MERCHANT REVENUE STREAMS

REAL-WORLD ANALYSIS FOR AN EVOLVING ENERGY LANDSCAPE

The Fractal Model co-optimizes battery degradation and physical constraints with the ISO-specific revenue streams. By simulating dispatch at 5-minute and hourly intervals, it delivers the high-resolution, transparent data, and sensitivity analysis, required to de-risk merchant storage investments for lenders and equity partners.

Electric Reliability Council of Texas (ERCOT)

Footprint: 90% of Texas.

Notes:

  • ERCOT is an energy only market. No capacity market.
  • “Real-Time Co-optimization plus Batteries (RTC+B)” was implemented on December 5, 2025. Under RTC+B, Ancillary Services (AS) are no longer “static” obligations bought once a day and locked in. Instead, they are dynamically co-optimized with energy every five minutes in the Real-Time Market (RTM).
  • DRRS has a “go live” date slarted for late 2026.

Revenue Opportunities Include:

  • Arbitrage (RT & DAM): Profit from the price spread between charging at low prices and discharging during peaks; settled at the Node (LMP) in 5-minute (RT) and hourly (DAM) intervals; paid in $/MWh.

  • Regulation Up (RT & DAM): Sub-minute adjustments to increase frequency via AGC; now co-optimized every 5 minutes in RT; paid in $/MW-hour.

  • Regulation Down (RT & DAM): Sub-minute adjustments to decrease frequency via AGC; now co-optimized every 5 minutes in RT; paid in $/MW-hour.

  • Responsive Reserve Service (RRS) (RT & DAM): High-speed frequency response for sudden contingencies; now cleared in both DAM and RT co-optimization; paid in $/MW-hour.

  • Fast Frequency Response (FFR) (RT & DAM): A sub-type of RRS providing sub-second response to frequency deviations; cleared in both DAM and RT; paid in $/MW-hour.

  • ERCOT Contingency Reserve Service (ECRS) (RT & DAM): 10-minute ramping product to handle net-load ramps and sustained frequency events; cleared in both DAM and RT; paid in $/MW-hour.

  • Non-Spinning Reserves (RT & DAM): 30-minute response for longer-duration contingencies or forecast errors; cleared in both DAM and RT; paid in $/MW-hour.

  • Dispatchable Reliability Reserve Service (DRRS) (RT & DAM): Implementation targeted for Late 2026. 30-minute offline-to-online reliability product to reduce RUC instructions; expected to clear in both DAM and RT; paid in $/MW-hour.

Pennsylvania-New Jersey-Maryland Interconnection (PJM)

Footprint: Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia, and the District of Columbia.

Revenue Opportunities Include:

  • Energy Arbitrage (RT & DAM): Managing congestion across the RTO; settled at the Node (LMP) in 5-minute (RT) and hourly (DAM) intervals; paid in $/MWh.

  • Regulation Service (RT): Consolidated Phase 2 Design (2025/26). Fast-responding frequency signal following a single bi-directional AGC signal (RegD signals were consolidated); paid a capacity price in $/MW-hour + mileage (performance) credits.

  • Synchronized Reserves (RT): 10-minute contingency response from online resources; now cleared every 5 minutes and co-optimized with energy; paid in $/MW-hour.

  • Secondary Reserves (RT): 30-minute response product for grid stabilization and longer-duration contingency recovery; cleared in real-time every 5 minutes; paid in $/MW-hour.

  • RPM Capacity Market (Auction): Annual payments for peak availability; cleared through the Base Residual Auction (BRA) and Incremental Auctions (IA); payments based on Effective Load Carrying Capability (ELCC) accreditation; paid in $/MW-day.

ISO New England (ISO-NE)

Footprint: Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island, and Vermont.

Revenue Opportunities Include:

  • Energy Arbitrage (RT & DAM): Shifting offshore wind and gas-constrained power; settled at the Node (LMP) in 5-minute (RT) and hourly (DAM) intervals; paid in $/MWh.

  • Regulation (RT): Automatic Generation Control (AGC) for frequency stability; resources follow a 4-second signal; paid a capacity clearing price in $/MW-hour + service (performance) credits.

  • Day-Ahead Ancillary Services (DAAS): Replaced the Forward Reserve Market on March 1, 2025. Daily procurement of 10-minute and 30-minute reserves (TMSR, TMNSR, TMOR) to bridge the “uncertainty gap” between day-ahead and real-time; paid in $/MW-hour.

  • Forward Capacity Market (FCA) (Auction): Annual payments for capacity cleared 3 years in advance to ensure long-term reliability; paid in $/kW-month.

  • ConnectedSolutions (VPP): Distribution-level performance payments for summer/winter peak shaving via utility-administered battery programs; paid in $/kW-performance.

Alberta Electric System Operator (AESO)

Footprint: Alberta. Alberta is a purely “energy-only” merchant market, meaning there are no capacity payments. Batteries must earn their entire return through energy and ancillary services.

Revenue Opportunities Include:

  • Energy Arbitrage (RT): Buying low and selling high in the real-time market; shifted from a single “Pool Price” to Nodal Pricing (LMP) in 2026 to reflect local congestion; settled in 5-minute intervals; paid in $/MWh.

  • Regulating Reserve (RT): Continuous sub-minute adjustments via AGC to balance fluctuations; procurement volumes are now dynamically adjusted hourly to manage steep solar and wind ramps; paid in $/MW-hour.

  • Spinning Reserve (RT): Resources synchronized to the grid that can respond within 10 minutes; now co-optimized with energy to reduce “opportunity cost” conflicts; paid in $/MW-hour.

  • Supplemental Reserve (RT): Resources that can reach full power in 10 minutes without synchronization; often provided by behind-the-meter load or quick-start assets; paid in $/MW-hour.

  • Fast Frequency Response Plus (FFR+) (Contracted): New for 2026. A high-availability service procured via commercial contracts (up to 750 MW) to support intertie flows; requires sub-second response and a 60-minute sustain capability; paid in $/MW-hour.

  • Congestion Arbitrage (RT): New Opportunity for 2026. Enabled by Optimal Transmission Planning (OTP), which allows for managed congestion; batteries can now earn revenue specifically by resolving local bottlenecks that the AESO intentionally leaves “un-built.”

SPP Markets+ (Western Interconnection)

Footprint Participating balancing authorities across the Pacific Northwest, Mountain West, and Western Canada.

Overview: SPP Markets+ is a conceptual and operational expansion of the Southwest Power Pool’s services into the Western Interconnection. Unlike the full SPP RTO, Markets+ is a “day-ahead” market service designed for utilities in the West that aren’t ready to join a full RTO but want the efficiencies of a centralized market. As of 2026, Markets+ is active across portions of Washington, Oregon, Idaho, Wyoming, Montana, Colorado, Arizona, and British Columbia.

Revenue Opportunities Include:

  • Energy Arbitrage (DAM): Shifting low-cost solar or hydro generation from the morning to the evening ramp; paid in $/MWh.

  • Regulation Up (DAM): Reserving capacity to increase generation in response to sub-minute frequency signals; paid in $/MW-hour.

  • Regulation Down (DAM): Reserving capacity to decrease generation in response to sub-minute frequency signals; paid in $/MW-hour.

  • Short-Term Ramping Up/Down (DAM): A flexible product designed to handle the “Duck Curve” and rapid changes in wind/solar output; paid in $/MW-hour.

  • Operating Reserves (Spin/Non-Spin) (DAM): 10-minute and 30-minute contingency products to ensure grid reliability during unexpected outages; paid in $/MW-hour.

  • Resource Adequacy (Western Power Pool – WPP): While Markets+ provides the dispatch, the “Capacity” payment typically flows through the Western Resource Adequacy Program (WRAP); paid in $/kW-month.

Alberta Electric System Operator (AESO)

Footprint: Alberta. Alberta is a purely “energy-only” merchant market, meaning there are no capacity payments. Batteries must earn their entire return through energy and ancillary services.

Revenue Opportunities Include:

  • Energy Arbitrage (RT): Buying low and selling high in the real-time hourly market; paid in $/MWh.

  • Regulating Reserve (RT): Continuous sub-minute adjustments to balance sub-second fluctuations; paid in $/MW-hour.

  • Spinning Reserve (RT): Resources synchronized to the grid that can respond within 10 minutes to a contingency; paid in $/MW-hour.

  • Supplemental Reserve (RT): Resources that can reach full power in 10 minutes but do not need to be synchronized; paid in $/MW-hour.

  • Fast Frequency Response (FFR) (RT): A newer sub-second response product specifically designed to combat low-inertia issues on the Alberta grid; paid in $/MW-hour.

CAISO Extended Day-Ahead Market (EDAM)

Footprint: Participating Balancing Authorities across California, Oregon, Washington, Nevada, Idaho, Utah, and Wyoming.

Revenue Opportunities Include:

  • Integrated Forward Market (IFM) Arbitrage (DAM): Capturing the value of the “Day-Ahead Duck Curve” by shifting surplus regional solar/hydro to evening peaks; settled in hourly intervals; paid in $/MWh.

  • Imbalance Reserves (Up/Down) (DAM): New for 2026. A capacity product designed to reserve upward and downward ramping capability to bridge the “uncertainty gap” between the Day-Ahead forecast and Real-Time reality; paid in $/MW-hour.

  • Reliability Capacity (Up/Down) (DAM): Replaced Residual Unit Commitment (RUC). Payments to ensure sufficient physical capacity is committed and “online” to meet the ISO’s reliability forecast; paid in $/MW-hour.

  • Ancillary Services (Reg/Spin/Non-Spin) (DAM): Co-optimized across the entire EDAM footprint, allowing resources to provide frequency and contingency reserves for loads in other balancing areas; settled in hourly intervals; paid in $/MW-hour.

  • Greenhouse Gas (GHG) Awards (DAM): A co-optimized model that uses a “Reference Pass” (counterfactual run) to attribute clean energy transfers to specific state carbon policies; paid as a Price Adder ($/MWh).

  • Congestion Revenue Rights (CRRs) (DAM): Financial instruments used to hedge against the cost of transmission congestion between EDAM zones; Phase 1 (Go-Live) design focuses on equitable allocation of revenues from EDAM transfer constraints; paid in $/MW.

California Independent System Operator (CAISO)

Footprint: 80% of California and a small portion of Nevada.

Notes:

  • As of the 2025/2026 compliance years, California has fully transitioned away from the old “4-hour peak” counting rule to a 24-hour hourly showing framework. This fundamentally changes how a battery’s capacity is valued and sold. RA value now depends on Charging Sufficiency—showing the state has enough excess solar in midday slices to charge the battery before it can “count” in the evening slices.
  • IR has a “go live” date slated for May 2026.

Revenue Opportunities Include:

  • Energy Arbitrage (DAM, FMM, & RTD): Capturing value by shifting midday solar to evening peaks; settled across Day-Ahead (IFM), 15-minute (FMM), and 5-minute (RTD) intervals; paid in $/MWh.

  • Regulation Up/Down (DAM & FMM): Maintaining grid frequency via sub-minute AGC signals; awarded in the Day-Ahead and refined in the 15-minute market; paid in $/MW-hour.

  • Spinning Reserves (DAM & FMM): Synchronized resources reaching full power in 10 minutes; awarded in the Day-Ahead and 15-minute markets; paid in $/MW-hour.

  • Non-Spinning Reserves (DAM & FMM): Resources reaching full power in 10 minutes from a standstill; awarded in the Day-Ahead and 15-minute markets; paid in $/MW-hour.

  • Imbalance Reserves (IR) Up/Down (DAM Only): New for 2026. Capacity reserved Day-Ahead to cover the uncertainty between the Day-Ahead forecast and Real-Time 15-minute needs; paid in $/MW-hour.

  • Resource Adequacy (RA) (Contracted): Bilateral capacity payments that require the resource to be available and bid into the market; paid in $/kW-month.

New York Independent System Operator (NYISO)

Footprint: New York State.

Revenue Opportunities Include:

  • Energy Arbitrage (RT & DAM): Balancing upstate renewables and Canadian imports against downstate load centers; settled at the Node (LBMP) in 5-minute (RT) and hourly (DAM) intervals; paid in $/MWh.

  • Regulation Service (RT): Sub-minute frequency management via AGC; resources follow a high-speed signal; paid a capacity clearing price in $/MW-hour + performance movement (mileage) credits.

  • Operating & Uncertainty Reserves (RT & DAM): Includes 10-minute (Spin/Non-Spin) and 30-minute reserves, plus the newly deployed Uncertainty Reserve product to handle renewable forecast errors; co-optimized with energy; paid in $/MW-hour.

  • ICAP Capacity Market (Monthly): Payments to ensure local and statewide reliability; based on seasonal Capacity Accreditation Factors (CAF) that de-rate nameplate MW; influenced by the “CHPE-Out” reliability parameters for 2026; paid in $/kW-month.

  • Index Storage Credits (ISC) (Contracted): A 15-year revenue floor provided by NYSERDA for awarded projects; settled as the difference between a strike price and a Reference Price (composed of energy arbitrage and capacity values); paid in $/MWh.

Midcontinent Independent System Operator (MISO)

Footprint: Arkansas, Illinois, Indiana, Iowa, Kentucky, Louisiana, Michigan, Minnesota, Mississippi, Missouri, Montana, North Dakota, South Dakota, Texas, Wisconsin, and Manitoba (Canada).

Revenue Opportunities Include:

  • Energy Arbitrage (RT & DAM): Managing regional wind-rich (North) and solar-heavy (Central) zones against a thermal-heavy South; settled at the Node (LMP) in 5-minute (RT) and hourly (DAM) intervals; paid in $/MWh.

  • Regulating Reserve (RT & DAM): Real-time frequency following via AGC; procurement targets were increased to 600 MW+ in 2026 with dynamic hourly requirements to handle steeper solar ramps; paid in $/MW-hour.

  • Spinning & Supplemental Reserves (RT & DAM): 10-minute and 30-minute contingency products; prices are now heavily influenced by a $10,000/MWh Value of Lost Load (VOLL) scarcity cap; paid in $/MW-hour.

  • Short-Term Reserve (STR) (RT & DAM): Expanded to DAM in late 2025. A 30-minute flexibility product designed to handle net-load forecast errors and sudden wind/solar drops; now clears in both markets to ensure “deliverability” before the operating hour; paid in $/MW-hour.

  • Planning Resource Auction (PRA) (Seasonal): Capacity payments cleared through a four-season auction (Summer, Fall, Winter, Spring); based on Accredited Capacity (SAC) which de-rates batteries based on historical performance during “Risky Hours”; paid in $/MW-day.

Southwest Power Pool (SPP)

Footprint: Arkansas, Iowa, Kansas, Louisiana, Minnesota, Missouri, Montana, Nebraska, New Mexico, North Dakota, Oklahoma, South Dakota, Texas, and Wyoming.

Revenue Opportunities Include:

  • Energy Arbitrage (RT & DAM): Managing renewable curtailment and steep ramps in the central wind corridor and newly integrated Western footprint; settled at the Node (LMP) in 5-minute (RT) and hourly (DAM) intervals; paid in $/MWh.

  • Regulation Up/Down (RT & DAM): Core frequency response following AGC signals; now co-optimized across the expanded East and West Balancing Authorities; paid in $/MW-hour.

  • Spinning & Supplemental Reserves (RT & DAM): Standard 10-minute contingency products; cleared in both markets; paid in $/MW-hour.

  • Uncertainty Product (RT & DAM): Formerly known as Ramping Capability. A product designed to handle net-load and renewable deviations over 30-to-60-minute windows; cleared in the DAM and RTBM to ensure the grid can “bend” without breaking; paid in $/MW-hour.

  • Resource Adequacy (Bilateral – ELCC): A bilateral obligation framework where LSEs must secure accredited capacity for two distinct seasons. Accreditation is now based (2026) on Effective Load Carrying Capability (ELCC) rather than a simple 4-hour rule. Summer 2026 requires a 16% PRM, while Winter 2026–27 jumps to a 36% PRM; paid in $/kW-month.

Independent Electricity System Operator (IESO)

Footprint: Ontario. Ontario uses a hybrid model of “Market Renewal” (shifting to a Day-Ahead Market in 2025/2026) and long-term capacity contracts.

Revenue Opportunities Include:

  • Energy Arbitrage (RT & DAM): Profiting from price spreads across a financially binding Day-Ahead Market (DAM) and 5-minute Real-Time Market; settled at the Node (LMP) to reflect local congestion and losses; paid in $/MWh.

  • Regulation Service (RT): Specialized AGC-based frequency following; resources follow a high-speed signal; paid in $/MW-hour via a “Capability” (availability) and “Performance” (mileage) payment.

  • Operating Reserves (RT & DAM): Includes 10-minute Spinning/Non-Spinning and 30-minute Supplemental reserves; now co-optimized with energy in both the DAM and RT markets to maximize battery dispatch efficiency; paid in $/MW-hour.

  • Capacity Auction (Seasonal): A competitive auction for short-term reliability; evolved in 2026 to include distinct Summer and Winter obligation targets (e.g., 1,800 MW Summer / 1,200 MW Winter) to manage nuclear refurbishment gaps; paid in $/MW-day.

  • Long-Term Reliability Services (LT-RFP / MT-RFP): Long-term (15–20 year) contracts for new-build storage; structured as a Monthly Fixed Payment to ensure project bankability, often combined with a revenue-sharing mechanism; paid in $/MW-month.

  • Global Adjustment (GA) Shaving: A “behind-the-meter” strategy for Class A industrial customers to reduce their share of Ontario’s GA costs by discharging during the Top 5 peak hours of the year; paid as an Avoided Cost ($/MW).

Western Energy Imbalance Market (WEIM)

Footprint: Arizona, California, Idaho, Montana, Nevada, New Mexico, Oregon, Utah, Washington, Wyoming, a portion of Texas, and British Columbia (Powerex).

Overview:
The WEIM, operated by CAISO, is a real-time energy-only market that allows utilities across the West to trade imbalances in their load and generation.

Revenue Opportunities Include:

  • Real-Time Energy Arbitrage (FMM & RTD): Capturing value from price fluctuations between the 15-minute (FMM) and 5-minute (RTD) markets; settled at the Node (LMP); paid in $/MWh.

  • Imbalance Energy Settlements (FMM & RTD): Payments for delivering energy to cover deviations between a utility’s local schedule and actual real-time demand; cleared in both FMM and RTD; paid in $/MWh.

  • Flexible Ramping Product (FRP) (FMM & RTD): A real-time capacity payment for resources providing upward or downward ramping capability; awarded in FMM (for 15-minute uncertainty) and RTD (for 5-minute uncertainty); paid in $/MW-hour.

  • Bid Cost Recovery (BCR) (RT): Monthly and daily make-whole payments ensuring that a battery’s total real-time operating costs are covered if market dispatch results in a net loss; calculated across all RT intervals; paid in Total $ uplift.

  • GHG Shadow Pricing (FMM & RTD): A carbon adder for clean resources outside California “deemed delivered” to the CAISO BAA; cleared in both FMM and RTD to account for real-time dispatch changes; paid as an Adder ($/MWh).

SPP RTO West

Footprint: As of its official launch on April 1, 2026, the SPP RTO West footprint spans Arizona, Colorado, Montana, Nebraska, New Mexico, Utah, and Wyoming (integrated with the existing 12-state Eastern footprint).

Revenue Opportunities Include:

  • Energy Arbitrage (RT & DAM): Nodal trading across the West BAA; co-optimized via the DC ties (Stegall, Sidney, Miles City) in 5-minute (RT) and hourly (DAM) intervals; paid in $/MWh.

  • Regulation Up/Down (RT & DAM): Secondary frequency control; cleared in DAM and RT to manage Western renewable volatility; paid in $/MW-hour.

  • Spinning & Supplemental Reserves (RT & DAM): 10 and 30-minute contingency products; co-optimized across the footprint in DAM and RT; paid in $/MW-hour.

  • Uncertainty Product (RT & DAM): Ramping capability for net-load forecast errors; cleared in DAM and RT (5-10 minute horizons); paid in $/MW-hour.

  • TCR/ARR Congestion Hedging (DAM): Financial instruments to hedge price spreads; includes specific DC Tie Entitlements for inter-connection transfers; paid in $/MW.

  • Resource Adequacy (Binding Winter 2026/27): Compliance with the Western Resource Adequacy Program (WRAP) and SPP PRMs; paid via bilateral contracts or performance incentives.

Fractal ModelMERCHANT REVENUE STREAMS