Interview with Jim Parks
Jim Parks, an IEEE Smart Grid Technical Expert, is a program manager in the Smart Grid department at the Sacramento Municipal Utility District. He has held a central role in SMUD’s Smart Grid deployment and currently oversees the final stages of the Smart Grid implementation. He is also developing a long-term roadmap for SMUD’s Smart Grid programs.
In this interview, Jim Parks provides some of the latest success stories and research findings from SMUD’s Smart Grid deployment, which is nearly complete. He highlights the distinctive benefits the company is receiving from its advanced metering infrastructure, which reaches nearly 100% of the customer base. He also provides findings from smart pricing pilot programs in the residential sector, which gained significant customer participation and achieved important reductions in peak load.
Question: The Sacramento Municipal Utility District has nearly finished its Smart Grid deployment. We’re eager to learn about the installation, the impact on your business, and customer benefits, but could you first give us a general characterization of the project?
We are in the last three months of our 4-year effort to install Smart Grid technologies and systems. This was a huge project. SMUD is a $1.4 billion company and the Smart Grid had an overall budget of $360 million, so it impacted day-to-day work and activities across the company. We have about 2,100 employees and more than half of them contributed at least some time to the project. It really was a company-wide effort.
I am pleased to point out that SMUD did not raise customer rates because of Smart Grid. We developed a business case to ensure that benefits would exceed the cost and we leveraged federal funding and factored the deployment’s costs into our operation. There was no rate increase as a result of implementing our Smart Grid project.
Can you give us a summary of the many projects this involved?
The Smart Grid deployment projects cost $308 million and were supported in part by $128 million in grants from the American Recovery and Reinvestment Act. The projects were organized into seven project areas and involved more than 40 subprojects.
The project areas included $138 million for advanced metering infrastructure (AMI); $58 million for distribution automation technologies including SCADA and automated feeders; $58 million for customer applications projects, including upgraded energy management systems and demand response applications for six public agencies; $15 million for residential demand response programs; $22.6 million for technology infrastructure to facilitate interoperability between software systems and customer relationship management software; $13 million for smart pricing pilot studies; and $3.3 million for cybersecurity.
We’ve also conducted $52 million in research and development projects, which have been funded by SMUD and grants from ARRA and other agencies. The research focuses on renewables integration, energy storage, a microgrid demonstration, demand response, dairy digesters and strategies for managing electric vehicle loads, among other things.
Your deployment of AMI infrastructure and smart meters is comprehensive and already demonstrating its value. What were the AMI highlights, in your opinion?
Because of its $138 million in cost, the AMI project was the biggest component of the deployment. I also think it was one of the biggest success stories because we deployed AMI in nearly 100% of our service territory. Very few customers declined smart meters and opted out of the program. And now, because we have full implementation, we get fully automated meter reads and are really well-positioned to provide time-of-use rates to all of our residential customers in the coming years.
We’ve also gained immediate benefits. For example, we expected that the AMI connect/disconnect capability would enable us to reduce the number of truck rolls for provisioning customers but the success of this feature has been quite startling: we’ve actually avoided over 500,000 truck rolls since deploying the system.
We can detect when meters are off-line, which helps with tamper detection and outage notification. And the meters can be “pinged” to show when they are back online. These functions, when fully enabled, will help pinpoint where crews are needed and will reduce truck rolls as well as labor costs. And that’s a big deal. In time we will investigate using the system to automatically measure customer loads on specific transformers and use the voltage reads at individual meters to evaluate service conditions.
SMUD has just completed dynamic pricing pilot studies for the residential sector. Tell us about the studies and what you’ve learned.
For two summers now, under the smart pricing component of the Smart Grid project, we’ve had large samples of customers on a variety of rates. Some customers are on time-of-uses (TOU) rates, others are on TOU rates combined with critical peak pricing (TOU/CPP), and others are only on CPP. And we have two categories of customers on these rates: those we invited to participate and opt into the program and those we assigned to the rates by default with the option to opt out. We expected as much as a 50% refusal rate in the second category, but only about 10% refused. So we had really good participation, much better than we expected.
The interesting piece from my perspective was the CPP component. For these customers we established a 10:1 differential between off-peak and on-peak pricing, which is huge. The lowest off-peak rate was 7.2 cents/kWh and the CPP rate was 75 cents/kWh. The CPP rate was implemented no more than 12 times each summer.
We found that each group reduced their peak load by using these various rates. Overall, those on default TOU rates reduced their peak load by 6% and those with TOU/CPP saved 8%. People who opted in saved more than those who were put on the rate by default. Those that opted into the TOU program, for example, saved 10-13%.
The CPP rates had the highest impact. The 75 cents/kWh rate definitely drives behavior. Those who opted in to CPP reduced peak loads between 22% and 26%, roughly twice the reduction achieved by the default (opt-out) CPP group, which saved 12% to 13%.
How important are these findings to the industry, in your opinion?
We had good customer participation and the results are significant. I believe the findings are likely to impact other programs throughout the United States. Other utilities will be able to actually look at this study, appreciate that it was well conducted and provides good information, and better understand what will happen if they apply these rates and techniques in their service territories.
Do you have a strategy for implementing any of these rates?
Our current plan is to have full-scale rollout of TOU for all of our residential customers by 2018. I think for a while CPP will be optional. And we will continue pilot tests to learn more about these types of programs.
The introduction of system-wide TOU rates will be an accomplishment. I’m not aware of too many other utilities that have implemented it this extensively because you need to have the AMI in place.
Customer acceptance is key to AMI and new rate programs. What was your strategy for communicating with customers to gain their participation?
Our biggest communication effort was in the AMI program. Around the time we began implementing our smart meters there was substantial distrust of the technology in a neighboring utility’s service territory. We had already installed about 80,000 meters but we stopped our implementation midstream and conducted additional, extensive tests to ensure that our meters were accurate and that the network functioned properly, even in the most challenging AMI environments such as remote and really dense urban locations.
We also trained about 40 people to become public speakers and reach out to the community with information about smart meters and our project. They delivered presentations to elected officials and all types of groups, from local chambers of commerce to neighborhood associations to Rotary clubs. They explained what we were doing, why we were doing it, and what the benefits were to the community. It paid big dividends. The vast majority of our customers have indicated they were satisfied with the project.
For the dynamic rate studies, we randomly selected customers. We sent written materials to each individual to explain their specific rate and gave them the option to opt-in. Similar materials were sent to the default customers with the option to opt-out. We gave them a special customer support number to call and made sure that there were well-trained call center representatives and program managers available to address all potential questions and areas of concern. It worked out really well.
You have partnered with public agencies to install or upgrade building energy management systems. How has this work progressed?
As part of the customer applications projects, we partnered with six local agencies, including schools, colleges, the County of Sacramento and State of California offices. We worked with them to deploy or upgrade their energy management systems to monitor their energy use and help them reduce their peak loads. These customers are all implementing controls to enable automated demand response (AutoDR) in their facilities. Five of the six have completed AutoDR tests and verified their systems. The sixth agency will be complete by the end of this year.
We can see from results so far that the control strategies are delivering load reductions that are incredibly close to what we estimated. The load reduction performed just like we thought it would. Based on what we’ve learned, we have developed another ADR program for additional commercial customers and will be expanding that in the coming years.
What’s next for SMUD, now that its Smart Grid deployment is essentially completed?
After we finish up the projects, we will evaluate each of them and then determine the next steps. I expect that we will expand some projects, others will need more research and if some don’t give us the full benefits we had expected, we may put those on hold. I do see a lot of additional applications for AMI already. We are getting a lot of AMI-related data that we will be able to use to develop good programs for our customers and to enhance the reliability of our system. So there is still a lot of work to do. We are not at all at the end of our evolution to Smart Grid. In many ways it’s just beginning.
Jim Parks has dedicated much of his career to developing emerging energy efficiency technologies. In addition to his work on Smart Grid for SMUD, his efforts have focused on electric transportation technologies, energy efficiency program development, energy efficiency implementation and transmission planning.