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Changes are coming to solar inverter standards, bringing with them new business opportunities that the installer community should start preparing for now. Updated safety and performance standards - specifically, a supplement to UL 1741 - are expected to be published in the coming months, unlocking inverter functions that promise to smooth solar integration onto the grid while enhancing grid reliability. This key release will be followed later by a revision to IEEE 1547.

UL 1741 is the Underwriters Laboratory (UL) standard that ensures safe equipment operation for inverters delivering enhanced, grid-supporting capabilities. IEEE 1547 is the standard governed by the Institute of Electrical and Electronics Engineers (IEEE) that covers inverter equipment’s interconnection with the electric grid.

Leveraging expanded inverter functions for grid services, such as voltage and frequency regulation, will allow solar developers to grow and diversify their customer base to include electric utilities. Inverter manufacturers and the solar development community have expertise that is definitely in demand as utilities integrate increasing amounts of solar power onto the grid and confront potential disruptions to system reliability.

Concern about solar impacts on grid reliability can, in some cases, lead to utility requirements for interconnection studies that add considerable time and cost to project development. In extreme cases, such as in Hawaii, utilities have placed a temporary moratorium on additional solar PV systems on already saturated circuits.

From the utilities’ perspective, these actions are intended to ensure that distributed generation does not degrade power quality and reliability at the circuit or system level. Such concerns are valid when a utility is the sole provider of ancillary services, but the robust nature of inverters’ grid-support capabilities (e.g., voltage regulation using reactive power) could be a catalyst for improved interconnection processes and expanding feeder hosting capacity.

According to the Smart Electric Power Alliance’s 2015 Solar Market Snapshot, as of the end of last year, four states had installed more than 1 GW of solar power. These inverters are set to maximum power point tracking, which maximizes real power output, and a unity power factor, which prevents the inverters from actively producing or absorbing reactive power. These states have what some may consider high penetrations of solar, yet they have maintained system reliability even though they are, in isolated areas, approaching the upper limit of circuit hosting capacity.

Some players are already positioning themselves for the opportunities such solar growth could create, as they are working with utilities to pilot new programs in high-penetration markets. For example, both inverter manufacturer Enphase and installer SolarCity have collaborated with Hawaiian Electric Co. on adjusting inverter set points to allow for a wider operating range for system frequency.

In the case of passive inverter functions, the issue is basic interconnection, but enabling grid-supporting features moves the conversation into more complex grid integration of distributed energy resources (DERs). Integration can ensure reliability for the utility while raising hosting capacity to allow for expanded growth of solar, potentially even on circuits previously closed to additional development.

In other words, the interest is definitely there - on both sides of the inverter. Based on research reports - and attendance at conference workshops on the topic - we are seeing strong utility interest in advanced inverter functionality. Now that more than 1 million solar installations are on the U.S. grid, utilities are increasingly viewing the technology as a potential asset to enhance system reliability.

At the beginning of each year, we survey utilities nationwide, asking about their activities related to solar power. Beyond meticulously quantifying growth in solar capacity, we also capture key information about utility programs and interest in the technology and policy issues emerging at the intersection of the utility and solar industries.

This year, 190 utilities responded to an inverter-related question, with 109 reporting interest in advanced inverters but only 14 actively implementing the technology. Last year, 67 utilities reported interest, but again, only 14 had begun advanced inverter deployment. In other words, from 2015 to 2016, interest grew more than 60%, but the number of implementation programs remained unchanged (see Figure 1).

At least part of the reason for the gap between interest and active program development is the need for safety and performance standard updates. For example, the UL 1741 update has been under way for more than a year, with no release date set as of this writing. Even last year’s revision to California’s Rule 21, the state code for interconnection, directly referenced the standards process. The new Rule 21 must take effect within 12 months of the final publication of UL 1741 Supplement A, with the expectation it would be finalized in the near future.

Another challenge is the lack of standards for how inverters and other DERs communicate with specific utility platforms - an issue that, like other aspects of the growth of DERs on the grid, will continue to evolve with technology. Utilities, solar installers, customers and other industry stakeholders will all have to keep up.

Waiting for updates

At their most basic level, inverters convert the direct current generated by solar PV panels into the alternating current that powers the grid, and until recently, that was all solar installers or utilities expected or needed them to do.

But as solar penetrations on local distribution lines and the grid, in general, have grown, utilities have found these installations must be actively integrated into the electric ecosystem to preserve reliability. Although the exact levels of penetration at which disruptions may occur may vary, studies have shown that rising levels of solar on the grid increase voltage variability on distribution circuits. Such variability, in turn, can cause load tap changers and other voltage control devices to adjust up one order of magnitude more often than before the solar was installed, increasing both wear and maintenance costs on the equipment.

Inverters, on the other hand, use no moving parts to manage voltage fluctuations. Rather, volt-watt and volt-VAR functions now embedded in all inverters can effectively regulate circuit voltage, mitigating the need for frequent mechanical adjustments that use legacy voltage control assets.

So, why aren’t these features being deployed now? The short answer is the industry standards required to activate them haven’t been released yet.

As noted, the key safety standard, UL 1741 - and specifically Supplement A, which contains the needed testing procedures - is still being updated by UL, with no set release date. It will be the “permission slip” for widespread installation of inverters with enhanced features.

In the meantime, a few utilities, working with inverter companies, have negotiated special purpose certifications with Underwriters, allowing them to install and test some inverters on a pilot basis, using the near-final language of the draft 1741 update.

On the other hand, UL listing is not required for utility equipment in most areas, based on the understanding that each utility is the authority on its own grid hardware needs. Consequently, centralized inverters for utility-scale solar power plants have been capable of delivering grid-supporting functions for years. Whether a utility dispatches them for that purpose depends on the utility’s need for the grid service and its access to the hardware - seeing as most solar installations are, in fact, not utility-owned.

From the residential customer perspective, UL listing is required according to local building and electrical codes. Simply put, anything plugged into an outlet or wired into the grid must be able to perform its function safely and reliably within the established standards.

 

Communications conundrum

Once grid-supporting inverter functions are unlocked, service providers, utilities and grid operators will face a new challenge - communicating with inverters to activate and control the reliability enhancements they can provide.

UL 1741 and its Supplement A will be the code that all manufacturers will have to meet for UL listing. Meanwhile, IEEE 1547 - also under revision and projected to be finalized by 2018 - will govern the specifics of how inverters perform discrete functions, such as voltage control.

Communications standards, on the other hand, will be left to the platforms with which the inverters interact - like software that is compatible with a PC or Mac. Customers - which, in most cases, will mean utilities - will determine communications connectivity between inverters and the grid based on existing hardware and control systems, the benefits of each protocol, and individual preferences.

Several protocols could work - for example, DNP3, IEC 61850 and Modbus - but each has advantages and disadvantages. Utilities are already using these standards for other applications; however, not all inverters can adequately communicate according to utility-preferred protocols. Intermediate hardware, such as the communications enclosure labeled No. 2 in Figure 2, becomes necessary in these cases to mediate between the inverter’s and the utility’s communication protocols.

One example of the challenges raised by this disconnect is that not all inverter-compatible standards allow devices to “push” data to the central control system outside regular monitoring intervals. Protocols lacking this capability require the utility’s control systems to monitor all inverters’ data streams in real time to detect aberrations that might warrant a response, usually in the form of a command to adjust the inverters’ performance. “Pushing” notifications up the system hierarchy can more efficiently allocate communications bandwidth.

On the other hand, anti-islanding - which prevents an inverter from putting power on a distribution circuit during an outage - is handled natively within the inverter, ensuring that safety is not a factor in the communications compatibility choice.

The unfolding changes to inverter standards are opening an opportunity for solar and energy storage developers to use their inverters - or to aggregate their customers’ inverters - to support the grid as service providers to utilities. Where appropriate, they could also sell aggregated services in ancillary services markets under independent system operators that manage the transmission grid.

Ancillary services may include regulation and contingency services, such as voltage regulation and synchronous reserve, that in total comprise reliability services. The ability for non-utility players to provide these services may vary according to state regulations, which may require eventual modification - a process currently under way in California, New York and other states.

However, not all utilities will adopt software control systems and networking for DERs just because their customers adopt solar en masse. The coming standard updates will also enable inverters to autonomously deliver voltage and frequency regulation without communicating with a central controller. Operating parameters encoded on inverter firmware specify output behavior based upon inputs from detected power quality conditions. For example, detecting a specific grid frequency above 60 Hz, the North American grid standard, would cause the inverter’s frequency-watt function to reduce real power output in proportion to the frequency increase, countering the over-frequency condition.

Such autonomous grid-supporting functions will increase reliability without requiring major disruptions in distribution grid operations, but they will still usher in new business opportunities for solution providers. Developers and DER aggregators can engage with distribution grid operators to deliver services to enhance reliability while also potentially reducing grid operating costs.

Photovoltaic solar systems are durable goods with 20-year life spans, which means growth will eventually slow as the market becomes saturated and fewer suitable rooftops remain to host installations. Selling reliability services by leveraging existing and future installations could simultaneously diversify a solar developer’s product offerings and customer base and strengthen its long-term outlook.

That opportunity will be moot until utility regulation allows for more sophisticated rate designs to compensate customers and service providers for ancillary services. Under traditional net metering, customers could lose money if they were to use these advanced inverter functions to support the grid because, at present, compensation relies on real power output. Technology alone will not transform the grid into a less centralized machine with vastly more renewable resources. Regulation and markets must also evolve. As is often the case in the power sector, technology is rarely the hard part.

 

Ryan Edge is a research analyst at the Smart Electric Power Alliance, where he researches grid integration of distributed energy resources, solar markets and utility business models.