Practical Application of NEC 2017
Inside this Article
Every 3 years the solar industry receives an updated set of instructions for designing and installing PV systems—the National Electrical Code. Although adoption dates for the new Code vary by jurisdiction, many states will be operating under NEC 2017 by the end of this year.
In this article, we discuss the practical implications of NEC 2017 for PV system design and installation; we also provide specific information about the intent of the new requirements, compliance strategies, cost implications and perspectives from industry experts. This article references callout tags, shown in Figure 1, that provide system designers with a quick guide to 2017 Code changes.
Note that large-scale PV systems are not a main focus of this article. One of the changes in NEC 2017 is the introduction of Article 691, “Large-Scale Photovoltaic (PV) Electric Power Production Facility,” which applies to non–utility-controlled solar farms with a capacity greater than or equal to 5 MWac. The focus of this article is those residential, commercial and industrial PV systems that must comply with Article 690.
Callout A: Functional Grounded PV Systems
NEC 2017 introduces a definition for a functional grounded PV system, which is one that “has an electrical reference to ground that is not solidly grounded.” Unsurprisingly, this category includes PV systems that the industry previously referred to as ungrounded, which includes the majority of contemporary string inverters and module-level power electronic (MLPE) devices. Surprisingly, the functional grounded concept also applies to PV systems previously referred to as grounded, which includes legacy systems and large-scale systems that use transformer-isolated inverters.
An informational note in 690.2 elaborates: “A functional grounded PV system is often connected to ground through a fuse, circuit breaker, resistance device, non-isolated grounded ac circuit, or electronic means that is part of a listed ground-fault–protection system. Conductors in these systems that are normally at ground potential may have voltage to ground during fault conditions.” Any technician who has had to troubleshoot a ground fault in a so-called “grounded” PV system knows that “if a ground fault is indicated, normally grounded conductors may be ungrounded and energized.” That is because these systems make the connection to ground via a fuse, which does not meet the solidly grounded definition in Article 100.
The implications of the functional grounded PV system concept ripple throughout NEC 2017, affecting requirements related to disconnecting means, overcurrent protection, wiring methods and conductor identification. While the practical implementation of these changes is not difficult, especially in residential applications or systems with MLPE, it may take some time for installers and inspectors to align their practices and expectations with the new requirements.
Jason Fisher is Solar City’s principal compliance engineer as well as a member of Code-making panel (CMP) 4, which is responsible for Articles 690 and 705. Fisher notes: “In the short term, the new PV system grounding configurations in 690.41 will likely cause some confusion for the installation and enforcement communities. While the new grounding configurations are more comprehensive and accurate than those in previous Code editions, they do have implications beyond grounding practices related to conductor color coding, overcurrent protection and disconnecting means. Since these new installation methods are most appropriate for our current limited electrical systems, I am confident that everyone will become accustomed to these changes over a short period of time. Once you understand the definition of a functional grounded PV system, you realize that we almost never install solidly grounded or ungrounded PV arrays.”
According to Bill Brooks, principal of Brooks Engineering and another member of CMP 4, the expanded system grounding configurations in 690.41 will actually simplify system design, installation and inspection. Brooks points out that CMP 4 was able to eliminate Section 690.35, “Ungrounded PV Systems,” in its entirety as part of the 2017 cycle of revisions. The definition of a functional grounded PV system includes not only PV systems deployed with transformerless (TL) or non-isolated inverters, but also PV systems deployed with transformer-isolated inverters. Brooks concludes: “We now have a single wiring method that works for all types of PV systems and inverters. This single wiring method will help contractors and AHJs, saving everyone time and money. It is also safer.”
Callout B: Conductor Color Marking and Wire Type
Section 690.31(B)(1) permits only solidly grounded conductors to have a white or gray outer finish per 200.6. In light of the new definition of functional grounded systems and the changes in 690.41 and 690.42, the only type of PV system designated as solidly grounded is one with no more than two PV source circuits, and with no dc circuits on or in a building. Thus, practically speaking, any residential or commercial PV system can no longer have field-installed white- or gray-colored dc PV conductors. Because MLPE-based systems without field-installed dc wiring and TL-type string inverters (where the transition away from white- and gray-colored conductors has already occurred) dominate the residential and commercial markets, this is generally not a significant change for most installers. The exception to the rule is large-scale ground-mounted systems deployed using central inverters with fuse-based ground-fault–protection devices: Since these systems are also considered functional grounded under NEC 2017, installers can no longer use white or gray conductors in these applications.
What conductor colors should integrators use? The NEC does not include any prescriptive requirements, except that conductors should not be white or gray [690.31(B)(1)], or green or bare [250.119]. Identifying conductor polarity is important for avoiding field wiring mistakes, and many installers default to using red (positive polarity) and black (negative polarity) for field-installed dc conductors. Installers should be aware, however, that some red conductors have been known to fade to white after short- to medium-term UV exposure. A good option for both longevity and polarity identification is to use black conductors with a colored tracer stripe visible along the length of the conductor.
Servicing legacy systems. The new grounding nomenclature does away with a particularly problematic previous Code prescription that required PV Wire for exposed single-conductor cables in “ungrounded” PV systems, which excluded the use of USE-2 conductors. This requirement meant that service technicians faced nearly insurmountable Code-compliance issues when replacing older “grounded” inverters with TL inverters, as these legacy systems often rely on USE-2 conductors for field wiring. Section 690.31(C)(1) now clarifies that installers may use both PV Wire and USE-2 for any exposed outdoor PV source-circuit wiring within the array.
Due to the new color-marking requirements, however, technicians should be particularly cautious when performing maintenance on older systems. Never make assumptions about polarity or voltage based on labels or color coding. Always use a multimeter to verify potential with reference to ground.
Callout C: Voltage and Current for Systems ≥ 100 kW
Articles 690 and 691 now define generating capacity as “the sum of parallel-connected inverter maximum continuous output power at 40°C in kilowatts.” As part of the 2017 cycle of revisions, CMP 4 made an effort to reduce costs for larger PV systems, specifically those with a generating capacity greater than or equal to 100 kW. To that end, it added new maximum voltage and circuit current calculation methods, in 690.7(A)(3) and 690.8(A)(1)(2), that allow PEs to use computer simulations to calculate these values. While the traditional calculation methods ensure safety, the CMP recognized that they may also be overly conservative. Using computer models to simulate maximum voltage and current is not only more accurate, but also may allow for more modules per source circuit or smaller conductors and conduit—all of which can lower material costs.
Designers on projects with a generating capacity of more than 100 kW can utilize these new calculation options where a licensed PE designs the system using “an industry-standard method” and provides stamped documentation. Informational Notes clarify that Sandia National Laboratories’ “Photovoltaic Array Performance Model” is one example of an industry-standard method for calculating these values. Since a variety of common PV system simulation programs—such as Helioscope, PVsyst and SAM—incorporate the Sandia model, PEs can use these platforms to calculate maximum voltage and current values for dc PV circuits.
Calculating maximum current. With regard to the maximum current calculation for PV source and output circuits, it is worth noting that 690.8(A)(1)(2) contains two directives. First, the value must be based on the “highest 3-hour current average resulting from the local irradiance on the PV array accounting for elevation and orientation.” This is the value that PEs can derive from simulation program data. Second, the Code establishes a floor or minimum value that applies regardless of the simulation results. Specifically, the current value cannot be less than 70% of the value calculated using 690.8 (A)(1)(1), which is the traditional method of calculating the maximum current based on 125% of the parallel-connected PV module Isc ratings.
“It will take engineers a while to grasp the maximum current calculation method,” opines Brooks, “but once they do, PV system designs will improve. The new calculation method will reduce conductor and conduit costs, which make up an increasing percentage of the overall costs in large PV systems.”
As an example, consider a case in which a professional electrical engineer performs a simulation showing that the highest 3-hour average annual source-circuit current value is 8.6 A for an array made up of modules with an Isc rating of 9.49 A. If the system has a generating capacity of less than 100 kW, the PE must size the source-circuit conductors based on 690.8(A)(1)(1): 9.49 A x 125% = 11.86 A. If the system has a generating capacity of more than 100 kW, the PE can size the conductors based on the simulated value (8.6 A), according to 690.8(A)(1)(2), provided that the simulated value is not less than 70% of the 690.8(A)(1)(1) value. In this case, the simulated value is the maximum current for design purposes, since 8.6 A is higher than the minimum allowable value of 8.3 A (11.86 A x 70%).
Maximum voltage. Integrators and inspectors should note that 690.7 expands on the maximum voltage limits between any two circuit conductors and any conductor and ground. As in earlier Code editions, the maximum allowable voltage in one- and two-family residential applications remains 600 Vdc. Unlike in earlier editions, the maximum allowable voltage for PV systems on other types of buildings is now 1,000 Vdc. Ground-mounted systems, meanwhile, are not subject to a voltage limitation and do not need to comply with Parts II and III of Article 490 if they have a rated voltage of 1,500 Vdc or less.
Callout D: DC Arc-Fault Detection and Interruption
The 690.11 requirements for dc arc-fault circuit protection for PV systems operating at 80 Vdc or greater are unchanged in 2017. However, the CMP added an exception for PV output circuits and dc-to-dc converter output circuits not in or on buildings; this exception applies to circuits that are direct buried or installed in metal raceway or enclosed metal cable trays. It is also worth noting that 691.10 allows for large-scale (5 MW or greater) PV systems that do not comply with 690.11, provided that a PE designs and documents an alternative fire mitigation plan.
Brooks explains the logic behind these requirements: “The exception in 690.11 is based in part on the fact that no arc-fault–detection equipment exists for circuits operating above 40 A. While there are no protective devices that address PV output circuits, arcing faults in circuits that are direct buried cannot start a wildfire, and the ground-fault–protection system will detect arcing faults in circuits in metal raceways and enclosures. Since the exception does not cover source circuits, ground-mounted PV plants with a generating capacity less than 5 MW are still required to have arc-fault detection on source circuits. Developers of large-scale systems can look to Article 691.”
It is important to note that the dc arc-fault exception for PV output circuits does not cover roof- or building-mounted systems. Unless UL develops new product safety standards to address higher-current dc arc-fault devices, dc PV circuits operating above 80 V and 40 A cannot comply with NEC 2017, which means that higher-capacity central inverters with PV output circuits are essentially not allowed in rooftop applications. String inverters with integrated dc arc-fault protection can meet 690.11 requirements in rooftop or ground-mounted applications. Where the exception applies, ground-mounted applications can use dc combiners with string-level arc-fault devices.
Callout E: Rapid Shutdown of PV Systems on Buildings
For the second Code cycle in a row, 690.12, “Rapid Shutdown of PV Systems on Building,” is raising eyebrows. The CMP made significant changes and additions to this section, expanding it from a mere 133 words in NEC 2014 to more than 1,100 words in NEC 2017. We focus on a few of the most notable revisions related to initiation device type and location, and control limits outside and inside the array boundary.
Initiation device. The new subsection 690.12(C) provides specific guidance regarding allowable types of rapid-shutdown– initiation devices, including the service disconnecting means, PV system disconnecting means and readily accessible switches that clearly indicate “on” and “off” positions. This subsection further states that initiation devices at one- and two-family dwellings must be readily accessible and located outside the buildings. A six-handle initiation device rule also applies where there are multiple PV systems on a single service.
Outside array boundary. The NEC 2017 requirements for controlling PV circuit conductors outside the array are similar to those in NEC 2014, with one notable exception that will be of particular concern to system designers and installers: As shown in Figure 2, the 2017 Code defines the array boundary as extending 1 foot from the array in all directions, rather than the NEC 2014 5-foot boundary for conductors entering a building or 10-foot boundary for conductors on the roof. In the short term, integrators can design and install NEC 2017–compliant PV systems much as they are doing now—using MLPE, remotely operable roof-mounted shutdown devices or roof-mounted string inverters—except that they must now locate the latter two solutions much closer to the PV modules. Note, however, that subsection 690.12(D) requires the use of equipment specifically listed for performing the rapid-shutdown function as opposed to simply rated for the switched current and voltage.
Inside array boundary. New requirements in 690.12(B)(2) for controlling PV circuit conductors within the array illustrate where rapid-shutdown compliance becomes more difficult. This is the subsection that has industry stakeholders using the term module-level rapid shutdown when talking about the new Code requirements. This term is not entirely accurate, however, as 690.12(B)(2) lists three methods of controlling conductors within the array: using listed rapid-shutdown PV arrays [690.12(B)(2)(1)]; limiting conductors to 80 Vdc or less within 30 seconds (module-level shutdown, in other words) [690.12(B)(2)(2)]; or employing PV arrays with no exposed wiring or conductive metal parts [690.12(B)(2)(3)].
The requirements for controlling conductors within the array boundary are contentious for several reasons. Many solar industry stakeholders feel that they will drive up costs and may compromise system reliability. Others question their efficacy with regard to firefighter safety, the primary goal of rapid shutdown. While it is beyond our scope to explore all of the technical issues and stakeholder perspectives related to this topic, “Module-Level Rapid Shutdown for Commercial Applications” covers them in detail (SolarPro, September/October 2016).
One bit of good news for the installer community is that the CMP delayed enforcement of the new requirements inside the array boundary until January 1, 2019. This short-term relief is intended to provide a UL Standards Technical Panel time to develop a product safety standard for listed rapid-shutdown arrays, as well as to allow manufacturers time to develop compliant products and solutions.
Systems with energy storage. More good news for system integrators is that the CMP added several new diagrams to 690.1. In particular, Figure 690.1(b) clarifies that the Code does not consider energy storage systems, multimode inverters, stand-alone inverters or any associated loads to be PV system circuits. Therefore, these circuits are not subject to the rapid-shutdown requirements in 690.12. The Code requirements related to energy storage systems are found in Article 706, which does not mention rapid shutdown.
Callout F: Overcurrent Protection and Disconnects
Apart from rapid-shutdown requirements for PV systems on buildings, the most substantial 2017 Code changes with regard to system design relate to overcurrent protection devices (OCPDs) (690.9, “Overcurrent Protection”) and disconnecting means (690.13, “Photovoltaic System Disconnecting Means”; and 690.15, “Disconnection of Photovoltaic Equipment”). Designers and installers should read these sections carefully.
Overcurrent protection. System designers and installers should pay particular attention to the revised OCPD requirements for PV source and output circuits in 690.9(C). Whereas NEC 2014 and earlier Code editions required OCPD in both poles of PV systems deployed using non-isolated Type-TL inverters, NEC 2017 requires only a single OCPD, as shown in Figure 3. Designers can place this single OCPD on either pole of the array, provided that all the devices in the PV system are in the same polarity.
Much of the content in 690.9(B) regarding OCPD rating is not new, but the 2017 edition reorganizes it. For example, the CMP moved the requirement that OCPDs in dc PV circuits be listed for the application to this subsection. Note that the CMP added a new allowance for adjustable electronic OCPDs in 690.9(B)(3).
Disconnecting means. Previous Code editions sometimes left system designers and installers at odds with jurisdictional authorities regarding what constituted the PV system disconnect, where to locate it and how to label it. The additions and changes to Figure 690.1(b) are welcome clarifications, as the PV system disconnect location is clearly marked for a variety of system configurations. These diagrams, in combination with extensive rewrites to 690.13, should allow designers to confidently implement NEC 2017 requirements for PV system disconnecting means.
It bears emphasizing that all energy storage equipment, battery-based inverters and loads lie outside the boundary of the PV system. This is a very important distinction that SolarPro has covered previously in some detail. See the article by Bill Brooks, “NEC 2017 Updates for PV Systems” (SolarPro, May/June 2016), for an in-depth discussion of this topic.
System designers should pay careful attention to 690.15, as some of the terminology may be new to many in the solar industry. As an example, the CMP introduced the term isolating device, which in this context is a device that is intended for isolating PV equipment and circuits from the source of power and that does not require an interrupt rating. Note that the allowable types of isolating devices are listed in 690.15(C).
While these devices must be able to provide isolation from all conductors that are not solidly grounded, they are not subject to the simultaneous disconnection requirements that apply to PV system disconnecting means [690.13(F)(1)]. Note, however, that isolating devices alone do not suffice for dc combiner output circuits, or inverter or charge controller input circuits operating over 30 A; these circuits require an equipment disconnecting means. Unlike isolating devices, equipment disconnecting means are subject to simultaneous disconnection requirements [690.15(D)]. Both equipment disconnects and PV system disconnects are allowed in place of isolating devices.
Practically speaking, one of the most significant changes in NEC 2017 is that it requires isolating devices or disconnecting means in both poles of a PV circuit, as shown in Figure 3. The Code requires the provision of these devices as needed to isolate PV equipment—including modules, fuses, dc-to-dc converters, inverters and charge controllers—from “all conductors that are not solidly grounded.” Since the vast majority of PV systems are functional grounded rather than solidly grounded, it is necessary to disconnect both poles of PV circuits.
Practical considerations. It is helpful to think about how NEC 2017 requirements apply to common applications, such as dc combiners, inverter-integrated combiners or inverter input circuits. First, disconnection means are required to isolate fuses from ungrounded conductors. A touch-safe fuseholder itself qualifies as an isolation device for circuits with a maximum current up to 30 A. Second, dc combiner output circuits with a maximum current greater than 30 A require an equipment disconnecting means that is capable of opening both poles simultaneously and is either integral to the equipment, located within sight and within 10 feet of the equipment, or remotely operable from within 10 feet of the equipment. The requirement for equipment disconnecting means also applies to inverter input circuits (>30 A).
In rooftop applications, arc-fault requirements effectively limit dc combiner outputs to 40 A or less; rapid-shutdown requirements, meanwhile, mandate remotely operable equipment disconnecting means capable of simultaneously disconnecting all current-carrying conductors. When specifying equipment for ground-mounted systems with a generating capacity of less than 5 MWac, integrators should be aware that the majority of disconnecting combiners currently on the market are designed to disconnect one pole of the array only. In large-scale applications, 691.9 provides PEs with more design latitude for PV equipment isolation; this allowance assumes that only qualified persons service the array and that they are provided with written safety procedures and conditions, as well as operation and shutdown procedures.
It is not clear how manufacturers will go about meeting the demands of a fragmented market, given that Code cycle adoption varies across the US. Brian Lydic, senior standards and technology engineer at Fronius USA, elaborates: “Our non-isolated units already required simultaneous disconnects for all poles, so that’s no issue for us. The single-pole OCPD question is more interesting. Right now, installers have the ability to install ‘slugs’ or blanks in fuseholders, which means they can fuse poles or not depending on the AHJ’s adopted Code cycle. To reduce costs, of course, we’d like to eliminate half of the fuseholders as soon as possible. We want to work with industry stakeholders to push the acceptance of the new wiring methods so that all customers, even those in pre-2017 jurisdictions, can enjoy the lowest costs.”
Michael Neiman, an applications engineer at Yaskawa–Solectria Solar, echoes these sentiments: “We designed the dc and ac interfaces of our products with flexibility in mind. Thanks to this flexibility, we are configuring interfaces across our inverter and combiner product families to take full advantage of—as well as fully comply with—the new Code requirements. For example, we can simplify our string combiners by fusing just one dc polarity and not both. This lowers the product cost to our customers.”
Callout G: Equipment and System Grounding
In Part V of Article 690, there is a lot of shaded gray text, which the NFPA uses to indicate where the Code has changed. In many of these places, including in 690.43, “Equipment Grounding and Bonding,” the CMP reorganized and clarified existing requirements without making substantial changes. It left other sections, such as 690.45, “Sizing of Equipment Grounding Conductors,” more or less unchanged.
Perhaps the biggest changes are in 690.47, “Grounding Electrode System.” At first glance, the brevity of this section compared to earlier editions is striking. However, this results largely from the fact that the new functional grounded PV system definition eliminates the need to differentiate between various system grounding configurations. On the whole, the revised rules will simplify system design and installation, as well as reduce material costs.
As an example, the 2017 Code cycle removes all requirements related to dc-specific grounding electrode conductors (GECs) for systems that are not solidly grounded. This means that PV system grounding conductors do not have to be continuous and are not sized per 250.166, but rather in accordance with 250.122. Only solidly grounded PV systems, which are increasingly rare, are required to have a dc GEC connected to the grounding electrode system and sized in accordance with 250.166. As described in 690.41(A), the most common PV system grounding configurations are not solidly grounded. This means that the equipment grounding conductor, on the output of the PV system and connected to the associated distribution equipment, provides the connection to ground for ground-fault–protection purposes and bonding. Part VII of Article 250 defines the allowable methods of equipment grounding.
Metal in-ground support structures. One important point of clarification appears in 690.47(A), which requires that both buildings and structures supporting PV arrays have a grounding electrode system. Since Article 100 defines structure as anything that is “built or constructed, excluding equipment,” this extends to PV racks and mounting structures. With this in mind, integrators working on ground-mounted PV systems should take note of a new type of grounding electrode permitted.
A new subsection, 250.52(A)(2), is dedicated to metal in-ground support structures that comprise a metal extension of a building or structure and qualify as grounding electrodes. Many of the foundations used for ground-mounted PV systems—including pilings, ground screws and other metal foundations—can qualify as grounding electrodes provided that the metal is in direct vertical contact with the earth for at least 10 feet. More important, at buildings or structures with multiple metal in-ground supports—as is typically the case with PV ground mounts—installers need to bond only one of these in-ground supports to the grounding electrode system. This last detail is important. Normally, 250.50 requires that all the grounding electrodes at a building or structure be bonded to form a single grounding electrode system. The allowance in 250.52(A)(2) means that installers working on a structure with multiple pilings can use a single bonding jumper to connect one piling to the grounding electrode system.
Additional auxiliary electrodes. NEC 2017 has renumbered the sometimes controversial requirement for additional auxiliary electrodes as 690.47(B) and, significantly, has made it more permissive. The revised version allows— but does not require—installation of electrodes at the location of ground- and roof-mounted arrays, and changes the GEC-sizing requirement. Revised language in 250.66 (which concerns ac grounding electrode sizing) clarifies that the GEC does not need to be sized any larger than the particular maximum for a given type of electrode, provided that the GEC “does not extend on to other types of electrodes that require a larger-size conductor.”
Note that the Code does not require bonding additional auxiliary electrodes to an existing grounding electrode system by means of a bonding jumper. In many cases, however, installing a bonding jumper will provide a superior path for lightning-induced surges as compared to bonding by equipment grounding conductors only.
According to SolarCity’s Fisher, the revised 690.47(B) will reduce system costs and eliminate confusion. He notes: “This section has always been confusing to understand and to comply with. The language that presented real challenges was the directive to locate the auxiliary grounding electrode ‘as close as practicable to the location of roof-mounted PV arrays.’ Frequently this language requires a site-specific discussion with the field inspector prior to installation, especially for complex arrays and buildings. It also presents real challenges to people concerned about the impact of this new grounding electrode system with regard to lightning effects. NEC 2017 clarifies that a grounding electrode system must be in place for a building, but that an existing system that is Code-compliant is satisfactory. The PV system equipment grounding conductors must simply be bonded to this grounding electrode system using traditional methods found in Section 250. This revision helps reduce costs by removing ambiguity around NEC requirements.”
Callout H: Labeling and Marking
While the majority of labeling requirements for PV systems remain unchanged, installers will appreciate the fact that NEC 2017 removed a few, including the 2014 requirements for ground-fault warning labels for both grounded systems [690.5(C)] and ungrounded systems [690.35(F)].
In addition, the CMP simplified the dc PV power-source labeling requirements. To meet 690.53, most PV systems will need a label with only two lines: maximum voltage [per 690.7] and maximum circuit current [per 690.8(A)]. Where charge controllers or dc-to-dc converters are installed, the label must also call out these maximum current values. Installers should place the 690.53 label on dc PV equipment disconnects or dc PV system disconnects in multimode or stand-alone inverter systems. The PV system disconnecting means for interactive systems does not require this label, since this disconnect is on the ac side of the system [see Figure 690.1(b)].
Unfortunately, installers will spend any pennies saved on ground-fault and dc PV power-source labels on new rapid-shutdown labeling: 690.56(C)(1) requires a label identifying the type of rapid shutdown (inside and outside the array boundary or outside only); 690.56(C)(2) requires a roof map for buildings with more than one type of rapid shutdown, as shown in Figure 4; and 690.56(C)(3) requires a label identifying the initiation device. (See “NEC 2017 Updates for PV Systems,” SolarPro, May/June 2016, for more information.)
Callout I: Point of Interconnection
The CMP greatly revised the point of interconnection requirements as part of the 2014 revision cycle. The most significant changes are largely intact in NEC 2017, though some of the numbering is revised and the term “power source” replaces “inverter” in many cases. For an in-depth discussion of options for making a Code-compliant interconnection under NEC 2014 or NEC 2017, see Jason Fisher’s recent article “Interactive Inverter Interconnection” (SolarPro, January/February 2017).
One notable change in 705.12 bears mentioning, since it will benefit some residential installers: The CMP added a version of the longstanding “120% rule” that applies specifically to center-fed panelboards. A new subsection, 705.12(B)(2)(3)(d), clarifies that installers can make a load-side connection on either end—but not both ends—of a center-fed panelboard, as shown in Figure 5, provided that the sum of 125% of the power-source output current plus the rating of the OCPD protecting the busbar is less than or equal to 120% of the busbar rating.
Practice Makes Perfect
As is the case with each Code cycle, NEC 2017 revisions both reflect the past and look to the future. The CMP seeks to improve on the past by addressing common design and installation mistakes that compromise the safety of fielded PV systems. At the same time, it may also use new Code requirements—such as module-level rapid shutdown—to push manufacturers and industry stakeholders to develop products or features that improve safety. To that end, manufacturers have become increasingly involved in the Code-making process over the last few cycles, in part so that they can implement design changes focused on making installations easier and more affordable while still meeting evolving Code requirements. We recommend that system designers and installers also get involved—and quickly. The deadline for public input for NEC 2020 is September 7, 2017.
Rebekah Hren / Solar Energy International / Winston Salem, NC / solarenergy.org
Brian Mehalic / Solar Energy International / Winston Salem, NC / solarenergy.org