The wires business goes up for grabs as California opens its landmark case on distributed generation.
Jay Morse has studied distributed generation for the past seven years. Today, as an...
affecting the regulated gas and power industries over the last 20 years. Marston has been called one of the architects of the open-access revolution in natural gas as a result of his work as assistant to the chair on FERC Order 436 in the mid-1980s.
No Gen Is An Island
New rate-making principles for the distributed power market.
If customers install on-site generation, regulators must rethink the basic principles that govern grid services and backup power. Here is a list of principles to consider.
1. Assure the collection and e-distribution of necessary operational data. New information on the impact of dispersed generation on individual segments of the distribution system (e.g., feeders and substations) will be needed to rethink both class and customer-specific prices. Accordingly, information regarding conditions on these segments will need to be comprehensively collected and "e-distributed" to the market on a real-time basis.
2. Send accurate price signals to the "Distributed Power Market." Distribution rates and performance-based rate-making mechanisms should give customers incentives to invest in distributed generation where it is economically efficient compared to utility T&D investments (e.g., through real-time locational prices).
3. Balance equity and efficiency concerns. Many public policies are at issue in the selection among generating options. The rules governing distributed generation should take into account the full range of public policy goals, which may include such diverse objectives as encouraging energy efficiency and diversity, minimizing adverse effects on global environment and maintaining equity among all classes of ratepayers.
4. Avoid unneeded "islanding" of facilities. In designing or approving rates to distributed generators, care should be taken to avoid creating unintended incentives for users to isolate themselves from the grid. If standby charges are too high, users may respond by installing multiple, smaller generating units - providing their own redundancy and/or diversity - and avoiding the standby charge entirely. From a public policy perspective, that could lead to an economically inefficient level of investment in both T&D and generation assets.
5. Define new distribution services. Customers should be able to select distribution service with different levels of reliability (e.g., firm or non-firm), and a level of standby service that corresponds to the amount of on-site capacity that they wish to back up.
6. Recognize upstream T&D benefits. Standby rates should reflect physical and economic benefits obtained by the T&D system, or T&D benefits should be returned to self-generators through a credit mechanism.
7. Reflect realistic probabilities of outages. Rates should reflect the diversity of generating resources on the distribution system (e.g., many small generators impose less risk than one generator of the same total capacity), and the high availability of new generating equipment.
8. Reflect frequency of actual use. Standby rates should be based on actual usage of distribution capacity, to provide incentives to minimize use during times of peak load on the affected portion of the T&D system.
9. "No harm, no foul." Standby rates should charge capacity costs only for on-site generation outages that occur at the distribution system's peak, not for demands when excess capacity is available.
10. Load Reduction. Standby rates should