By Joe Jancauskas, Senior Electrical Engineer at Castillo Engineering

While moderately oversizing your solar panel cables can ensure fire safety and help you meet your voltage drop criteria, vastly oversizing your cables and strictly adhering to a voltage drop mandate could unnecessarily reduce the long-term profitability of your solar projects.

In this second part of our PV cable sizing series, we take a look at why exactly PV cables are so oversized and how you can better calculate cable sizes to ensure safety while also maximizing project returns.

Why are PV cables so oversized?

To understand why cables are so oversized, you should be aware that the direct current (DC) input wiring to the inverter is generally split into two terms by National Electrical Code (NEC): the PV string wiring is referred to as the “photovoltaic source circuits,” while the output wiring from the combiner boxes is referred to as the “photovoltaic output circuit.” If a re-combiner is used, its output wiring is referred to as the “inverter input circuit.”

First, part of the reason why PV cables are so oversized is because the NEC assumes that PV is a continuous load. This is often a conservative assumption since a variable power source like the sun is not often at full output for more than three hours, per the NEC definition of continuous load. Many solar projects use far more copper than is needed to maintain safety, resulting in unnecessary costs and lower project returns.

Second, in addition to the normal 125% sizing factor for continuous loads, an additional 125% sizing factor is added to account for PV output occasionally being greater than nameplate for those rare irradiance and temperature combinations that are better than Standard Test Conditions, for a resulting 156% sizing factor applied to the full load current of the photovoltaic output circuits.

Another reason why PV cables are significantly oversized is because solar module ratings are based on 1,000 W/m2 of solar irradiance, which is only ever exceeded on rare occasions in terrestrial environments. As a result, many often think that this infrequent incident must be planned for as worst-case design engineering, but is this truly always necessary? A lot of design concerns come from a fixation on “nameplate” equipment ratings, even if those ratings aren’t relevant in real-world scenarios.

In order to calculate a nameplate rating for a piece of electrical equipment, you must establish a specific set of conditions, such as 100% load for 40 years at 30 °C (86 °F) ambient temperature. This combination of conditions, however, almost never happens, which is why a lot of utility transformers and cable systems are still in service long after their initial 40 years of design service life.

Real-time nameplate ratings are not fixed values but fluctuate with changes in ambient and loading conditions. For transformers and cables, the biggest concern regarding aging and end of life is the degradation of their organically based insulation materials. Let’s look at some of the rating conditions for the major PV project elements of transformers, cables, transmission lines and PV Modules.

Transformer ratings

PV transformers without battery energy storage (BESS) cannot be always loaded, but short-time minor overloads should not be an issue. Even IEEE Standard C57.91-20 recognizes that short-term overloads of up to 200% of nameplate rating can be possible under certain conditions without significant loss of life. Emergency four-hour overload ratings of 200% over nameplate ratings have been adopted by some major utilities since the capital cost of providing double the equipment rating, which would rarely be used, is cost prohibitive.

Many PV designs do not take advantage of using a set of cooling fans in order to purchase a lower-rated transformer and save capital costs. For example, when Florida Power & Light is designing an 85 MVA system (75 MW of PV and 10 MVAr of capacitors), it purchases a 51-MVA transformer. The first stage of added fans takes the rating to 68 MVA and the second set of fans takes the rating to 85 MVA.

The fans are less expensive than buying another 34 MVA worth of transformer, and each stage of fans gives you a boost of ~33%. The transformer should be located within a fence to avoid public exposure to the moving fan blades, which typically do not have “finger-safe” guards.

When sizing cables for a continuous load, the NEC requires a 125% factor to be applied to the rating, with one exception. Per NEC, if the feeder is only supplying transformers, then the cables must be sized for “the sum of the nameplate ratings,” with the assumption that the transformer size already incorporates the 125% factor from all the loads that they were sized to serve.

Cable ratings

Many PV systems have actual load factor” of around 40%. One way to decrease a cable size is to use a specific table provided by IEEE, which provides voluminous tables for both 100% and 75% load factors; with the 75% load factor option generally giving a cable size reduction from the 100% tables which closely match the tables in the NEC.

Using a messenger wire system, like one from CAB System, lets you use a higher cable ampacity, but this higher value can get negated if the cables have to transition underground for any significant distance.

Large utility transmission lines have been adopting “dynamic ratings” based on actual ambient and loading conditions measured by sensors placed around the line conductors themselves. Utilities are applying technology to save money and increase ratings. Why shouldn’t PV owners do the same?

PV module ratings

The rating of the PV panels is based on 25° C (77° F) operating temperature at 1000 W/m2 irradiance. It is important to note that as the temperature increases, PV modules produce less power. The highest PV output is often on cool, windy days in late spring when the temperature conditions will be far less than the high temperatures built into the nameplate assumptions of the other electrical equipment, such as transformers and cables.

The PV module international rating standard provides good consistency for comparing module ratings, with only one drawback: Depending on geographic location, the conditions that define STC almost never occur in the real world. One reason why STC occurs so rarely is that the temperature parameter is 25° C cell operating temperature. This is the operating temperature of each solar cell behind the glass front of the module, not the ambient temperature.

For an individual cell to be operating at 77° F, it means that the ambient temperature would likely have to be closer to 32° F. This does depend on variables such as how close to the roof the module is mounted and how much cooling airflow the module is receiving.

Several years ago, we worked with a community college in Ohio and obtained one-minute irradiance data for an entire year. The “Standard Test Conditions” on which the modules are rated were only present for about 12 minutes out of the entire year, so in this instance, it goes against that blanket “STC rating” assumption.

A few data points almost hit the tremendously high value of 1,400 W/m2, likely from “cloud lensing,” where clouds refract brighter-than-usual sunlight, but it was only for one minute. More importantly, we couldn’t find any interval above 1,000 W/m2 that was present for more than six minutes, which was less than an NEC three-hour period for continuous loads. Also, a fair percentage of high irradiance minutes are at temperatures above 85° F, meaning that the power reduction from high temperature means that you should next expect maximum output for those minutes.

For every PV module, there are three temperature adjustment factors given on their data sheets: Power in relation to temperature, the voltage in relation to temperature and short circuit current in relation to temperature. The first two are negative factors, and the short circuit current increases with temperature.

So, let’s take an independent look at where that extra 125% factor might have come from. For starters, as the temperature goes higher, the short circuit current goes up. Assuming a conservative factor of 0.6%/°C, moving from the rated conditions of 25°C (77°F) to 50°C (122°F) yields an insignificant increase of 1.5%. The rest of the 23.5% would mostly come from irradiance, but that’s still a conservative estimate.

This doesn’t correlate to real-world weather conditions has resulted in many solar module suppliers publishing the alternative Nominal Operating Conditions (NOC) ratings in addition to STC ratings. NOC conditions are defined as an irradiance of 800 W/m2, 20°Celsius ambient conditions (68°F), and an air mass of 1.5. This gives a lower, more realistic indication of expected power output.

A review of the community college irradiance data, however, shows that NOC occurred for a total of 1,306 minutes or just 0.5% of the total daylight time during the year. This is an improvement over the 12 minutes at STC, but it’s still not a meaningful percentage of actual operating time.

Voltage drops

Voltage drop design criteria varies from project to project, with a common criterion of 2%. We have seen criteria as low as 0.5% for DC, which drives the design to no. 8 copper string wires and large copper combiner box output conductors.

For string inverters that have multiple string inputs, the standard voltage drops criteria and resulting loss calculations are realistic. When combiner boxes provide a single input to either a string inverter that has a single MPPT or to a central inverter with a recombiner, it is not so realistic.
Each combiner box is a single electrical node and can only have one voltage — those varying string voltages must average out to a single voltage because electrically they don’t have a choice. For those PV Owners who have rigid voltage drop criteria, a worst-case string voltage drop can drive an increased design cable size when to a voltage criterion that doesn’t exist.

In many cases, NEC requirements take extra precautions to prevent fires. Those extra precautions cost extra to implement, but there was a change in the 2017 NEC that allows engineering analysis to determine the maximum three-hour current for arrays over 100 kW. We have applied this to several of our clients, and it has saved them at least one cable size for portions of the array.

This method to reducing the 1.56 factor isn’t used frequently, because an AHJ hasn’t adopted the 2017 NEC code,Then there is the “need-it-now” factor for many projects, which precludes the extra time for engineering analysis, and doing a traditional NEC design can be completed within the rushed timeline.

When copper prices were low, it did not matter very much monetarily to the project, but it’s a different story today. A system over 100 kW needs to avoid the 1.56 factor whenever possible.

Depending a PV array’s DC/AC ratio and geographic location, the peak inverter output may not be present for three continuous hours, or with a high DC/AC ratio on single-axis trackers with bifacial modules and string optimizers, it could be present for 10 hours or more.

The bottom line is that you need to understand the anticipated year-long variations in the behavior of your PV system and take advantage of allowed engineering cost reductions wherever you can; and don’t double-up on worst-case factors that are not going to occur concurrently. If you have any questions about PV cable sizing, voltage drop, or otherwise, get in touch with one of our engineering experts today. Also, stay tuned for part three of our PV cable sizing series, where we will include more insights on reducing cable costs.