I'm working with a manufacturing client here in San Jose who's on PG&E's E-20 secondary voltage schedule. They're considering installing their own 1.5MVA transformer to qualify for E-19 primary service. The rate difference looks attractive - about $0.015/kWh lower on the energy charges plus a significant demand charge reduction. But I'm trying to understand all the hidden costs and requirements. Does anyone have experience with PG&E's transformer ownership requirements for E-19 qualification? Their tariff book mentions "customer facilities" but doesn't spell out the technical specs clearly.
PG&E E-19 vs E-20 - When Does Customer Transformer Ownership Matter?
Paul, I've done several E-20 to E-19 conversions here in Fresno. PG&E requires that you own and maintain the primary-to-secondary transformation equipment to qualify for E-19. That means not just the transformer but also the switchgear, protective relaying, and metering equipment on the primary side. The engineering study alone can run $15,000-25,000, and then you're looking at annual maintenance contracts. The 1.5MVA transformer itself will run about $120,000 installed. Make sure your client's load factor is high enough to justify the capital investment.
Dan's numbers sound right. Here in Reno with NV Energy, the transformer ownership requirement is similar for primary service qualification. One thing to watch for is the minimum load requirement - I think PG&E's E-19 has a 500kW minimum demand threshold. If your client doesn't consistently hit that, they might get bumped back to secondary billing even with their own transformer. Also check the power factor requirements - primary service usually has stricter PF penalties.
Good point about the minimum load, Cliff. I had a client with Eversource here in Hartford who installed a customer-owned transformer but their seasonal load variations dropped them below the primary service minimum for several months. The utility averaged their annual demand and kept them on primary rates, but it was touch and go. Paul, make sure you model your client's load profile over a full year before making the investment decision. Also factor in the property tax implications - that transformer becomes assessable equipment.
Thanks for the input everyone. The load profile shows pretty consistent 800-1,100kW demand so we should be safe on the minimum threshold. Dan, those capital costs are concerning though - at $120K plus installation and ongoing maintenance, the payback period stretches out to about 4.5 years based on the rate differential. I'm also wondering about liability issues if something goes wrong with customer-owned primary equipment. Does PG&E require special insurance coverage for transformer ownership?
Yes, PG&E typically requires increased liability coverage for customer-owned primary equipment - usually $2-5 million depending on the transformer size. You'll also need to coordinate with their protection engineering group on relay settings and fault coordination. The interconnection agreement can take 6-8 months to finalize. One more consideration - if your client ever wants to sell the property, the new owner inherits all the transformer maintenance responsibilities. Some buyers see that as a negative.
I'm also in the PG&E territory (San Jose) and have been through this analysis several times. The key is getting accurate transformer loss data for your calculations. Modern transformers run about 1.5-2% losses at full load, but that varies with loading. If you're comparing E-20 secondary metering to E-19 primary metering, you need to account for those losses properly in your savings analysis. Sometimes the "savings" disappear when you factor in the actual efficiency curves. Get quotes from multiple transformer manufacturers - ABB, Siemens, and General Electric all have good options in that size range.
Pete, excellent point about the transformer losses. I was using a generic 2% loss factor but hadn't considered the loading variations. This client runs pretty steady during business hours but drops to about 200kW overnight and weekends. The efficiency curve will definitely impact the economics. I'm starting to think the payback might be longer than originally calculated, especially with Dan's insurance and maintenance cost inputs.
Paul, one more thing to consider - PG&E's time-of-use periods. The E-19 schedule has different TOU windows than E-20, and the peak period demand charges can be significantly higher on E-19 depending on when your client's maximum demand occurs. I've seen cases where the TOU restructuring actually made primary service more expensive despite the lower base rates. Make sure you model the full rate structure, not just the energy charges.
Cliff, great catch on the TOU differences. I was focused on the energy rate differential but hadn't fully analyzed the demand charge timing impacts. This is getting complicated enough that I think we need a formal engineering economic study before proceeding. The client was hoping for a quick decision but there are too many variables to wing it. Thanks everyone for the reality check - this forum saves me from costly mistakes regularly.
Smart approach, Paul. These transformer ownership decisions look simple on paper but get complex fast when you dig into all the details. Feel free to post your findings once you complete the study - always good to share real-world results with the group.
Agreed, and don't forget to factor in potential future rate changes. PG&E has been restructuring their commercial rates frequently. What looks good today might not look as attractive in 3-5 years when rate structures change again.