2.4   What Are Some Recent Major Issues Being Discussed by Regulators?

2.4.2 What Financial Questions Are Raised by Distribution Resource Plans?

Another effort is also underway that was triggered by legislation, AB 327: the requirement that the California utilities under the CPUC regulations must file Distribution Resource Plans (DRP) (see 3.6.1) with the CPUC which take into account the impacts and the benefits of DER systems. These DRP requirements were based on the principles outlined in a Resnick Institute White Paper “More Than Smart” (see 3.6.2).

These DRPs could also identify locations where DER systems could be particularly beneficial, and would identify “locational incentives” for implementing DER systems with the appropriate advanced functionalities at those locations. These DRPs would thus support utilities in exploring and making the most beneficial use of DER system capabilities. However, the challenges and questions that need to be resolved are both technical and financial.

From a financial perspective, a number of questions would need to be answered in any regulatory jurisdiction that is requesting utilities to develop distribution plans that take into account DER systems, such as [*]

• Bulk power. What are the financial impacts and potential benefits for the bulk power systems?

• Wholesale energy reductions, due to the reduced quantity of energy produced based on net load

• Reductions in the marginal wholesale price of energy (Locational Marginal Prices) if DER systems are located in strategic sites

• Reductions in the requirements for resource adequacy, such as the reductions in total generation capacity and operational reserves

• Reductions in flexible capacity, due to the reduced need of resources for system balancing

• Reduced need for other bulk power ancillary services, such as frequency management

• Reduced RPS energy prices and integration costs

• Reduced transmission capacity required for system and local area transmission

• Increased ability for DER systems to be bid into the wholesale market for energy and other services

• Avoided transmission local congestion and losses as determined by the difference between system marginal price and LMP nodal prices

• Reduces charges to Load Serving Entities (LSEs) for wholesale market and transmission access charges

• Distribution. What are the financial impacts and potential benefits for the distribution system?

• Reduced or deferred subtransmission, substation and feeder capacity upgrades, due to the reduced need for local distribution system upgrades

• Reduced distribution losses, due to losses between wholesale transaction and distribution points of delivery

• Improved distribution steady-state voltage,  including voltage limit violation relief, reduced voltage variability, and the use of compensating reactive power

• Improved distribution power quality, including minimizing transient voltage spikes and sags, avoiding or minimizing momentary outages, and providing harmonic compensation.

• Extended life for distribution equipment, by minimizing the number of switching and level changing actions

• Improved distribution reliability, resiliency, and security, by reducing the frequency and duration of outages along with the ability to withstand and recover from external natural, physical and cyber threats

• Increased distribution safety, with improved public safety and the reduced potential for property damage

• Customers and Society. What are the financial impacts and potential benefits for customers and society in general?

• Increased customer choice, which could provide customer and societal value from robust markets for customer alternatives

• Reduced CO2 emissions, reflecting federal and/or state emissions cap-and-trade allowance revenues, cost savings, or compliance costs

• Reduced health costs caused by other pollutants, due to use of renewable sources

• Increased energy security, due to the reduced risks derived from greater supply diversity and less “lumpiness” of supply

• Coordinated with water use, where synergies can be found between DER and water management (electric-water nexus)

• Fewer impacts on land use, with environmental benefits and avoided property value decreases from DER deployment instead of large generation projects

• Economic benefits for  State and/or local entities (e.g., increased jobs, investment, GDP, tax income)

In addition to these specific questions, many tariff and incentive issues need to be answered:

• What form should locational regulations and incentives take?

• How can double counting of benefits be avoided if locational and temporal incentives are used for multiple purposes?

• How should tariffs be structured to permit utility requests/commands for voltage management by DER systems?

• What financial aspects should be tariff-based and which should be left to the retail energy market?