Gordon C. from Santa Clarita CA. I'm working on a client who's considering relocating to the Pacific Northwest and I'm struggling to understand the BPA vs investor-owned utility rate structures. In Oregon, it looks like some areas are served by PGE (investor-owned) while others get BPA power through local public utilities. The BPA wholesale rates seem much lower, but I can't figure out how to compare them to retail IOU rates. Client is looking at about 5 MW industrial load. Can anyone explain how BPA rate schedules translate to actual retail rates?
Pacific Northwest BPA vs IOU rate analysis confusion
Beatrice S. from Salem OR. Gordon, you're dealing with one of the most complex rate structures in the country. BPA sells wholesale power to public utilities like Eugene Water & Electric Board or Clark Public Utilities, who then set their own retail rates. The BPA rates you're seeing (currently around $0.028/MWh for firm power) are wholesale - retail rates from public utilities typically add distribution costs, administrative overhead, and local improvements. For 5 MW industrial, you might see retail rates from BPA-served utilities around $0.045-0.055/kWh total, compared to PGE industrial rates closer to $0.075-0.085/kWh.
David C. from Seattle WA. Beatrice is right about the complexity. In Washington, Seattle City Light gets BPA power and their Schedule 40 (large general service) runs about $0.0521/kWh all-in for industrial customers. Compare that to Puget Sound Energy (investor-owned) Schedule 40 at around $0.0834/kWh. The catch is that BPA preference customers (public utilities) get first dibs on the cheap hydropower. When regional demand exceeds BPA resources, the public utilities have to buy supplemental power at market rates, which can be much higher.
This is exactly the kind of detail I needed. So if I understand correctly, BPA serves as a wholesale provider to public utilities, but not directly to end users? David, when you mention supplemental power at market rates, how often does that happen? Is it predictable or does it vary with hydro conditions? My client needs reliable rate forecasting for their business model.
Keith D. from Eugene OR. Gordon, the supplemental power issue varies significantly with hydrological conditions. In low water years like 2015 and 2021, BPA couldn't meet all preference customer needs and utilities had to purchase expensive market power. Eugene Water & Electric Board had to implement temporary rate surcharges during those periods. For long-term planning, most BPA preference utilities build in some risk premium for dry years. You should also consider that BPA rates are set for 2-year periods and can increase substantially - the current rate period runs through September 2025.
Nancy P. from Spokane WA. Keith mentioned the 2-year rate periods which is crucial for planning. Avista (investor-owned) serves part of Spokane while the city utility serves other areas. The rate differential can be significant - city utility industrial rates around $0.048/kWh vs Avista Schedule 25 at $0.071/kWh. But Avista has more stable rates while city utility rates can spike during regional power shortages. For 5 MW load, the annual difference could be over $500k, but with more volatility risk.
Randy Dawson here. This is a great discussion of BPA vs IOU dynamics. Gordon, for your client analysis I'd recommend building scenarios around both normal water years and drought conditions. The Northwest Power and Conservation Council publishes long-term hydro forecasts that can help with planning. Also consider that BPA preference utilities often have simpler rate structures - mostly energy charges with minimal demand charges - while IOUs have more complex demand ratchets and time-of-use periods. For industrial customers, the demand charge structure can be as important as the energy rate depending on load factor.
Randy, that's a great point about demand charge structures. Looking at Eugene Water & Electric Board Schedule G, I see a simple $4.85/kW demand charge with no ratchet, while PGE Schedule 83 has declining block demand charges starting at $16.24/kW with a 12-month ratchet. For my client's variable industrial process, the simpler structure might be worth more than the energy rate differential. This analysis is getting quite complex but the potential savings are substantial.
Gordon, one more consideration - transmission access. Some industrial sites in Oregon can choose their retail provider under direct access rules, but transmission constraints might limit options. If your client is looking at specific sites, verify whether they'd actually have a choice between BPA preference utility service and IOU service. Geographic location often determines available options regardless of rate preferences.
Beatrice, good point about direct access limitations. I've been assuming choice exists everywhere but that's clearly not the case. Working with the client to identify specific potential sites and then mapping available utility options for each. This thread has been incredibly helpful in understanding the regional complexity. Thanks everyone for the detailed explanations.