Utility program deep dive · Northern and Central California
PG&E C&I battery, demand charge and VPP economics
How B-19 demand charges, the Base Interruptible and Capacity Bidding programs, ELRP and the ending DSGS program stack up for a business battery.
VPP Economics has no affiliation with, sponsorship from, or endorsement by any utility, aggregator, platform, or device maker named here.
The short answer
- Demand charges make PG&E one of the strongest markets for a business battery. On B-19 secondary service, the summer peak-window demand charge is $46.16 per kW and the maximum-demand charge is $37.37 per kW every month (PG&E B-19). In our central case, a 250 kW / 1,000 kWh battery cuts the bill by about $70k a year and pays back in about 6.3 years with the 30% federal credit.
- The peak window is 4–9 p.m. every day, and five hours long. A four-hour battery cannot cover the whole window at full power, so the reliable shave is set by energy, not inverter size. We assume 175 kW.
- Demand response pays less than the bill, and it overlaps. The Base Interruptible Program (BIP) pays up to $15.90 per kW-month in summer (PG&E AL 7738-E), about $153 per kW-year at the smallest tier. Its reduction is measured at the meter against a firm service level, so kW already used to shave the daily peak cannot be counted again.
- State VPP pay is ending, and rebates are closed. DSGS has no funding after 2026 (CALSSA), and SGIP’s general-market storage budget is closed (PG&E). The business case now rests on the tariff and the federal credit.
What each PG&E program is
B-19 demand charges
Three demand charges on one bill: maximum demand at any time, the peak during 4–9 p.m., and the part-peak during 2–4 and 9–11 p.m. Summer is June–September (PG&E B-19). Smaller sites on B-10 pay a single $20.50 per kW maximum-demand charge (PG&E B-10).
B-19 Option S for storage
Replaces most of the monthly peak charge with daily charges of $1.60 per kW in summer and $1.22 in winter, with a lower maximum-demand charge (PG&E B-19). It rewards shaving every day rather than avoiding one bad 15-minute interval a month.
Base Interruptible Program (BIP)
Monthly pay on potential load reduction, whether or not events are called; 15- or 30-minute notice; up to 180 event hours a year; $6 per kWh charge for usage above the firm service level; 100 kW minimum (PG&E, PG&E AL 7738-E).
Capacity Bidding Program (CBP)
Aggregator-managed, day-ahead, May–October, events of up to four hours (PG&E). The aggregator’s contract, not the tariff, sets what the site receives (Symmetric Energy).
Value per kW of flexible capacity
Value per kW-year by source
What one kW of reliable reduction is worth a year, bundled B-19 secondary service.
Swipe to see the full chart →
The maximum-demand charge is the most valuable kW on the bill but the hardest to capture: it is set by the single highest 15-minute interval of the month, at any hour, so the battery must be charged and ready whenever the site peaks. The peak-window charge is easier because the hours are known. Our central case counts 175 kW off the peak window and only 40 kW off maximum demand.
Stacking needs care, depending on M&V methodology. BIP measures the whole-site load against a firm service level, so a battery that already discharges every evening shows little extra reduction on event days. BIP fits best with curtailable process load; the battery handles the daily demand charge.
The capital stack
Ten-year capital stack
Federal credit plus 10 years of avoided costs as a share of installed cost plus 10 years of maintenance. Past the dashed line, the package more than covers its cost.
Swipe to see the full chart →
Every case clears the 10-year line, even without the federal credit. Peak-window savings alone are about $36k a year, about as much as the entire bill-savings case for the same battery at Xcel Energy Colorado. The $17k of energy shifting comes from the same evening discharge, so it stacks without conflict.
Simple payback
Years to repay net cost from avoided costs, net of maintenance.
Swipe to see the full chart →
Assets and combinations
Shave the 4–9 p.m. window
A four-hour battery covers most of the five-hour window. Longer durations capture more of the peak-window charge; extra power without energy does not help.
Solar charges, storage shaves
Solar lowers midday demand but not the 4–9 p.m. peak. Paired with storage, it supplies charging energy in place of grid off-peak power; B-19 has a separate Option R for solar customers (PG&E B-19).
BIP’s natural fit
Chillers, pumps and process loads that can drop to a firm service level earn BIP pay without using battery capacity (PG&E).
Separate Business EV rates
PG&E’s Business EV rates apply to separately metered charging, and a stationary battery used solely for EV charging qualifies (PG&E).
Financing and ownership
Own, borrow or share savings
A 250 kW / 1,000 kWh battery at a B-19 secondary site, central case.
Swipe to see the full chart →
The developer’s side
The site’s line above is only half of the deal. The developer pays the full $600k, 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.
What the developer earns
Present value of what the developer receives, as a share of what it spends, by contract terms.
Swipe to see the full chart →
PG&E’s large bill savings make a third-party deal possible, but the site’s share is small: about 7% of bill savings over 15 years, or about 17% over 20, for the developer to earn 8%. A 25% split would leave the developer short. A funded DSGS successor or a resource adequacy contract could add revenue, but only for capacity not already committed to daily shaving, and neither is modeled here.
Additional Finance Options and Considerations
Captures the bill and the credit
Net cost about $420k after the 30% credit, repaid from about $66k a year of net savings.
Positive from year one
Payments of about $61k a year are below the bill savings, so the battery can be debt-financed at 8% and still produce cash every year. Interest totals about $191k over the term.
Capital-free, small share
A developer owns the battery, claims the credit and keeps most of the bill savings: about 7% goes to the site over 15 years. It suits sites without tax appetite or capital budget.
For BIP or CBP
If the site also enrolls curtailable load, the aggregator or PG&E contract should state how battery discharge is treated in the baseline.
What ifs
Demand charges move
B-19 demand charges were reduced in March 2026 (PG&E B-19). A shift from demand to energy charges would shrink the largest layer.
Daily demand charges
At $1.60 per kW-day in summer, a site that shaves every day saves about $195 per kW over the summer, close to the standard peak-window value, but with far less risk from one missed day (PG&E B-19).
Construction-start deadlines
Losing the 30% credit adds about $180k to net cost and roughly 3 years to payback.
State VPP pay
A funded successor to DSGS would add a market-based layer, but only for battery capacity not already committed to daily shaving.
The swing factor
Each additional 10 kW reliably taken off maximum demand is worth about $4k a year.
CCA generation rates
Sites served by a CCA pay PG&E delivery charges and CCA generation charges; the generation side of the energy shift will differ.
Compare: PG&E residential for households, and Xcel Energy C&I for a lower-demand-charge contrast.
Method and caveats
An independent, hypothetical analysis for business owners, facility managers, program designers, developers and other readers in PG&E’s service area. Terms checked October 26, 2026.
Assumptions: 250 kW / 1,000 kWh battery at $600 per kWh; $15 per kW-year maintenance; 30% federal credit; bundled B-19 secondary service; 175 kW off peak-window demand and 40 kW off maximum demand; daily discharge of 875 kWh at 90% round trip.
Taxes and surcharges are excluded. Figures are illustrative avoided costs before financing, degradation and augmentation. Gross payments are not net profit.
VPP Economics has no affiliation with, sponsorship from, or endorsement by PG&E, the California Energy Commission, any aggregator or any company named here.