SMA Shipped GW of Inverters in 2023—Here’s What That Does and Doesn’t Tell You About a Solar System

First, the headline: SMA shipped inverters at gigawatt scale in 2023. Based on the company’s preliminary reporting, 2023 inverter shipments landed at about 19 GW — 19.2, maybe? I’d have to open the release to quote the exact decimal. In an industry where many respected inverter brands never pass a single GW in a year, that is a different manufacturing class, and it deserves acknowledgment.

The gigawatt shipment figure tells you the company survived the market’s field-feedback loop at scale. It is not an engineering specification. The quality of an actual solar system is built elsewhere: in the scope definition, in the module-to-inverter matching, and in the transfer-switch decision that somehow never makes it onto the first revision of the drawing.

Quick introduction so you know where this is coming from: I am a quality and compliance manager at a mid-sized renewables distributor. Every proposal, bill of material, one-line diagram, and datasheet that leaves for an installer crosses my desk — roughly 200 unique designs a year, plus resubmissions. In 2024, I rejected about 11% of first submissions. Not because the inverters were from unknown brands. Most often because the design around the inverter did not match the contract, the site, or the electrical configuration.

Why the gigawatt shipment record deserves respect

To ship gigawatts of power electronics year after year, a manufacturer has to keep warranty claims manageable. That requires component traceability, automated testing, firmware change discipline, and a field-return loop that actually closes. At that volume, problems do not stay hidden for long. SMA has been through that pressure for years.

In my own four years of dock checks and inbound inspections, SMA’s quality was consistently the baseline other suppliers were measured against — and some were visibly below it. I won’t publish supplier scorecards, but that difference has shaped which brands we stock and which ones we quietly stop returning phone calls about.

Still, brand trust only gets you to the starting line. A warranty replaces a failed inverter. It does not cover the week of schedule lost because the string voltage was calculated at 25°C instead of the site’s actual winter minimum.

First: decide what “solar system” means in your contract

What is the definition of a solar system? Textbook version: photovoltaic modules, mounting structure, inverter(s), and the associated electrical equipment needed to safely deliver power. Contract version: whatever the scope section says it is. Those two versions disagree more often than you would think.

In my reviews, “solar system” is a scope word, not a hardware word. It needs to name the components and, just as importantly, name the boundary. Does the system end at the inverter’s AC terminals? At the main panel? Does it include load-side distribution, a backup subpanel, or the generator transfer switch that the homeowner already told the salesperson about?

Recently I read a proposal for a “complete residential solar system.” It included modules, an SMA inverter, racking, and rapid shutdown. It did not include the smaller subpanel or the interlocked transfer switch needed for the generator the client already owned. The EPC said transfer switches were “not usually part of a solar system.” That is true only if everyone defined the system that way at the beginning. We caught it before signing, but it cost a site visit, a revised price, and two weeks of schedule. The equipment was fine. The contract language was not.

Bifacial panels and SMA inverters: the numbers I check before anything else

Most summaries of “bifacial solar panels advantages disadvantages” start with the rear-side gain. The real advantage is straightforward: with an elevated rack, a reflective surface like snow or white gravel, and enough row spacing, bifacial modules can produce meaningfully more energy from the same footprint. In the right climate, that is a legitimate design win.

The real disadvantage is less obvious: rear-side gain is an estimate, not a label value. Module nameplates are based on front-side irradiance. The extra current from the rear side depends on mounting height, ground cover, row spacing, and soiling — none of which are known with precision when the financial model is written. That uncertainty is exactly where module-inverter mismatches creep in.

This is also where I made my own rookie mistake, so let me save you the same embarrassing email. In my first year of reviewing designs, I approved a string layout with bifacial modules by checking the nameplate Voc against the inverter’s maximum input voltage. I did not apply the temperature correction for a cold, clear morning. At minus 15 degrees, with the module operating well below 25°C, the open-circuit voltage climbed well past what the datasheet allowed. A senior engineer caught it during the required second review, but the installation crew had already pre-assembled the strings. The rework cost us the better part of a day and a very quiet drive back to the office. That is when I added a rule to our checklist: calculate every string at the lowest recorded site temperature, not at standard test conditions.

With SMA string inverters, there are three numbers I verify before I approve any bifacial design:

1. Open-circuit voltage at cold temperature. The SMA datasheet gives a maximum DC input voltage, and it is an absolute limit. If the bifacial gain assumption is wrong, the current can be higher than expected — but voltage is the one that damages input stages.
2. Maximum DC current per MPPT. Bifacial modules can push more current than their nameplate suggests when the rear side is lit. Check the module’s temperature-corrected Isc against the inverter’s per-MPPT current limit before assuming extra rear-side energy is harvestable.
3. Effective DC/AC ratio. Bifacial gain on a reflective site can push the array above the inverter’s recommended DC-to-AC ratio. Some clipping is normal. What is not acceptable is designing the financial model around simulated rear-side gain that the inverter physically cannot process at noon.

None of those checks are about whether SMA makes a good inverter. They are about whether the system around the inverter is technically coherent.

The “solar inverter transfer switch” question

Let me be direct: in a grid-tied PV-only system with no battery and no generator, there is usually nothing to transfer, so a “solar inverter transfer switch” is not a required component. The inverter is certified to detect grid loss and stop exporting — that is anti-islanding, not a transfer. The AC disconnect, where required, is also not a transfer switch. If the design has no backup function, the answer is no, and skipping it is a no-brainer.

The answer changes when storage appears. A battery inverter that intentionally powers loads during an outage needs a way to separate those loads from the grid. That function can be integrated into the inverter or its backup accessory, but it has to be designed, not improvised. Adding a generator makes the question more serious: a generator, a grid-forming battery inverter, and the utility can become two or three energy sources trying to share one load center. That is where a generic manual transfer switch from the electrical distributor is often underspecified.

If the phrase “generator” appears anywhere in the scope, my review does not proceed until the design explains how generator start, load transfer, and neutral-ground bonding are coordinated with the storage inverter. In an off-grid or hybrid system with SMA Sunny Island equipment, for example, generator control is part of the system architecture — the inverter can manage generator starts and system switching according to the manufacturer’s installation documentation. That is different from installing a separate transfer switch and hoping it plays nicely with a grid-forming inverter. This is also why I keep repeating the same sentence in review comments: read the inverter manufacturer’s installation manual and technical information before you quote a transfer switch, not after the inspector asks for it.

I have rejected designs for missing transfer-switch documentation, and I have rejected designs for including the wrong one. The problem was never the brand of the inverter. It was treating a code-sensitive switching decision as a commodity line item.

Where I’d ignore my own advice

If the project uses microinverters or module-level power electronics, most of my DC string advice above does not apply the same way. If you are designing a utility-scale plant around SMA’s central inverter platforms, the review is a completely different discipline — medium-voltage transformers, station protection, and grid interconnection requirements are beyond what a distributor quality reviewer does.

I would also ignore any article, including this one, that tells you a transfer switch is “always required” or “never required.” The correct answer lives in the datasheets, the single-line diagram, the local authority’s amendments, and the manufacturer’s installation documentation. Everything else is just a conversation starter.

Take the larger point with you: SMA’s 2023 gigawatt shipment figure is a legitimate reason to trust the manufacturer. It is not a reason to trust the system design. The design earns trust through checked calculations, clear scope definitions, and honest answers about what happens when the grid goes down.

I have never once regretted rejecting a design for an unverified number. I have regretted trusting a big brand name instead of reading the datasheet. These days, I read the datasheet like it owes me money.