Portland General Electric C&I battery, demand charge and VPP economics

PGE’s business flexibility is built around Energy Partner, a demand response program that has run since 2020 and is part of the roughly 600 MW of flexible load PGE counts today (PGE). Energy Trust of Oregon pays upfront for business solar and storage, and Oregon has no state business battery rebate. Medium and large sites take service on Schedule 83 (31–200 kW) or Schedule 85 (201–4,000 kW), which bill most of their cost by demand.

Demand charges are the largest value per kW, but only on paper for a battery. Because on-peak demand is the highest reading across a 16-hour window, six days a week, a 400 kWh battery can hold down a peak of 100 kW for four hours or 50 kW for eight. We assume 50 kW, which needs a site whose peak is short and predictable.

Stacking needs care, depending on M&V methodology. Energy Partner measures reduction against a baseline built from the five highest-load days among the last 10 typical days. A battery that already shaves those days lowers its own baseline, so we do not stack Energy Partner with daily demand shaving.

Even with the federal credit, the best Schedule 85 case covers about 70% of cost over 10 years. Energy Partner alone covers mostly what the incentives cover, about 44%. PGE business batteries make sense where backup power, a solar project or a short, sharp peak is already driving the decision.

Energy Partner covers curtailable building load, thermostats and on-site batteries; it excludes fossil-fueled backup generators. Energy Trust’s business storage incentive runs through its solar program.

The site’s line above is only half of the deal. The developer pays the full $240k, carries maintenance, insurance and performance risk, and prices all of it into the contract to earn a return on its capital. That is why third-party storage contracts usually run 15 years or more, and why lenders treat 15- to 20-year terms as financeable. The chart below values each deal from the developer’s side.

Even keeping every dollar of demand savings for 20 years, the developer falls short. The 16-hour on-peak window limits what a four-hour battery can shave, and Oregon has no capacity auction to fill the gap: capacity in the Northwest is planned through utility resource plans and the Western Resource Adequacy Program, in which utilities show and trade capacity among themselves, so a business battery has nothing to bid into. At the modeled cost, a developer cannot earn 8% and still leave the site a share of demand savings. Battery-service offers are not priced the other way around, as a fee on top of handing over the savings: shared-savings providers promote a guaranteed share from day one (Gridwealth Electric), and Peak Power’s projects in Westchester, New York, split bill savings and market revenue with the building owner (NYSERDA case study). A deal that cannot fund a share is usually not offered at all. A guaranteed 15% share would need an installed cost about 69% lower, near $75k, well below today’s prices, so here a deal depends more on new program pay than on cheaper batteries; larger sites help, and providers such as Peak Power focus on facilities with more than 1 MW of load (Peak Power’s overview). The battery-service line above shows that 15% share.

Two PGE programs could add revenue. Energy Partner pays about $31 per kW-year at 4–8 p.m. but, as above, does not stack cleanly with daily shaving. Schedule 200, Dispatchable Standby Generation, is open to batteries of 250 kW and 750 kWh or more. Its $137.40 per kW-year rate for demand response plus reserves sets how much PGE will fund toward the switchgear, controls and wiring needed to dispatch the battery; it is not a yearly cash payment, and leaving early means repaying part of PGE’s capital.

Compare: Portland General Electric residential, Xcel Energy C&I and PG&E C&I for California.