DER Market Design & Economics

DERs introduce new economic and business considerations alongside technical changes. This section examines DER project finance and monetization, deployment business models, the concept of "value stacking," and implications for utility economics and rate design.

Business Models for DER Deployment

Several deployment and ownership models have emerged:

  • Customer-Owned DER: The end-user purchases and owns the asset (solar, battery, CHP). Benefits from bill savings, backup power. Requires capital/credit. Economics depend on retail rate offset (influenced by NEM).
  • Third-Party Ownership (Lease/PPA): A third-party company (e.g., Sunrun, Tesla Energy) installs and owns DER on customer property.
    • Solar Lease: Customer pays fixed monthly fee.
    • Power Purchase Agreement (PPA): Customer buys DER output (per kWh) at agreed price, usually below grid rate.
    This model removes upfront cost, simplifies value prop. Popular for residential solar. Also used for community solar (developer sells subscriptions/PPAs).
  • Aggregation & Virtual Power Plants (VPPs): Provider aggregates many distributed resources (customer or third-party owned) to operate collectively and sell services.
    • Examples: DR aggregators (CPower, Enel X) enrolling C&I clients; Residential VPPs (Tesla Powerwall VPP in CA, Sunrun's ISO-NE capacity contract).
    • Relies on software and market expertise.
    • Unlocks "value stacking" by accessing wholesale market revenues unavailable to individual small resources. Key intermediary for brokers/investors.
  • Utility-Led Models: Utilities experimenting with models:
    • Utility-owned DER on customer premises (rate-basing). E.g., HECO BTM batteries, Green Mountain Power Powerwall program.
    • Non-Wires Alternative (NWA) procurements: Paying third-party DER for targeted load reduction instead of infrastructure upgrades.
    • Partnerships via competitive affiliates or third parties for C&I solutions.
    • Community Choice Aggregators (CCAs) contracting for DER projects.
    Shift from seeing DER as competition to integrating it into utility business.

Value Stacking and Revenue Streams

A core economic feature of DER is value stacking – deriving value from multiple sources simultaneously or sequentially. Unlike a traditional plant, aggregated DER can provide stacked services:

  • Retail Energy Savings: Reducing host's grid electricity purchases (kWh energy charges, kW demand charges). Primary value for BTM DER.
  • Net Metering Credits / Feed-in Tariff: Compensation for energy exported to the grid (at retail rate or specific tariff rate).
  • Capacity Payments: Payments from capacity markets (e.g., PJM, ISO-NE) or utility programs for being available during system peaks (common for DR and storage).
  • Ancillary Services: Revenue from providing grid services like frequency regulation, spinning reserve, voltage support (especially for fast-reacting batteries, smart inverters).
  • Demand Response Programs: Direct payments or bill credits from utility DR programs for peak load reduction.
  • Grid Services / Non-Wires Alternatives (NWA): Compensation for deferring distribution upgrades via targeted load relief (e.g., ConEd BQDM). Resilience value may emerge.
  • Environmental Credits: Revenue from selling Renewable Energy Certificates (RECs), carbon offsets, or LCFS credits (for EV charging).
  • Other Emerging Values: Potential future revenue from transactive energy platforms (P2P trading) or blockchain-based local markets.

Capturing multiple streams often requires aggregation or advanced control. Aggregators unlock wholesale market revenues (capacity, ancillary services) for small DER. A key challenge is avoiding double counting or conflicts between stacked services (addressed by market rules like FERC 2222 coordination requirements).

See also: Value Stacking in Demand Response

Impact on Utility Revenue and Rate Design

Widespread DER adoption challenges traditional utility economics:

  • Revenue Erosion: Customers generating own power or reducing load leads to fewer utility kWh sales. Under volumetric rates, this erodes utility revenue needed to cover fixed grid costs, raising "utility death spiral" concerns.
  • Rate Design Changes: Utilities respond by proposing:
    • Higher fixed monthly charges.
    • Demand charges (especially for residential solar customers).
    • Minimum bills.
    These aim to ensure all customers contribute to fixed costs but can reduce DER savings.
  • Performance-Based Regulation (PBR): Realigns utility incentives. Utilities earn rewards for integrating DER (e.g., NY REV allowing returns on DER program spending), becoming facilitators rather than adversaries.
  • Non-Wires Alternatives (NWA): Utilities procure DER services to defer costly infrastructure upgrades. If DER avoids a large investment, regulators may allow utilities to share savings or earn returns on NWA payments. Shifts towards open markets for grid services.
  • Rate Design Evolution: Trend towards more granular pricing reflecting costs: TOU, peak demand pricing, potentially location-based or real-time pricing. Strengthens value for DER that can respond to price signals.
  • Cost Allocation Concerns: Utilities worry about DER users paying their share of grid upkeep. Leads to debates about standby charges or grid access fees (e.g., Hawaii post-NEM).

In summary, DER economics depend on stacking multiple value components within evolving regulatory structures. Business models are adapting (leases, VPPs) to monetize DER creatively. Value stacking is key, especially for storage. Utilities and regulators must adapt market design and rates to integrate DER fairly and reliably, transforming utility business models from selling kWh to managing distributed services platforms. Energy investors and managers must track these trends, as they dictate DER project revenue and viability.