Practical Application of NEC 2017: Page 2 of 5

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.

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