Southern California Edison C&I battery and demand response economics

SCE delivers power to businesses across Southern California and sets the delivery side of every rate in CPUC general rate cases, including the demand charges that drive most battery economics. The 2025 decision raised SCE’s revenue by $1.685 billion from October 2025 (CPUC). In cities served by a community choice aggregator such as Clean Power Alliance, the aggregator sets the generation share of the time-of-use energy price; SCE still bills, meters and runs demand response (SCE).

The aggregators are not only price-setters. Clean Power Alliance’s $70 million Power Ready program installs solar and storage at municipal critical facilities at no cost to the sites (Clean Power Alliance). For private businesses, though, the main programs are SCE’s and the state’s.

Every deep dive on this site has one feature that changes how its economics read. At SCE it is a rate holiday for fleets. On most business rates, demand charges are the largest single reason to buy a battery. On TOU-EV-8 and TOU-EV-9, the rates for separately metered EV charging, SCE lists demand charges as “currently not applicable until determined and authorized by the Commission” ({a(EV_FS, "SCE")}). Industry guides expect them back around 2030 ({a(EV_READY, "EV Ready Energy")}, {a(EV_HELP, "EV Charging Help")}).

The holiday flips the battery’s job. At a depot on TOU-EV-8, fast charging no longer sets an expensive monthly peak, so the classic reason for a depot battery disappears and only the energy spread remains: about 35¢ on summer weekday evenings against about 8¢ off peak. That still pays for a battery over its life, but at about 10.8 yr, not 3.9 yr. If demand charges come back in 2030 at levels like TOU-GS-2, the same battery would pay back in about 5.9 yr. A fleet operator buying a battery now is betting on that date.

The other half of the fleet story is ending. Charge Ready Transport, which built make-ready infrastructure for medium- and heavy-duty fleets at low or no cost, no longer accepts applications, and agreements must be signed by December 31, 2026 (SCE). Rule 29, which covers most utility-side make-ready work for separately metered EV charging, continues (EV Charging Help).

SCE’s business programs were built for curtailment, and most participants still cut load rather than discharge a battery. TOU-BIP pays a monthly credit for interrupting at least 15% of load on 15 or 30 minutes’ notice (SCE). ELRP pays $2 per kWh for reductions from 4 to 9 p.m., May through October, with no penalty for missing an event (SCE). Auto-DR pays for the controls that let a building respond automatically (SCE).

Batteries complicate the measurement. A battery that discharges every weekday evening to save on the bill is already in the baseline that CBP-E and ELRP measure reductions against. Paying it again for an event requires an extra discharge beyond its normal schedule, or a baseline method that separates the two. Stacking needs care, depending on M&V methodology. For that reason our central case counts no event pay, and the CBP-E row in the capital stack is a what-if.

Solar barely moves an SCE business peak. Time-related demand charges are measured from 4 to 9 p.m. in summer, after solar fades, and the facilities charge can be set on any cloudy afternoon, so we credit 100 kW of solar with only 10 kW of reliable facilities-demand reduction. Business exports on the Solar Billing Plan earn hourly credits (SCE) that average a few cents at midday (SCE), well below what the site pays.

Run together, the pair is worth about $9k a year more than the two assets alone. About $5k comes from charging the battery with exports worth about 5¢ instead of grid power at about 16¢, and about $4k from holding 15 more kW off the facilities charge. SCE’s new Option DD strengthens the pairing: its facilities charge excludes demand from 8 a.m. to 1 p.m. and it adds a daily peak demand charge, and it is open to sites with or without storage, including solar customers (SCE). Midday charging, from solar or the grid, would then never set the facilities charge. SCE does not publish Option DD prices in the fact sheet, so we have not modeled it.

SCE businesses sit at the far end of the chart, next to SCE and PG&E homes. This is the opposite of Massachusetts, where business exports earn about 60% of the energy price. In Southern California, a solar-charged battery keeps nearly the full value of the evening kWh it replaces. That is the strongest case for pairing storage with new commercial solar in this series.

Every case with demand charges pays back in about 3.9 yr to 4.5 yr. The EV depot is the outlier, and its answer depends on a CPUC decision that has not been made.

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 (Morgan Lewis). Third-party storage contracts usually run 15 years or more (Peak Power), and lenders treat 15- to 20-year terms as financeable (Illinois Power Agency). The chart below values each deal from the developer’s side.

SCE is financeable for a third-party owner without any program pay. On TOU-GS-2 the developer can leave the site about 42% of bill savings and still earn its return, and the risk it carries is rate design, not a program budget: a rate case that lowered demand charges, or a move to Option DD, would change the savings. At an EV depot on TOU-EV-8, the same 15-year deal with 25% of savings to the site would cover only about 70% of the developer’s cost on our model, unless demand charges return.

Compare: PG&E C&I for B-19 demand charges in Northern California, Mass Save C&I for a net metering contrast, and Con Edison C&I for fleets in New York City.