I've got a client with a manufacturing facility in Marietta getting hammered by Georgia Power for power factor penalties. Their internal PF meters consistently show 0.92-0.94, but GP is billing them at 0.75-0.78 on Schedule PL-1. The penalties are running $3,200/month. Has anyone seen this kind of discrepancy before? I'm wondering if it's a metering synchronization issue or if GP is measuring at a different point than the customer meters. The facility has about 2.5MW demand with mostly motor loads and some VFDs.
Georgia Power claiming 0.75 PF when my meters show 0.92?
Rachel, I've seen this exact issue with Dominion here in Virginia. The utility was measuring PF at 15-minute intervals while the customer was reading instantaneous values. Motor starting transients can drag down the interval average even when steady-state PF looks good. Request the detailed interval data from Georgia Power - you'll probably see periodic dips that your client's meters aren't catching. Also check if they have any large motors that cycle on/off during the billing period.
Phil's right about the interval averaging. Duke Energy does the same thing here in Charlotte. One thing to check - are your client's PF meters true RMS or just fundamental? With VFDs in the mix, you could have significant harmonic distortion that affects the utility's power factor calculation but doesn't show up on basic meters. Harmonics can make the utility's displacement power factor calculation look worse than what simple meters report.
We had a similar case with APS here in Phoenix. Turned out the customer had installed capacitor banks but they were switching based on kVar readings, not actual power factor at the meter. The utility measures PF at the service entrance while the caps were correcting downstream. Customer thought they were at 0.95 PF but utility was seeing 0.82 because of the measurement point difference. Saved them $45K annually once we got it sorted out.
Great points everyone. Derek, the harmonics angle is interesting - this facility does have about 15 VFDs ranging from 10-150HP. Sarah, the capacitor bank location could definitely be an issue. They have a 600kVar bank that switches based on plant kVar demand, not utility meter readings. I'm going to request the 15-minute interval data from Georgia Power and also check the harmonic content at the service entrance. Will report back what we find.
Rachel, also verify the CT and PT ratios on both the utility and customer meters. I had a case with Puget Sound Energy where a customer's PF meter had incorrect CT ratios programmed, making their readings artificially high. The 2000:5 CTs were programmed as 1200:5 in the meter setup. Simple but costly mistake that went unnoticed for months.
David brings up a good point about CT ratios. Also check if the customer meters are measuring line-to-line or line-to-neutral voltages correctly. Wrong voltage configuration can throw off the power factor calculation significantly. I've seen meters configured for 480V delta when the service was actually 480V wye, causing a 1.732 error factor in the PF calculation.
Update: Got the interval data from Georgia Power and found the smoking gun. The facility has two large air compressors (200HP each) that cycle every 45 minutes during peak production. When they start, the power factor drops to 0.65 for about 2-3 minutes, which is exactly during GP's demand interval measurement. Customer meters were showing steady-state PF after the motors were up to speed. Installing soft-starters reduced the penalty by 80%. Thanks for all the input!