I finally caught up this morning with David Roberts’ excellent post on Vox about big solar, and noticed that in his discussion of capacity factor he mentions inverter load, saying “inverter load is important, though I won’t bore you by explaining it.”
But I will!
A good place to explore inverter load is the Solar Star Projects, a sprawl of ground-mounted solar panels straddling the LA-Kern County line in the Antelope Valley, on the edge of the Mojave, and which Dave mentions.
Technically speaking, it’s called the “Solar Star Projects” because there’s Solar Star 1 and Solar Star 2. But it’s correctly treated as one plant because 1 and 2 are conjoined, had the same builder, use the same SunPower systems, have the same power buyer (Southern California Edison) and charge the same price for their energy.
Dave labeled it the world’s largest solar plant at 579 megawatts. There is a plant in India that is said to come in around 600 MW, but I’ve never been able to get firm data on it and I’m not sure how much is actually operational, so I’m comfortable giving Solar Star the crown.
Turns out, too, that Solar Star is a little bigger than even the company that owns it says. According to the Western Renewable Energy Generation Information System database and filings by the builder, the plant is actually 586 MW. This is confirmed in a recent Fitch’s Ratings release on the plant, which noted: “The completed project’s capacity totals 586 MW of capacity, providing an additional 7 MW of capacity compared to design specifications.”
But enough of that – you came here to read about inverter load.
So as you probably know, inverters are the electronics that convert direct current (DC) output into alternating current (AC) before it goes onto the grid. This results in some loss in power, but systems are built with more DC (photovoltaics) power capacity than AC (inverter) power capacity. The ratio of PV to inverter is called the inverter load ratio, or ILR.
In its most recent report on utility solar trends [PDF], the Lawrence Berkeley Laboratory last fall noted that ILRs were climbing. That is, developers were installing more PV capacity per inverter capacity than they used to. Why? Well, one big reason is that, as Dave noted, PV has fallen in price so dramatically. A few more panels come cheap. Why not?
This doesn’t help the plant produce more peak power – the plant can’t produce more than its inverter capacity – but it does help it produce full power for more of the day. Instead of a production curve that peaks at somewhere between 11 a.m. and 1 p.m., you can get steady peak or near-peak production for several hours. This boosts capacity factor and can pay off for the electricity seller, as LBNL explains:
… with some utilities (particularly in California) offering time-varying PPA prices that favor generation during certain daylight hours, including late afternoon, many developers have found it economically advantageous to oversize the DC array relative to the AC capacity rating of the inverters. As this happens, the inverters operate closer to (or at) full capacity for a greater percentage of the day, which – like tracking – boosts the capacity factor, at least in AC terms…. (T)he resulting boost in generation (and revenue) during the shoulder periods of each day outweighs the occasional loss of revenue from peak-period clipping (which may be largely limited to just the high-insolation summer months).
LBNL says that back in 2010, ILRs were around 1.2, on average, and were often much lower than that. Now they’re just shy of 1.3 on average, and never under 1.2. Here’s a chart from the lab:
And, indeed, we can see this at Solar Star, where the PV panels add up to 747.29 MW of installed capacity. Divide this by the 586 MW of AC capacity, and you get a ratio of 1.28.
With this arrangement, Solar Star was able to operate at a remarkably high capacity factor in 2015: 35.2 percent.
The plant generated 1,663,593 megawatt-hours of electricity, as reported by the Energy Information Administration with – this is an important point here – a plant capacity of 540 MW. Why 540 MW and not 586 MW (or even 579)? Because the entire plant wasn’t online for the whole year – construction began in 2013 and big blocks gradually came online until the whole thing was done in late June 2015. Taking into account exactly how much capacity was online ever day of the year in 2015, the average daily capacity was 540 MW.
You might be curious how much Southern California Edison paid for this energy. Well, the PPAs aren’t public, but FERC records show the total for the year to be $157,180,118, or $94.48/MWh or, to put it in the units you see on your electricity bill, about nine and a half cents per kilowatt-hour.
This, however, masks the extreme variability in pricing. As LBNL noted, when the electricity flows to the utility can make a big difference in how much it pays. At Solar Star, Southern California Edison paid as little as $49.99/MWh during offpeak hours in the first quarter of the year. But in the third quarter – July, August and September, when California energy use often peaks – it paid $251.40 for “onpeak” electricity.
I don’t know exactly how these periods are defined in the Solar Star contracts (there’s one for each “unit” of the plant), but if you read the footnotes to my Crescent Dunes post a few weeks ago (and who didn’t), you know that one California solar PPA I did see defined the peakiest peak as weekdays from 1 p.m. to 8 p.m. during July, August and September.
So you can see why solar power developers will take readily add more cheap PV – leading to a higher ILR – in order to boost generation as the afternoon wears on.
One last thought. The overall average price of nearly 10 cents/kWh paid in 2015 emphasizes again how quickly solar prices have fallen. The Solar Star contracts are about five years old. That means that the price of solar has fallen by half or more in five years, with no change in the regulatory structure. Pretty impressive.