is required in one leg of a PV circuit only [690.9(C)]; disconnecting means are required in both legs of a PV circuit [690.15]; and both USE-2 and PV Wire are allowed as single-conductor cable in a PV array [690.31(C)].

Recommended Practices

Based on this understanding of existing Code requirements and factoring in the relevant changes introduced in NEC 2017, I recommend the following practices when retrofitting non-isolated inverters in place of legacy transformer-isolated inverters.

1. There is no need to replace existing USE-2/RWH-2 cables with PV Wire. PV systems installed more than 3 years ago are unlikely to have PV Wire cable whips or source-circuit conductors. It is not possible to retrofit these modules with PV Wire, nor is it necessary. The USE-2/RHW-2 cable installed within these arrays is perfectly good and is safe for the operating life of the PV system. NEC 2017, the most recently adopted Code edition, supports this practice.

2. If the existing array has white wires for the previously grounded conductors, simply re-identify these as ungrounded conductors. Whereas one pole of legacy transformer-isolated PV arrays is connected to ground via a fuse, both poles of non-isolated PV arrays are balanced on either side of the ac ground reference. This means that a PV array operating at 300 Vdc has a voltage to ground of 150 Vdc for both the positive and the negative poles. In other words, neither conductor is at ground potential even though the circuit is referenced to ground through the grounded ac service transformer. Since neither pole of the array is intentionally grounded, service personnel should re-identify any dc conductors with a white marking or insulation, since these wires will no longer be at ground potential.

Prior to the introduction of non-isolated inverters, installers commonly used white markings to identify intentionally grounded conductors in a PV array. This practice was intended to meet NEC Section 200.6, which includes a special allowance for re-identifying grounded single conductors in PV systems with a white marking [200.6(A)(6)]. Where existing USE-2/RHW-2 conductors are identified in this manner, service personnel can simply remove or cover the white marking. In the event that existing conductors have white insulation, I recommend re-identifying these white conductors by some suitable means rather than removing and reinstalling new conductors, based on the precedence that 200.6(A)(6) sets for the re-identification of small PV system conductors.

3. Installing a dc disconnect that opens both positive and negative poles of the PV array will bring the existing system into full compliance with NEC 2017. While not required in existing installations, the safest and best approach is to replace the dc disconnect on each inverter with one that opens both the positive and negative poles of the PV array. You can easily rewire even the standard Square D HU361 disconnect used on many thousands of systems to open both positive and negative conductors. This practice makes the inverter much safer to service in the event of a ground fault. Fortunately, most replacement inverters on the market today have an integral dc disconnect that opens both poles. It is very easy and straightforward, therefore, to upgrade an existing PV array for full compliance with the newest edition of the NEC.

Bill Brooks / Brooks Engineering / Vacaville, CA / brooksolar.com

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