Recent Regulatory Changes Affecting Rates (c. 2023–2025)

The regulatory landscape for electricity is constantly evolving. Several key changes implemented or under development between 2023 and 2025 significantly impact Commercial & Industrial (C&I) tariffs and procurement strategies across deregulated U.S. markets.

Introduction of Dynamic and Demand Flexibility Rates

  • Regulators are increasingly pushing for rates that reflect real-time costs to encourage peak reduction and renewable integration.
  • California: CPUC approved expanded dynamic pricing pilots (incl. RTP) for IOUs (2024-2027), potentially leading to default dynamic rates for large C&I by 2025+. Rulemaking 22-07-005 focuses on demand flexibility and new rate designs.
  • Illinois: CEJA promotes TOU/RTP options; ComEd offers Rate BESH (hourly pricing) for medium C&I.
  • Pennsylvania: PUC directed utilities (e.g., PECO) to develop optional TOU generation rates for default service (rolled out 2023).
  • Trend: Moving away from flat rates toward time-varying structures (TOU, Critical Peak Pricing, RTP).

Net Metering and DER Compensation Reforms

  • Regulators are adjusting how customer-sited generation (like solar) is compensated to better reflect grid value and manage costs.
  • California NEM 3.0 (Net Billing Tariff): Effective April 2023, drastically reduced export credits to avoided cost rates, incentivizing solar+storage for self-consumption.
  • Illinois Smart Solar Billing: Legislation initiated transition away from NEM by 2025, likely towards net billing with TOU elements, plus smart inverter rebates.
  • New York VDER Value Stack: Already replaced NEM for larger projects, crediting exports based on multiple time- and location-specific value components.
  • Impact: On-site generation economics become more complex; simple bill offsets are less common. Requires careful analysis and often pairing with storage. Growing state incentives for storage complement these reforms.

Capacity Market & Resource Adequacy Changes

  • ISOs are refining capacity market rules to ensure reliability amidst fleet transition.
  • PJM: FERC approved minor tweaks potentially lowering RPM prices slightly (2023). Stricter capacity performance rules implemented. Recent auctions cleared low, but future shortfall warnings exist.
  • MISO: Shifted to seasonal capacity auctions (from 2023/24). Tightened capacity accreditation for renewables/storage. Resulted in extreme price volatility in constrained zones (e.g., IL Zone 4 in '22/23, MO Zone 5 in '24/25).
  • ISO-NE: Ongoing Resource Capacity Accreditation changes (by 2025) will affect how hybrid resources count. Discussing Capacity Constraint Accounting (CCA).
  • Impact: Increased potential for capacity price volatility, especially zonal. Makes capacity cost forecasting more complex and highlights the value of peak load management and potentially bilateral contracts.

Transmission & Network Charge Updates

  • Significant investments in transmission infrastructure (for reliability, renewables integration) are leading to rising transmission charges.
  • Texas: PUCT approved TDU rate increases including Transmission Cost Recovery Factors (TCRFs) (e.g., Sept 2023).
  • PJM: Costs of baseline projects (incl. for state policies like NJ offshore wind) allocated to zones, increasing network rates in some areas (e.g., PSE&G).
  • ISO-NE: Formula rate updates increased Regional Network Service (RNS) charges.
  • Impact: Transmission costs are a growing component of C&I bills. Brokers should factor in escalation or use pass-through mechanisms in contracts.

Aggregation and Market Access (FERC Order 2222)

  • ISOs implementing rules (c. 2023-2026) to allow aggregations of DERs (batteries, flexible loads, generators) to participate in wholesale markets.
  • Status Varies: NYISO & CAISO have active DER participation models. PJM & MISO implementations ongoing.
  • State Opt-Outs: States retain some authority to limit retail customer participation via aggregators (legacy of Order 719).
  • Impact: Creates new potential revenue streams for C&I customers with flexible assets, working through aggregators.
  • See also: DER Policy & Regulation & FERC Order 2222

State Clean Energy Mandates & Default Supply Changes

  • States with ambitious clean energy goals (e.g., IL CEJA 100% by 2045) are implementing policies that create new bill charges.
  • Examples: Illinois "Carbon-Free Energy Adjustment" (funding nuclear); NYSERDA charges (RECs, ZECs); potential offshore wind contract costs socialized via distribution rates (MA, CT, RI).
  • Utilities are tweaking default service offerings (e.g., adding TOU options in PA, potentially sourcing more renewables in MD).
  • Impact: New mandatory charges appear on bills regardless of supplier. Default service becoming more complex, potentially creating opportunities for competitive suppliers to differentiate.

Retail Market and Broker Regulations

  • Increased state oversight of brokers and retail suppliers to enhance consumer protection.
  • Examples: NY DPS enforcement of marketing standards; Illinois broker certification requirement (2023).
  • Stricter rules on "green" marketing claims (requiring specific REC types or local sourcing).
  • Impact: Affects how brokers operate and necessitates compliance with disclosure and marketing rules.

Staying informed about these ongoing regulatory shifts is crucial for energy brokers and C&I customers to navigate costs, identify savings opportunities, and ensure compliance in the evolving energy landscape.