North America — Use cases
Regulation, energy, and incentive modelling for BESS across North American ISOs
A market-by-market view of how regulation, energy, and capacity products are settled across ERCOT, CAISO, PJM, NYISO, MISO, SPP, AESO, and IESO — what HOMER Front models directly, and how state-level programmes such as Massachusetts Clean Peak and ConnectedSolutions fit alongside wholesale participation.
Why ancillary services need market-specific modelling
North American BESS revenue rarely comes from energy arbitrage alone. Across the seven US ISOs, the two Canadian system operators, and the non-RTO Western and Southeastern utilities, ancillary services typically contribute 30–70% of total BESS revenue in the first years of operation. The exact share, and the optimal duration and cycling strategy, depend heavily on how each market defines and settles regulation, reserves, frequency response, and ramping products.
The same headline product name — “regulation”, “spinning reserve” — can mean materially different things in different markets. PJM’s RegD pays a fast-following BESS a capability payment plus a mileage payment scaled by a performance score, with hourly settlements and substantial revenue at performance scores above 0.9. ERCOT’s Reg-Up, by contrast, has no mileage component at all and clears in the day-ahead market like a capacity product.
On top of wholesale services, several states have introduced structured incentive programmes — Massachusetts Clean Peak, the New England ConnectedSolutions programme, New York’s Bulk Storage Incentive, California SGIP, New Jersey SuSI — that overlay scheduled or event-based dispatch obligations on the underlying market participation. In HOMER Front, these are represented through its revenue-stream and incentive inputs rather than rolled into a single “AS revenue” assumption.
7
US ISOs/RTOs with distinct AS product stacks
30–70%
Typical AS contribution to BESS revenue, year 1–3
4
Configurable revenue-stream types — Energy, Capacity, Regulation, and Time of Delivery
What HOMER Front models — and what it does not
HOMER Front does not ship pre-built, ISO-specific market setups. There is no built-in “ERCOT mode” or “CAISO mode”, and no embedded clearing prices for any particular market. Instead, it provides a single generic, flexible architecture that you adapt to any market by supplying the prices, constraints, and assumptions yourself.
Project revenue is represented through four configurable revenue-stream types:
Energy Market
Wholesale energy bought and sold — Day-Ahead (DAM), Fifteen-Minute (FMM), and Real-Time (RTM) markets, in any combination. You import the $/MWh price strips, including multi-year strips for late-stage analysis, and set escalators.
Capacity Market
Payment for pledged capacity, with discharge events you define as random (count and duration per year) or on specific dates. Compensation combines a capacity price with an energy price for the discharged energy.
Regulation Market
Frequency regulation — Reg-Up, Reg-Down, or a combined Reg-UpDown product. A day-ahead capacity price signal drives commitment, with a real-time dispatch percentage applied as energy throughput.
Time of Delivery (TOD)
A form of power purchase agreement — energy sold at a contracted price set with a 12×24 schedule or an imported annual profile, with optional daily or annual export obligations.
You adapt these to a specific market by supplying the price data, choosing which streams apply, and setting the constraints — power rating, state-of-charge bounds, round-trip efficiency, the per-market Maximum Storage Commitment, and the percentage of solar or wind output allocated to each market.
Scope of ancillary-service coverage. Among ancillary services, the Regulation Market is HOMER Front’s only dedicated construct. There is no built-in market type for spinning, operating, or contingency reserves, for fast frequency response, or for ramping products. Those products are described in the sections below as market context, not as HOMER Front features.
The market-by-market sections that follow are general guidance — they explain what each ISO settles, and therefore what you would need to configure. For the authoritative list of inputs and capabilities, see the HOMER Front product page and the HOMER Front manual.
Disclaimer — the ISO and market descriptions that follow are general industry guidance, believed accurate at the time of writing. Market rules, product definitions, and clearing prices change frequently; always verify against current ISO documentation and apply your own project-specific data and assumptions when modelling.
Regulation services — how each ISO settles
Regulation is the most BESS-favourable ancillary product in every North American market, and the one ancillary service HOMER Front represents directly — through its Regulation Market, which models a Reg-Up, Reg-Down, or combined Reg-UpDown product. Settlement mechanics, however, vary across two axes: the split between capability and mileage payments, and whether performance scores apply multiplicatively or as a binary qualification threshold. These are differences you capture by shaping the price signal you supply, not by selecting a market preset.
PJM — RegA and RegD
PJM operates two regulation signals: RegA (slow, traditional, matched to thermal generation ramp rates) and RegD (fast, dynamic, designed for BESS and flywheels). RegD performance is scored each hour on accuracy, delay, and precision, producing a performance score typically between 0.85 and 0.99 for well-tuned BESS. Settlement combines a capability payment (paid for cleared MW) and a mileage payment (paid for actual movement following the AGC signal), each multiplied by the hourly performance score.
The economic implication: a BESS with consistent 0.95+ performance scores on RegD earns substantially more per MW-hr than a unit drifting around 0.85. The assumed performance score and the RegD capability/mileage split are both worth treating as explicit, adjustable assumptions when you build the regulation price signal.
CAISO — Regulation Up / Regulation Down
CAISO procures Regulation Up and Regulation Down as separate products in the day-ahead and 15-minute markets, with a Mileage Multiplier applied to settle the actual AGC signal volatility against the cleared capacity. Resources that are energy-limited — which includes all BESS — must qualify under the Regulation Energy Management (REM) framework, which allows continuous bidding without violating SOC constraints by allowing the ISO to issue energy management instructions.
CAISO regulation co-optimises with Spinning Reserve, Non-Spinning Reserve, and Replacement Reserve under the integrated forward market, so each of those products has its own clearing-price behaviour to account for.
ERCOT — Reg-Up, Reg-Down, FFR, and ECRS
ERCOT’s regulation differs from every other US market in one important respect: there is no mileage payment. Reg-Up and Reg-Down clear in the day-ahead market as capacity products at a single $/MW-hr price; the AGC signal-following obligation is enforced through compliance rather than rewarded through volumetric mileage payments. This makes regulation a more predictable, lower-variance revenue stream in ERCOT than in PJM or NYISO, though absolute prices are typically lower.
Two adjacent ERCOT products are highly BESS-suited: Fast Frequency Response (FFR), which pays for sub-second injection following an underfrequency event, and ECRS (introduced 2023), which sits between Spinning Reserve and traditional regulation in response time. ECRS has been a major BESS revenue driver since launch, frequently clearing above $100/MW-hr during summer scarcity.
Because ERCOT is an energy-only market, there is no capacity payment — the full ancillary-service stack (Reg-Up, Reg-Down, RRS, ECRS, FFR, and Non-Spin) is settled purely on clearing prices. Of these, the Reg-Up and Reg-Down products map onto the HOMER Front Regulation Market; the reserve-type products are described later as market context.
NYISO — Regulation Service with movement payment
NYISO settles Regulation Service through a capacity component plus a movement (mileage) component, each scaled by a performance index. BESS participates under the Limited Energy Storage Resources (LESR) model, which acknowledges the energy-limited nature of the asset and prevents over-commitment beyond the duration the SOC can support. Locational constraints matter: NYC and Long Island regulation prices are typically higher than upstate due to transmission constraints, so zone-specific price series should be used as inputs.
MISO — Regulating Reserve and Short-Term Reserve
MISO Regulating Reserve is co-optimised with energy in the day-ahead and real-time markets, with ramp capability and mileage compensation applied. The Short-Term Reserve product (launched 2022) sits alongside traditional Spinning and Supplemental Reserve and has provided new BESS-suited revenue. MISO is the largest US RTO by geography and has substantial price variation across LRZs (Local Resource Zones), which is worth reflecting through zonal price inputs where data is available.
SPP — Regulation-Up, Regulation-Down, and Energy Storage Resource participation
SPP procures Regulation-Up and Regulation-Down with mileage settlement. BESS participation under the Energy Storage Resource (ESR) model is comparatively new in SPP; the market has fewer operational BESS assets than ERCOT, CAISO, or PJM, and price discovery is still evolving, which makes the choice of forward-curve assumptions especially important.
AESO and IESO (Canada)
Alberta’s AESO procures Regulation, Spinning Reserve, and Supplemental Reserve in a competitive market with energy-only price formation. Ontario’s IESO operates Regulation and Operating Reserve services alongside the Market Renewal Program (MRP, effective 2025) which introduces a Day-Ahead Market. Canadian BESS projects are typically anchored on LT1 / E-LT1 capacity contracts (Ontario) or merchant energy + AS (Alberta), with the Canadian Clean Technology ITC (30%) or Clean Electricity ITC (15%) applied at the financing layer.
State-level BESS incentive programmes across North America
Alongside wholesale market participation, several states and provinces run structured incentive programmes that overlay scheduled or event-based dispatch obligations — or capital incentives — on a BESS project. The descriptions below are general guidance on each programme. A schedule-based programme such as Clean Peak maps naturally onto a Time of Delivery contract, an event-based programme onto Capacity Market discharge events, and a capital incentive onto the project economics inputs — each configured to the programme’s published rules.
California SGIP
The Self-Generation Incentive Program provides capital incentives to BESS at multiple tiers, including the Equity and Equity Resiliency tiers for high-fire-risk areas. SGIP tier eligibility and the capital incentive can be modelled in HOMER Grid alongside CAISO wholesale and TOU rate stacking.
New York Bulk Storage Incentive
NYSERDA-administered capital incentives for large-scale BESS, with higher per-kWh values in load-zone-constrained areas (NYC, Long Island). The incentive can be stacked against NYISO ICAP, regulation, and energy revenue when you set up the project.
New Jersey SuSI
The Successor Solar Incentive program supports solar-plus-storage projects with structured payments. Modelled alongside PJM wholesale participation for co-located assets.
Massachusetts SMART
The Solar Massachusetts Renewable Target programme includes storage adders for solar-plus-storage configurations. It can be layered with Clean Peak and wholesale market revenues when modelling a full Massachusetts revenue stack.
Massachusetts Clean Peak Energy Standard
The Clean Peak Standard compensates clean energy delivered into seasonally-defined peak windows, with multiplier values that vary by season and by hour. Because the schedules are published in advance, it behaves as a predictable, time-based incentive that rewards discharge into the qualifying peak hours.
ConnectedSolutions
A utility-run demand-response programme across Massachusetts, Connecticut, Rhode Island, and New Hampshire that pays for performance during a limited number of called dispatch events each summer. Because events are triggered by system conditions rather than a fixed schedule, the dispatch obligation is uncertain at any given hour.
Hawaii programmes
HECO Battery Bonus, Bring Your Own Device (BYOD), and Customer Grid Services (CGS) programmes structure BTM BESS dispatch obligations against Hawaii’s 100% RPS target. Modelled in HOMER Grid for non-interconnected island systems.
Canadian Clean Technology ITC
30% federal investment tax credit for qualifying clean technology including BESS. Stacked alongside provincial procurement (AESO Energy Storage, IESO LT1 / E-LT1) and Clean Electricity Regulations compliance.
How HOMER Front combines revenue streams: the Order of Commitment
When a project participates in more than one market, HOMER Front does not blend them into a single, freely co-optimised dispatch. Instead it follows a defined Order of Commitment — a priority sequence that decides which market has first claim on the battery.
1. Committed obligations come first
Capacity Market obligations are settled before everything else, followed by Time of Delivery contracted capacity. These are treated as firm commitments the battery must honour, so they are met before any participation in the Energy and Regulation Markets.
2. Energy and Regulation use what remains
Participation in the Energy and Regulation Markets is allocated from the storage capacity left after Capacity Market and Time of Delivery obligations have been met.
3. Day-Ahead before Real-Time
Within the energy markets, the Day-Ahead Market is committed ahead of the Real-Time Market, reflecting the order in which a real operator commits capacity.
4. Two-day rolling optimisation
HOMER Front optimises each Energy Market together with the other revenue streams and components two days at a time, searching for the highest net present value within that window.
5. Maximum Storage Commitment caps exposure
Each market has a user-set Maximum Storage Commitment — a cap on how much of the battery’s capacity can be offered into that market in any time step. It is a physical exposure limit, not a proportional economic split, and is typically set higher for committed markets than for opportunistic ones.
6. Renewables allocated by user-defined percentages
Co-located solar and wind output is non-dispatchable. Its distribution across the available markets is set by user-specified percentages (PV Allocation, Wind Turbine Allocation), independent of price signals — avoiding spurious price-based allocation that would not be achievable in real operation.
Because committed obligations are honoured in priority order and physical exposure is capped per market, the resulting revenue projection reflects a dispatch the battery could realistically deliver, rather than the theoretical upper bound of a free, perfect-foresight optimisation. For the precise behaviour of each market and the full list of configurable inputs, see the HOMER Front product page and the HOMER Front manual.
Common questions
Can HOMER Front compare two or more BESS types in the same simulation?
Yes!, and this is a core use case. HOMER Front lets you evaluate multiple battery configurations under the same simulation conditions, enabling a fair, side by side comparison. Each BESS (with different degradation, c rate, efficiency, or cost) is optimized independently, so you can clearly see the impact on project economics.
This is especially valuable during procurement, where selecting the right battery technology is critical.
Does HOMER Front model degradation and augmentation?
Yes. Battery capacity degradation is modelled with user-configurable assumptions, and augmentation can be scheduled — or omitted entirely, with a State of Health (SOH) limit defining when the BESS stops functioning — and is capitalised in the project economics.
How does HOMER Front handle ISO market design changes during the project life?
Energy Market prices are imported as time-series, and multiple price strips can be mapped to specific years in late-stage analysis, so structural changes can be reflected by shifting the price series at the year boundary. Examples: ECRS introduction in ERCOT (2023), CAISO Slice-of-Day RA reform (2024), Ontario MRP DAM launch (2025).
What about non-RTO regions — the Southeast and Western Interconnection outside CAISO?
Bilateral PPA structures with utility off-takers (Duke, Southern Company, TVA, Salt River Project, PacifiCorp) can be modelled as Time of Delivery contracts. The Western EIM and EDAM extend CAISO-style energy market participation into the wider West, and can be set up as an Energy Market revenue stream where applicable.
Can we get a working session on a specific project?
Yes. For projects combining state-level incentives (Clean Peak, ConnectedSolutions, SuSI, SMART) with wholesale market participation, we recommend a working session to set programme assumptions explicitly before running the model. Get in touch with the team.
Related guides
Modelling ancillary services and structured incentives for your project?
Whether you are stacking ERCOT regulation with energy arbitrage, combining Clean Peak with wholesale market revenue, or evaluating a multi-market AESO position, HOMER Front gives you a flexible revenue model you configure to the market your investment decision depends on.