VPP Program Designer · for utilities, aggregators, program administrators and regulators
VPP Program Designer
Design a virtual power plant (VPP) or demand response (DR) program for any North American grid and see what it delivers: dependable megawatts (MW), what participants are paid, what the program costs per kilowatt (kW), and how the measurement and verification (M&V) method changes the answer.
Change the program rules and see the payment and the grid impact side by side. Pick any North American grid operator; capacity values, reserve margins and market-access rules follow the selection.
Step 1 · Market, rules, program channel and administrator
Step 2 · Who and what is enrolled
Step 3 · Payment and dispatch
Step 4 · Grid services the program sells
Pick the services to stack. Each one needs the right channel, dispatch and telemetry; the status shows what is counted under the market rules selected in Step 1. An orange note means the service adds nothing until the input it names is changed.
Grid service assumptions
Step 5 · Measurement and verification (M&V)
How the program decides what each site delivered. The method sets what participants are paid for and how many megawatts a planner can count on.
Cost and value assumptions
How the M&V method changes the answer
Megawatts credited under each baseline method for this program, with the estimated accuracy range. Participants are paid on credited megawatts; planners can only count on the low end.
Grid value stack by service
Annual value of each grid service the program sells, with the quantity behind it. Services that are not selected, or not available under the chosen rules, channel, dispatch or telemetry, show why.
Program cost versus grid value
Annual program cost by component, next to the grid value of every service the program sells. One-time costs are spread over the program life.
Pay per participant per year
Average annual payment per enrolled site by asset type, including the enrollment incentive spread over the program life.
The short answer: CAISO (California)
- Resource adequacy is most of the value. California has no capacity market; utilities and community choice aggregators buy resource adequacy, benchmarked by the California Public Utilities Commission (CPUC) at $11.53 per kW-month for 2026, about $138 per kW-year (CPUC). The planning reserve margin is 18% for 2026 and 2027 (CPUC).
- Only demand response can sell resource adequacy. Proxy demand resources qualify; the DER aggregation model sells energy and ancillary services but not resource adequacy (CAISO). Aggregations need 100 kW in total, with no per-site minimum (CAISO).
- Midday is the other grid need. About 30% of midday hours in Southern California saw negative real-time prices in 2025 (Grid Flexibility), averaging about −$9.80 per megawatt-hour (MWh) (Modo Energy). Solar turn-down and battery charging help, but the dollars are small.
- Measurement caps batteries at the home’s own load. Demand response baselines zero out net exports today (CAISO); a fix that would count exports was paused on October 1, 2026 (CAISO).
These points change with the grid operator selected above.
Example programs, channels and rules
A starting point
Each example loads a complete design: fleet, payment, telemetry, dispatch, M&V and grid services. Pick one, then change anything. The grid operator and market rules stay as selected.
How it is registered and paid
The channel is one setting inside a design: the route to value. Utility channels (direct load control, bring-your-own-device, rates, utility VPPs) earn the utility’s avoided costs; wholesale channels (grid-operator demand response, DER aggregation) sell into the market; the hybrid channel does both.
Today or theoretical
Today’s rules count only what the selected market allows now, so energy-only markets have no capacity payment and wholesale DER models open on their published dates. Theoretical rules lift market-access limits so any channel can sell any service, to test the most capable program imaginable. Physical limits still apply.
Where the example programs come from
Bring-your-own thermostat
Up to $100 to enroll and $25 a year, about 15 events a year (no more than 20), usually up to four hours, from one utility’s published terms (program terms; program page).
All-device dispatch
Dispatching every thermostat of one brand in a utility territory, enrolled or not, delivered 23 MW from more than 15,000 devices in its first season (Uplight).
Business demand response
Curtailable load paid about $60 per kW-year, as in one Midwest utility’s current business program (Missouri PSC filing).
Residential battery program
Customer batteries dispatched in demand response events for bill credits or annual payments, as in a proposed utility pilot (Missouri PSC filing). Rates here are assumptions.
Midday flexibility
Grid-interactive solar inverters turn down, and batteries charge, when midday prices go negative (Grid Flexibility; Modo Energy). Solar adds no peak kW on its own.
DER aggregation (mixed fleet)
Order 2222 is technology-neutral: an aggregation can mix batteries, thermostats, water heaters, EVs and commercial load (FERC), though CAISO registers load reduction separately as a proxy demand resource (CAISO). Open today in CAISO (CAISO) and NYISO (NYSRC), in ISO-NE from November 2026 (ISO-NE), PJM from February 1, 2028 (PJM), MISO from 2029–30 (MISO) and SPP from 2030 (PNNL).
Fully orchestrated two-way VPP
A distributed energy resource management system (DERMS) dispatches every asset, behind and in front of the meter, around the clock, and stacks capacity, energy shifting, regulation, reserves, distribution deferral and voltage support. No program does all of this today, so the example opens in theoretical rules. Locational deferral values are already paid in places, such as up to $56.26 per kW-year at some NYSEG substations (E3).
Method and caveats
A scenario tool for program design, not a forecast or a verified evaluation. Dependable megawatts are modeled delivered kW, adjusted by the M&V method’s estimated bias, then cut to the low end of its accuracy range. Benefit-cost uses the utility cost test: avoided capacity and event-hour energy value over program costs, without discounting. Stacked services lose a set share of value because the same kW cannot serve every market at once. One-time costs are spread evenly over the program life.
Regulation and reserve defaults are recent published prices: CAISO 2025 regulation up $3.40 plus down $7.51 and spinning reserve $0.84 per MW-hour (CAISO DMM); PJM 2025 regulation $55.05 and synchronized reserve $4.23 (Monitoring Analytics); MISO 2025 regulation $19.68 and spinning reserve $3.12 (Potomac Economics); SPP regulation up about $13.50, down about $4 and spinning reserve $5.40 (Modo Energy); NYISO first-quarter 2025 regulation $16.08 (Potomac Economics) and third-quarter East spinning reserve $7.57 (NYISO); ISO-NE 2025 regulation capacity $12.21 (ISO-NE) and spring 2025 ten-minute spinning reserve $6.87 (ISO-NE); ERCOT December 2025 day-ahead regulation up $2.23, down $1.86 and responsive reserve $1.72 (ERCOT). IESO, AESO and no-RTO ancillary values are placeholders. Distribution deferral defaults to $50 per kW-year on 20% of dependable kW, within the $13.63–73.97 range for PG&E primary distribution capacity (LBNL). Energy-shifting spreads, voltage support value, the 20% co-optimization loss, vehicle-to-grid availability and the hypothetical $80 capacity value for energy-only markets are assumptions.
Avoided capacity defaults are recent published market prices for CAISO, NYISO (New York City), PJM, MISO, ISO-NE and IESO, and estimates for SPP and the two regions without an organized market. ERCOT and AESO have no capacity market. Event-hour energy values are assumptions everywhere. IESO and AESO values are in Canadian dollars.
M&V accuracy ranges are indicative program-level estimates drawn from baseline studies (LBNL; LBNL; KEMA for PJM; CAISO baseline work group; FERC and NAPDR); real accuracy depends on load type, weather and fleet size. Per-device kW, platform fees and enrollment costs are editable assumptions. VPP Economics has no affiliation with any utility, aggregator or device maker. Checked October 19, 2026.