Since March 2024, my solar system has been experiencing recurring ground fault shutdowns — an inverter safety response to detected electrical leakage in the DC wiring. Ground faults are not minor glitches. They are the inverter's last line of defense against a potentially lethal electrical condition on the roof.
A ground fault occurs when current leaks from the DC wiring to the grounded metal frame of the solar array. In a properly functioning system, current flows only through the intended circuit: from panels, down the DC conductors, through the inverter, and back. A ground fault means current has found an unintended path to earth — through damaged wire insulation, moisture-compromised connections, or cracked components touching the metal racking.
The Aurora inverter's Ground Fault Detection Interrupter (GFDI) monitors for this condition continuously. When it detects leakage current exceeding the threshold (typically 0.5–1.0A for fuse-based GFDI systems), it de-energizes the inverter and logs an E018 fault code. This is a safety shutdown — the inverter is designed to stop operating because the alternative is far worse.
Why the inverter shuts down: Uncontrolled DC ground current can produce sustained electrical arcing — a high-temperature plasma discharge between conductors. Unlike household AC power, which cycles through zero 120 times per second (providing natural arc-extinguishing opportunities), DC current flows continuously. A DC arc, once struck, will sustain itself indefinitely as long as the sun is shining and the panels are producing voltage. DC arc temperatures routinely exceed 3,000°C (5,400°F) — hot enough to ignite roofing materials, wood framing, and wire insulation in seconds.
The 2011 rapid-shutdown gap: Modern solar installations (post-2014 NEC 690.12) are required to have module-level rapid shutdown — the ability to de-energize each panel individually within seconds of a fault. My 2011 system predates this requirement. It has no module-level power electronics (no microinverters, no DC optimizers). When the Aurora inverter detects a ground fault and trips offline, the panels themselves remain fully energized. High-voltage DC (up to ~300V in this two-string configuration) continues to flow from the roof to the inverter through the faulted conductors whenever the sun is shining. The inverter has stopped converting power, but the dangerous DC voltage is still present on the wires.
The GFDI fuse is the only protection: In this era of system design, the sole ground fault protection is a single fuse in the inverter's grounding conductor. If the fault current is high enough, this fuse blows and isolates the fault. But if the leakage is below the fuse rating — a "low-level" ground fault — the fuse holds, the inverter trips, and the fault persists energized on the roof. My system has experienced 237 of these trip events without the GFDI fuse blowing, which means the fault current is below the interrupting threshold but well above the detection threshold. This is the most dangerous operating regime: a confirmed ground fault that the system cannot fully isolate.
One loose wire from catastrophe: The inverter can only detect the ground fault because the equipment grounding conductor (EGC) from the array frame to the inverter is intact. If that single grounding wire were to corrode, loosen, or break — which is entirely plausible after 15 years on a roof with documented installation quality issues — the inverter would lose its ability to sense the fault entirely. The system would continue operating normally, completely blind to the ground leakage, while the fault condition persists and potentially worsens. Given the quality of workmanship documented in Part II, the integrity of a single bonding wire installed in 2011 cannot be assumed.
The data reveals a clear pattern: ground faults occur during the highest-production hours of the day, typically between 11:00 AM and 2:00 PM. This is not a coincidence — it is a direct consequence of the physics involved.
Thermal expansion: As panels heat up during peak sun (surface temperatures can exceed 65°C / 150°F on hot days), wiring insulation softens, connectors expand, and any marginal connection becomes more likely to develop electrical contact with the grounded racking. The highest panel temperatures coincide with the highest DC voltage and current — the exact conditions that maximize ground fault risk.
Moisture cycling: Morning dew evaporates during late morning, but in the shaded areas beneath panels where air circulation is restricted, condensation can persist. Combined with 15 years of accumulated debris, dust, and degraded sealant residue from the un-flashed roof penetrations, the space beneath the array creates conditions favorable to ground leakage — particularly as the day warms and thermal stress cycles the connections.
Voltage-dependent leakage: Ground fault current is proportional to system voltage. PV voltage peaks at maximum irradiance (solar noon). A marginal insulation defect that stays below the GFDI threshold in the morning may cross it at midday when voltage peaks. This explains why the system produces normally for hours before abruptly shutting down — the fault threshold is only exceeded when production reaches its daily maximum.
Ground faults were identified programmatically from Sunrun's own 15-minute interval production data, retrieved via their REST API. The detection algorithm identifies days where production was normal in the morning hours, then dropped abruptly to zero before sunset — a signature that matches inverter-initiated safety shutdowns and cannot be explained by weather or shading.
The methodology was validated against a 63-month control period (January 2019 – February 2024) with zero reported faults. During this period, the algorithm produced zero false positives, confirming that every detected event represents a real electrical fault condition.
The trend is accelerating. From 47 events in 2024 (partial year) to 147 in 2025 to 43 in Q1 2026 alone. At the current rate, 2026 is on pace for over 170 fault events — more than every other day. The underlying fault condition is worsening, not stabilizing.
The financial harm from 237 ground faults is compounded by a structural feature of Sunrun's billing model. Under "balanced billing," I pay a fixed monthly amount for estimated production regardless of what the system actually generates. On every fault day, I paid Sunrun for electricity that was never produced — and then bought that same electricity from Southern California Edison at retail rates.
The chart below shows the running total of double-cost damages over the full fault period. Note the steepening curve in late 2025 and early 2026 as faults become more frequent.
All 237 ground fault events, sorted chronologically. Each row shows the date, cutoff time, actual and expected production, kWh lost, and the double-cost financial impact.
| # | Date | Shutoff | Actual kWh | Expected kWh | Lost kWh | % Lost | Sunrun Cost | SCE Cost | Double Cost | Cumulative |
|---|---|---|---|---|---|---|---|---|---|---|
| TOTALS (237 events) | 2,133.62 | 40.5% | $806.30 | $943.14 | $1,749.44 | $1,749.44 | ||||