North America — Use cases
Battery storage modeling for North American projects
Stack revenues across ERCOT, CAISO, PJM, NYISO, ISO-NE, MISO, SPP, AESO, and IESO — with full IRA §48E ITC tax credit modeling, domestic content and energy community bonus adders, transferability mechanics, and duration sizing in one workflow.
The North American BESS market
The United States had approximately 30 GW of utility-scale BESS operational at end of 2024, with a pipeline of 200+ GW in interconnection queues across all ISOs and RTOs. The 2022 Inflation Reduction Act transformed the economics of every project in that pipeline: §48E ITC makes standalone storage eligible for a base investment tax credit, technology-neutral from 2025. Domestic Content adder (10 percentage points) rewards domestically manufactured cells and modules under §45X. Energy Community adder (10 percentage points) applies to projects in former fossil fuel-dependent communities. Transferability under §6418 allows tax credit monetisation by project developers without sufficient tax appetite; direct pay under §6417 extends this to tax-exempt off-takers.
The modelling challenge is compound: optimise dispatch across a revenue stack that differs by market, size duration under multiple market-design assumptions, and then compute the after-tax project economics including IRA credit mechanics. HOMER Front handles all three in a single workflow, using market inputs you configure.
In Canada, AESO's Energy Storage market (Alberta) and IESO's LT1 and E-LT1 RFPs (Ontario) are the two primary utility-scale BESS procurement channels. Canadian ITCs — Clean Technology ITC (30%) and Clean Electricity ITC (15%) — apply to BESS projects under federal eligibility rules.
30+ GW
US utility-scale BESS operational (2024)
200+ GW
US BESS in interconnection queues
2.5+ GW
Canada IESO LT1 BESS capacity contracted
HOMER Front for North American BESS
What HOMER Front does
- ›Multi-market revenue stacking — Energy, Capacity, Regulation, and Time of Delivery streams combined in one dispatch simulation
- ›IRA tax credit modelling: §48E ITC (Investment Tax Credit), §45Y PTC (Production Tax Credit) and others
- ›Day-ahead, fifteen-minute, and real-time energy price modelling, with multi-year price strips imported per market
- ›Capacity-market revenue through a configurable Capacity Market stream — applicable to PJM RPM, NYISO ICAP, ISO-NE FCM, MISO PRA, and Canadian procurements
- ›Duration sizing optimisation: 1-hour through 10-hour+ under different market mixes
- ›Standalone vs co-located solar+storage IRA credit interaction modelling
- ›Augmentation strategy: battery degradation, capacity guarantees, and replacement scheduling over 20-year project life
How the markets map. HOMER Front does not ship per-ISO presets. It represents revenue through four configurable streams — Energy, Capacity, Regulation, and Time of Delivery — that you adapt to each market with your own price data and assumptions. Among ancillary services it covers frequency regulation; it has no dedicated market type for spinning, operating, or contingency reserves. The market notes below are general context — see the ancillary services and incentive modelling guide and the HOMER Front manual for detail.
Market-by-market BESS context
ERCOT (Texas)
ERCOT is the most active US BESS market by installed capacity. The energy-only market design means all revenue comes from energy and ancillary services — no capacity payment exists. AS products include ECRS (ERCOT Contingency Reserve Service, introduced 2023), RRS (Responsive Reserve Service, which requires automatic underfrequency activation), Reg-up and Reg-down (via AGC), and Non-Spinning Reserve. Real-time energy price volatility in ERCOT — regularly reaching the $5,000/MWh offer cap during scarcity events — rewards fast-responding, high-cycle-rate BESS assets. Post-Uri reforms (February 2021 winter storm) have tightened weatherisation requirements and ancillary service procurement volumes.
In HOMER Front, ERCOT energy revenue is modelled by importing day-ahead and real-time Settlement Point Prices (SPPs) into the Energy Market, with Reg-Up and Reg-Down represented through the Regulation Market. The absence of a capacity market means duration sizing focuses on the regulation and energy-arbitrage spread rather than capacity-award probability.
CAISO (California)
CAISO's Slice-of-Day Resource Adequacy (RA) reform (effective August 2024) replaced the previous Must-Offer Obligation structure with a granular 24-hour slice requirement. BESS assets must demonstrate availability in each of the 24 RA slices they commit to, creating a more complex dispatch and availability management requirement. Flexible RA and Dynamic RA layer additional obligations; all three are Resource Adequacy constructs you would represent through the Capacity Market stream.
Ancillary services in CAISO include Regulation Up/Down (via AGC), Spinning Reserve, Non-Spinning Reserve, and Replacement Reserve. Day-ahead and real-time energy arbitrage under day-ahead market (DAM) and real-time market (RTM) prices complete the revenue stack. California SGIP provides additional BTM storage incentives for co-located residential and C&I projects.
PJM (Mid-Atlantic and Midwest)
PJM's Reliability Pricing Model (RPM) capacity auction is the anchor revenue stream for BESS in the PJM footprint. Delivery year capacity auctions (Base Residual Auction, or BRA) and Incremental Auctions (IA1, IA2, IA3) provide 1–3 year capacity commitments with performance penalties for non-delivery during emergencies. In HOMER Front, PJM capacity revenue is represented through the Capacity Market stream, with the capacity price and discharge events you configure to reflect RPM auction outcomes and Capacity Performance obligations.
PJM ancillary services include Regulation (via AGC, including up and down), Spinning Reserve, Non-Spinning Reserve, and Reactive Power capability. Of these, regulation maps onto the Regulation Market; in HOMER Front it stacks with the Capacity and Energy Market streams, reconciled through the Order of Commitment.
NYISO (New York)
NYISO's Installed Capacity (ICAP) market procures capacity through monthly and strip auctions differentiated by load zone. New York's Bulk Storage Incentive Program (administered by NYSERDA) provides capital incentives for large-scale BESS in load zones with capacity constraints — New York City and Long Island in particular. In HOMER Front, ICAP revenue is represented through the Capacity Market stream and regulation through the Regulation Market; reserve products have no dedicated market type.
ISO-NE, MISO, and SPP
ISO-NE's Forward Capacity Market (FCM) procures capacity 3 years ahead with Performance Incentive Payments (PIPs) and Performance Incentive Charges (PICs) rewarding or penalising performance during scarcity hours. MISO's Planning Resource Auction (PRA) and SPP's Resource Adequacy program each have distinct capacity market structures. In HOMER Front, the capacity revenue in all three is represented through the generic Capacity Market stream, and frequency regulation through the Regulation Market; reserve products such as ISO-NE Forward Reserve and SPP Operating Reserve have no dedicated market type.
AESO (Alberta, Canada)
Alberta operates Canada's only fully competitive energy-only electricity market. AESO's Energy Storage market procures ancillary services — Regulation, Spinning Reserve, Supplemental Reserve — alongside real-time energy from BESS assets. No capacity payment structure exists. Revenue modelling parallels ERCOT in structure: energy price volatility and AS clearing prices are the primary value drivers. Canadian Clean Technology ITC (30%) and Clean Electricity ITC (15%) apply to qualifying projects. In HOMER Front, AESO revenue is modelled by importing Alberta energy price scenarios into the Energy Market, with regulation represented through the Regulation Market.
IESO (Ontario, Canada)
IESO's Long-Term 1 (LT1) RFP awarded 2.5+ GW of 20-year capacity contracts in 2023–2024, primarily to BESS projects. Contracted capacity payments provide the anchor revenue; the Market Renewal Program (MRP, effective 2025) introduces a Day-Ahead Market (DAM) that creates new energy arbitrage opportunities. In HOMER Front, LT1 contracted revenue maps onto a Time of Delivery contract or the Capacity Market stream, regulation onto the Regulation Market, and post-MRP DAM and real-time arbitrage onto the Energy Market.
Ready to model your North American BESS project?
Whether you are optimising ERCOT regulation and energy stacking, structuring a PJM capacity market position, or evaluating an IESO LT1 project with Canadian ITC mechanics, HOMER Front gives you a flexible revenue model you configure to the market your investment decision depends on.