Austin Energy C&I demand response and battery economics

Austin Energy is city-owned and a non-opt-in entity, so a business in its territory buys power from Austin Energy and sells flexibility to Austin Energy first. ERCOT’s programs are reachable, but only with the utility’s permission, which is the key structural difference from a business in Houston or Dallas.

The City of Austin leads by example: all 195 eligible city facilities are enrolled in Commercial DR, and Austin Energy ran a winter demand response test in January 2026 on the way to year-round programs (Utility Oversight Committee).

Every deep dive on this site has one feature that changes how its economics read. For Austin Energy C&I it is the boundary between the city utility’s program and ERCOT’s. Most utilities we cover either own the only program or sit inside a market where a business can choose either. Austin has both, with a fence between them.

Commercial DR runs from 1 to 7 p.m., June through September. Its top tier adds ERCOT Energy Emergency Alerts at any hour of the year, so Austin Energy’s own program already answers ERCOT emergencies (Austin Energy). ERCOT allows ERS sites in NOIE territory, but a qualified scheduling entity that is not the NOIE needs the NOIE’s written authorization (ERCOT). ERCOT counts ERS and Load Resource sites as not participating in NOIE programs (ERCOT). A site can therefore earn from Austin Energy in summer and from ERCOT outside the summer event windows, with Austin Energy approving both.

Stacking needs care, depending on M&V methodology. Austin Energy reads the meter after each event to measure energy saved; ERS uses its own baselines on the same meter, which is why overlapping hours are barred.

For a site that can lower its monthly peak, the rate does more than the program: about $184 per kW-year from the demand charge and Regulatory Charge, against $50–$80 from Commercial DR. San Antonio’s CPS Energy pays a similar $70–$73 per kW for 25 summer events (CPS Energy). Austin’s one-time Fast ADR bonus, $200 per kW in the first year, is its strongest incentive.

A Secondary-voltage site of 10–300 kW pays a $10.32 per kW demand charge plus a $5.03 per kW Regulatory Charge, which recovers ERCOT transmission costs, along with a 3.912¢ power supply charge on energy (City of Austin). The Regulatory Charge rose from $3.73 on October 1, 2026 (Austin Energy). Energy prices do not vary by hour, so a battery earns from peak shaving, not arbitrage.

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.

With 25% of savings left to the site, a 15-year deal covers about 73% of the developer’s cost on our model. At the modeled cost, a developer cannot earn 8% and still leave the site a share of bill 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 45% lower, near $131k, or a larger site where cost per kWh falls; 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. A per-kW capacity contract like the one Austin Energy signed with Base for homes is what would change that.

Austin Energy plans 270 MW of demand response by 2035 and has approved 100 MW of local battery storage (Austin Energy plan update; Austin Energy). The future of VPPs at scale will depend on multiple assets working in unison at any given site: building controls, thermal storage, EV charging and batteries, dispatched together. For businesses, the next step is clarity on whether batteries count in Commercial DR, and a year-round season if the PUCT adopts 12CP.

Compare: Dominion Energy Virginia C&I for a utility program next to a capacity market, and the Austin Energy residential deep dive for the battery pilot and Base.