A brutal storm ripped through southwestern Minnesota in April and snapped 2,000 power poles. Worthington Public Utilities kept the lights on with a seat-of-the-pants microgrid.
California: Mandating Demand Response
California’s load-management experience argues for formal DR standards
pricing mechanisms for managing demand and supply and decrease the role of cash incentives, which are more expensive and difficult to sustain over the long haul. Additionally, the standards could be used to encourage permanent load shifting through technologies like thermal storage and pumped storage.
Rather than the current situation, in which each utility has its own system for communicating with smart thermostats and other DR-enabling technologies, a statewide standard for technologies that would implement price/emergency signal protocols also might be productive. Additionally, the load-management standards could be used as a premise to hold hearings, through which to explore the barriers that AB 1X poses to DR, and ways of addressing this issue.
To place the benefits of these standards in perspective, consider first a case in which no load-management standards are in place. In this scenario, dynamic pricing would be offered as an optional tariff by the utilities as they roll out AMI to customers. 6 An optional dynamic-pricing tariff is unlikely to achieve a participation rate greater than 20 percent and probably would not be combined with enabling technologies such as a smart thermostat. Under these assumptions, dynamic pricing could achieve a reduction in system peak demand of around 3 percent, representing over $1 billion in benefits over the next 20 years.
Now consider a second case in which a dynamic-pricing standard is adopted in California, requiring utilities to offer dynamic pricing as the default rate. Under these conditions, the literature suggests 80 percent of customers are likely to stay on dynamic pricing, with the other 20 percent opting back to their old rate. Assuming these dynamic-pricing customers are not equipped with enabling technology, the peak demand reduction could increase to some 10 percent, representing benefits of nearly $6 billion. The incremental benefit of the dynamic-pricing standard would be an increase in peak demand reduction of roughly 7 percentage points and incremental benefits of around $4 billion.
If, on top of the default dynamic-pricing standard, another standard was imposed that requires the installation of PCTs in all residential dwellings, the potential benefits would rise even further. The standard could require all residential customers be equipped with PCTs that can receive price signals so their temperature setback would be adjusted by a few degrees during critical-priced periods. With this technology installed, the estimated peak reduction potential might increase incrementally by roughly 3 percentage points to around 13 percent. 7 Collectively, demand response standards could be worth $9 billion. 8
Finally, an automated DR standard could be included with the PCT standard and the dynamic-pricing standard. This could equip commercial and industrial customers with system-wide automation, allowing them to leverage existing energy management control systems and automatically manage lights, air conditioning, and other sources of load during peak times. With this addition, the estimated peak reduction potential could increase incrementally by roughly 2 percentage points to approximately 15 percent. The present value of the benefits could increase incrementally by around $1 billion to $9 billion (see Figure 2) .
Clearly, substantial benefits can flow from implementing load-management standards. As the policy conversation