Orchestrated VPP calculator · NYISO and CAISO
Orchestrated VPP Calculator
Build a fleet of any Distributed Energy Resources (DERs) — home batteries, thermostats, EV chargers, commercial storage, industrial loads — and see what it earns orchestrated in NYISO or CAISO markets: capacity, energy and reserves, the aggregator’s share, what each participant is paid, and how that compares with utility demand response. Built for aggregators, utilities and program managers.
An orchestrated virtual power plant (VPP) is dispatched as one resource in the wholesale market and paid on metered output, whatever the mix of devices. Choose New York ISO (NYISO) or California ISO (CAISO) rules. ERCOT follows.
Step 1 · Market and location
Step 2 · Fleet: any mix of distributed energy resources (DERs)
Step 3 · Services and program terms
Market assumptions
Where the money comes from
Gross revenue by service, before the aggregator’s share and metering costs, next to what the same fleet earns in utility and state programs.
Which kilowatts count
Each DER must offer at least 10 kW, and the Aggregation at least 100 kW of each response type.
Net pay per site per year
What one participant of each type receives, orchestrated versus utility or state programs only.
The short answer
- NYISO pays an Aggregation the way it pays a power plant: for capacity, energy and reserves, on metered output and 5-minute dispatch (NYISO).
- Size rules keep most homes out today. Each DER must offer at least 10 kW and each Aggregation at least 100 kW per response type (NYISO Aggregation Manual). A thermostat, water heater or single 5 kW battery falls short.
- So far, big loads dominate. All 426 MW of aggregations past utility review by April 2026 were demand-side resources (NYSRC), and six former large Special Case Resources supplied 221 GWh of demand response in Q1 2026 (Potomac Economics).
What the NYISO rules require
10 kW per DER, 100 kW per offer
Applied separately to demand reduction, injection and withdrawal. A DER is one site with its own utility account, revenue-grade meter and point of interconnection (NYISO).
One Transmission Node
Every DER in an Aggregation must map to the same Transmission Node; a zone-wide fleet may need several Aggregations (M-38).
Hourly meters, 6-second telemetry
Aggregations need hourly revenue-quality metering and real-time six-second telemetry through the utility (NYISO).
Duration-limited accreditation
Aggregations elect 2, 4, 6 or 8 hours. A 4-hour Aggregation in New York City is accredited at 84.4% for 2026–27 (NYISO).
Each site must qualify
An Aggregation can sell a reserve product only if every DER in it can provide that product, so the calculator groups sites by capability (NYISO FAQ).
Utility programs allowed, NYISO programs not
Dual participation in utility programs such as Con Edison’s CSRP or DLM must be reported; a DER cannot also be an SCR or EDRP resource (NYISO FAQ).
Method and caveats
Capacity: summer uses the 2026 Summer Strip auction (New York City $13.38, all other zones $4.70 per kW-month) (NY DPS); winter uses the Q1 2026 average spot price (New York City $6.25, other zones $3.37) (Potomac Economics). Firm kW = kW × capacity accreditation factor (NYISO 2026–27 CAFs) × availability × the share of the elected duration the site can sustain.
Energy: batteries earn the NYISO-wide four-hour top-bottom spread, about $50 per kW-year in 2026 (Modo Energy), times the capture rate. Demand reductions earn the dispatch price for the dispatch hours, but only above the Monthly Net Benefit Threshold ($41 per MWh for September 2026) (NYISO).
Reserves: 2025 average day-ahead prices: East 10-minute spinning $8.49, non-synchronized $7.89, 30-minute $6.19 per MWh; West $6.28, $6.20 and $6.19 (NYISO). Rest of State uses West prices.
Utility comparison: Con Edison’s CSRP pays $6–$18 per kW-month, May to September ($60 per kW-year used for NYC) (Con Edison); elsewhere, $50 per kW-year from New York’s battery load management programs (NYSERDA). Edit it under Market assumptions.
Assumptions to check: metering and telemetry at $250 a year per home and $1,500 per business site; aggregator share 40%; demand reductions dispatched 60 hours a year at $150 per MWh; reserves offered 3,000 hours a year. These are planning placeholders, not published figures. Regulation, penalties for missed dispatch, interconnection costs and taxes are not included. Gross revenue is not participant profit.
The short answer
- California has no per-site minimum. A Proxy Demand Resource needs 100 kW in total for energy and 500 kW for spinning or non-spinning reserves, so any mix of homes can qualify together (CAISO).
- Resource adequacy is most of the value, and only demand response can sell it. CAISO has no capacity market; utilities and CCAs buy resource adequacy bilaterally, and the DER Aggregation model is not eligible (CAISO). The CPUC’s 2026 benchmark is $11.53 per kW-month (CPUC).
- Batteries are capped at their own home’s load. Demand response measurement zeroes out net exports today (CAISO). A fix that would count exports was paused on October 1, 2026 and is expected to resume in 2027 (CAISO).
What the CAISO rules require
100 kW in total, no per-site floor
Demand response needs 100 kW for energy and 500 kW for reserves; a DER Aggregation needs 100 kW, with no minimum per DER and each DER capped at 1 MW (CAISO).
One sub-LAP
Each aggregation must sit in one of about 23 sub-load aggregation points; a DERA spanning several pricing nodes is capped at 20 MW (CAISO).
Demand response or DER Aggregation
A DERA must include at least one DER that injects energy; load-only fleets participate as Proxy Demand Resources (CAISO).
Resource adequacy, sold bilaterally
Demand response can count toward resource adequacy if a utility or CCA shows it, with a must-offer obligation and at least 4 hours per dispatch; DERAs cannot (CAISO).
Net export zeroed out
Today a customer’s meter data is set to zero when it net-exports. The July 2026 proposal would apply the limit to the aggregation instead (CAISO); it is now paused until 2027 (CAISO).
One payer per kilowatt
DSGS bars dual compensation with ELRP and other programs (CEC), so the calculator compares the paths rather than adding them.
Method and caveats
Resource adequacy: counted kW × availability × the share of 4 hours the site can sustain × the CPUC 2026 unified Market Price Benchmark of $11.53 per kW-month ($138 per kW-year) (CPUC). Actual contract prices vary; edit it under Market assumptions.
Energy: batteries earn CAISO’s 2025 simulated four-hour battery energy revenue of about $39 per kW-year times the capture rate; actual batteries earned about $35 (CAISO Department of Market Monitoring). Load reductions earn the dispatch price for the dispatch hours.
Reserves: 2025 day-ahead averages were $0.84 per MWh for spinning and $0.94 for non-spinning reserves (CAISO DMM). Regulation is not available to demand response or DERAs (CAISO).
Program comparison: home and commercial batteries use DSGS Option 3, $62–$83 per kW a year by duration plus the 30% bonus for 2025–2026 (CEC); thermostats use SCE’s Smart Energy Program, up to $50 a year (SCE); business loads use ELRP at $2 per kWh reduced, up to 60 hours a year (CPUC). Residential EV charging and water heaters are given no program pay.
Assumptions to check: evening site load of 2 kW for battery homes (2.5 kW with two batteries) and 80 kW for the commercial battery site; metering, data and scheduling coordinator costs of $25 a year per home and $500 per business site for demand response, which uses existing utility meters, and $250 and $1,500 for a DERA, which needs per-DER metering and telemetry; aggregator share 40%; load reductions dispatched 40 hours a year at $200 per MWh; capture rate 90%. All sites are assumed to be in one sub-LAP. Penalties, the net benefits test and interconnection costs are not modeled. Gross revenue is not participant profit.