The Eastside Power Authority (em composed of four California irrigation districts, one municipal utility, and two water districts (em plans to leave Southern California Edison's (SCE's) electric...
Pricing Reform for the Local Disco: Setting Rates That Will Support Distributed Generation
services cost-effectively. Depending on the regulatory form established, however, regulators will have to decide when it makes sense to try to develop markets for ancillary services as opposed to allowing the UDC to provide them on a regulated monopoly basis.
# Generally speaking, DA is the use of DG resources for a variety of system functions including voltage support, and, potentially, system expansion in lieu of traditional wires and structures. An important agenda item that regulators have not yet recognized, therefore, involves defining and distinguishing DA from bulk power production at the distribution level. (This DA concept seems to have originated with Albert H. Benson in his Oct. 18 memo to Hugh Saussy, director of the Department of Energy's Boston office.)
While no one wants to create conditions that could give the UDC an opportunity to favor its own generation, the limited use of DG technologies in a carefully defined DA setting significantly may enhance the efficiency of existing system assets. DA also ultimately may enable the UDC to offer radically new processes and services.
More importantly perhaps, the pricing structure provides the UDC with incentives to achieve short- and long-term efficiency and maintain appropriate investment levels, especially in response to DG deployment. The tariff ensures that UDC profits are maximized when capacity is sufficient to serve load effectively; insufficient or excess capacity levels will reduce profits. The pricing structure induces the UDC to make efficient tradeoffs among capital-related costs (e.g., the access charge) and other cost elements such as congestion. Finally, in stark contrast to traditional COS-based approaches, the proposed cost-based tariff, when implemented under PCR or PBR, encourages the UDC to find the most cost-effective-rather than the most asset-intensive-solutions to customer problems. Under a COS regime, efficiency benefits accrue largely through regulatory lag.
The proposed UDC tariff has three components: (1) an access charge based on kilowatt-hour demand, (2) a throughput charge based on kilowatt-hour usage of the local grid (in addition to any energy charges), and (3) a congestion charge. Each of these components plays a role in inducing efficiency and providing incentives for maximizing the status of the system for all market participants, including DG owners. The three components are discussed further below:
1. Access Charge (Demand). The access charge generally would be based on a historic (e.g., 12-month) moving average of the load's contribution to system peak, however defined and measured. (Full implementation of this charge therefore requires appropriate metering, although load-profiling results could be used in the interim.) That represents a departure from the traditional "fixed" customer charge in that access revenues under this charge depend on two factors: the system's ability to offer capacity and the load's coincident peak usage (however defined and measured).
This arrangement encourages the UDC to find the most economical ways to add customers and capacity, thus promoting cost-effective use of both fossil-fired and renewables-based DG. On the other side of the meter, customers can manage this charge by adjusting their peak consumption. This feature, along with the fact that the charge generally will be lower for users with smaller energy