ISO/RTO Specific Charges & Mechanisms

Each Independent System Operator (ISO) or Regional Transmission Organization (RTO) has unique market rules, capacity constructs, and pricing mechanisms that significantly influence the final electricity costs for C&I customers within their footprint. Understanding these regional differences is vital for accurate cost forecasting and effective procurement strategies.

PJM Interconnection (Mid-Atlantic/Midwest)

  • Capacity Market (RPM): Uses the Reliability Pricing Model (RPM) with forward auctions (Base Residual & Incremental) setting capacity prices ($/MW-day) by zone for future years.
  • Peak Load Contribution (PLC): Customer's capacity obligation is based on their average demand during the 5 highest PJM system peak hours (5CP) of the previous summer. Drives capacity cost allocation.
  • Transmission (NSPL): Network Service Peak Load (NSPL) tag, often based on contribution to annual PJM or zonal peak, determines allocation of network transmission costs ($/kW-year). Often passed through via utility transmission riders.
  • Energy Pricing (LMP): Locational Marginal Pricing used.
  • Demand Response: Robust DR programs (Emergency & Economic) allow participation in capacity and energy markets.
  • Key Strategy: PLC management via peak shaving during predicted 5CP hours is critical for controlling capacity and transmission costs.

ERCOT (Texas)

  • Energy-Only Market: No centralized capacity market or direct capacity charges.
  • Scarcity Pricing (ORDC): Relies on the Operating Reserve Demand Curve (ORDC) adder, which increases energy prices significantly (up to $5,000/MWh cap) when operating reserves are low. ORDC enhancements in 2023 increased potential adders.
  • Ancillary Services: Costs for reserves (including the newer ECRS product launched mid-2023) are procured by ERCOT and uplifted to loads, typically passed through by REPs.
  • Demand Response (ERS): Emergency Response Service pays customers for availability to curtail load during highest-level emergencies.
  • Nodal Pricing & Congestion: Prices vary by node; congestion risk exists, though often hedged by REPs for standard contracts.
  • Key Strategy: Managing exposure to extreme price volatility through fixed contracts, hedging, or active load curtailment during scarcity events (often signaled by conservation alerts).

NYISO (New York)

  • Capacity Market (ICAP): Installed Capacity market ensures resource adequacy via monthly auctions.
  • ICAP Tag: Customer's capacity obligation based on their demand during the single NYISO system peak hour of the previous year.
  • Locational Capacity Prices: ICAP prices vary significantly by zone (e.g., NYC Zone J typically much higher than upstate zones) due to local constraints.
  • State Surcharges (NYSERDA): Significant charges funding state programs (RECs, ZECs for nuclear, potentially Offshore Wind) collected via utility bills or supplier pass-throughs. Impacted by CLCPA goals.
  • Demand Response (SCR): Special Case Resource program allows C&I load curtailment to be treated and paid as capacity. Transitioning to 6-hour performance requirement (2024). Utility DR programs also exist (CSRP/DLRP).
  • Energy Pricing (LBMP): Locational Based Marginal Pricing used, with distinct zones.
  • Key Strategy: ICAP tag management (reducing load during the predicted single system peak hour) is crucial, especially downstate. Leveraging DR programs and understanding state surcharge impacts are also key.

ISO New England (New England)

  • Capacity Market (FCM): Forward Capacity Market procures capacity via auctions (FCAs) three years ahead.
  • Capacity Tag (Peak Contribution): Customer's obligation based on demand during the single ISO-NE system peak hour of the prior year (recently around $2-3/kW-month in many zones, but historically higher and potentially rising).
  • Transmission (RNS): High transmission costs allocated via Regional Network Service charges, also based on contribution to the single system peak hour. RNS costs ($/kW-year) can be comparable to or exceed capacity costs.
  • Energy Pricing (LMP): Generally higher LMPs than other regions, especially in winter due to gas constraints.
  • Demand Response: Active Demand Resources participate in capacity and energy markets; utility programs like Connected Solutions link to ISO needs.
  • Key Strategy: Intense focus on managing load during the single annual system peak hour is paramount due to the double impact on both capacity and transmission charges.

MISO (Midcontinent)

  • Resource Adequacy (PRA): Historically annual, now seasonal Planning Resource Auctions (PRA) clear capacity prices by Local Resource Zone (LRZ).
  • Zonal Capacity Price Volatility: Prices can vary dramatically by zone and season if a zone is short on capacity (e.g., Zone 4 Illinois spiked in 2022/23; Zone 5 Missouri spiked in 2024/25 Fall/Spring auctions, reaching CONE levels).
  • Capacity Accreditation Rules: Tightening rules for renewables/storage effective capacity can influence future prices.
  • Retail Choice Limited: Mainly relevant for competitive customers in Illinois (Ameren) and Michigan (Choice cap). Michigan has SRM capacity charge mechanism.
  • Energy Pricing (LMP): Nodal pricing; potential for North/South price separation.
  • Demand Response: DR Resources can participate in PRA and energy markets.
  • Key Strategy: Tracking seasonal PRA results for relevant zones is crucial due to recent volatility. Bilateral capacity contracts may be sought for stability. Peak load management gaining importance.

CAISO (California)

  • Resource Adequacy (RA): No centralized auction; LSEs (Utilities, CCAs, ESPs) must procure sufficient system, local, and flexible RA capacity bilaterally or via solicitations to meet CPUC requirements.
  • RA Costs: Included in rates by ESPs/CCAs; costs rising due to tighter supply. Risk of high charges via Capacity Procurement Mechanism (CPM) if LSE is deficient.
  • Energy Market & Net Load: LMP-based energy. Significant solar penetration shifts net load peak to evening (4-9 pm TOU periods common). Requires flexible resources.
  • NEM 3.0 (Net Billing): Major 2023 change significantly reduces export credits for new solar, incentivizing self-consumption and storage.
  • Demand Charge Reforms: Innovative EV tariffs reducing/eliminating demand charges; broader reforms potentially coming via CPUC rulemakings focused on demand flexibility.
  • Retail Structure: Hybrid with IOUs, growing CCAs, and limited Direct Access.
  • Key Strategy: Understanding RA cost components in supply offers, optimizing solar+storage under NEM 3.0 rules, leveraging new dynamic rates and EV tariffs where applicable.

Navigating these regional nuances requires specialized knowledge. Brokers must understand the specific cost drivers (capacity tags, transmission allocation, scarcity pricing rules, state surcharges) within each ISO/RTO to provide accurate advice and structure effective energy management strategies for C&I clients.