Managing the Energy Internet

Written By: Stratton Report
October 20, 2016

An interview with Judy Ko of AutoGrid Systems

On October 6, AutoGrid Systems, announced that MCE, a community choice electricity provider servicing about 250,000 customers throughout the Bay Area, is utilizing the AutoGrid Flex™ flexibility management software application suite for its pilot demand response program. Stratton Report, which is very interested in the issue of how the grid is evolving to include demand-response programs and other aggregated distributed energy resources (DERs), took the opportunity to speak with Judy Ko, Vice President of Marketing at AutoGrid about her company’s latest projects and how it sees the future of distribution systems playing out.

Stratton Report: Can you tell us a bit about AutoGrid?

Judy Ko: AutoGrid is a software provider focused on Energy Internet applications. The “Energy Internet” is the term we use to describe the way the energy distribution system is evolving as the volume of intermittent renewables and customer-owned distributed energy resources continues to grow. Our software helps the system to manage periods of high demand and to balance the grid. As the distribution system moves further away from a model based on centrally dispatched generation, the grid has become much more dynamic and unpredictable; and managing it has turned into a big data problem. We have built a set of applications that primarily focus on dynamic grid management, utilizing demand response and other distributed energy resources as flexible capacity to balance energy supply and demand, and enable new service offerings and new revenue streams.

SR: Who are your customers?

JK: We sell our software to utilities and energy service providers in both regulated and as well as deregulated markets. As of now, we’ve got about thirty major customers, primarily in North America and in Europe. We are expanding into Asia and the Pacific Rim region as well.

SR: How would you describe your value proposition?

JK: Our software is very efficient at managing distributed resources, whether the resource is a demand response program or an aggregation of multiple demand response programs, or whether it is a single DER or a group of DERs aggregated to establish a virtual power plant. Utilities and power suppliers who are dealing with those situations find our products quite useful in enhancing reliability, enabling new revenue streams and improving customer engagement. In fact, some think flexibility management is the Energy Internet’s “killer app”.

SR: I understand your software was recently chosen by MCE in Northern California. Who are they and how are they utilizing your system?

JK: MCE is a non-profit community choice aggregator. They contract with their own generation sources to deliver cleaner, sustainable energy. Their default service option is based on fifty-fifty mix of renewable power and conventionally generated power. And they have another option which is a one hundred percent renewable power which costs a little bit more. They use PG&E for the transmission, the distribution and the metering. We are working with MCE on a market-based demand response pilot program. It went live in May in time for the summer peak season here in northern California. It is a pilot program, designed to see what kind of energy procurement expense reductions they could get from the customers who are participating. By lowering their energy procurement expenses, they could then pass on energy bill savings to their customers if they choose to expand the program.

SR: How does MCE deliver their energy savings?

JK: By remotely controlling customers’ key energy assets, for example, by dialing down the temperature of their water heaters or dialing up their thermostats. Our software’s role is to look for the real time market signals from the California ISO, and when the wholesale power price creeps up above a certain threshold, which indicates that demand is outstripping low-cost sources of supply, we signal for those customer assets to be turned down. Or, in the case of the customer’s air conditioning, we signal to turn the thermometer setting up. The same for pool pumps and water heaters; we adjust their controls to lower their energy usage during the peak period which usually lasts a few hours.

SR: What is MCE hoping to accomplish with this program?

JK: At the moment they are still studying the results, what worked and what didn’t, with the goal of figuring out how to broaden the program. They want to enlarge it, both in terms of numbers of customers involved, and by expanding it to also control customer-owned solar power, energy storage and electric vehicle chargers.

SR: Did MCE customers have to have their energy assets modified to permit the remote control?

JK: Volunteers were given smart thermostats, and remote load control switches were placed on pool pumps, water heaters, etc.

SR: Was the program strictly voluntary? Could people drop out at any time?

JK: Absolutely.

SR: What are some of the other applications AutoGrid is involved with?

JK: We have quite a range, some of which are fairly modest in size like this pilot program while other customers use our software to deal with a hundred megawatts of load, or more. One of our larger programs is in Europe, in the Netherlands, where they have a very high penetration of intermittent wind power from offshore wind farms, out in the North Sea. Sometimes the wind blows fiercely, and sometimes not at all. To help balance their grid, we aggregated a bunch of farmers.

SR: Farmers?

JK: A lot of agriculture in the Netherlands is done in green houses and the green houses have large combined-heat-and-power (CHP) units in them. Obviously, the farmers need to keep the crop within a certain temperature range but that can fluctuate a few degrees. So, they have actually aggregated the CHP units into a virtual power plant. Our software is controlling those aggregated CHP units so they respond to market signals from the local grid. The grid signals come every four seconds and our software controls how much energy is generated by the CHPs, largely to balance the impacts of the intermittent offshore wind. The aggregated CHP units can amount to a several dozen megawatts of balancing capacity. That is an example of the Energy Internet I mentioned earlier; these are customer owned CHP units being used to balance the grid, not utility-owned assets. The farmers make money out of this because they’re selling energy back into the wholesale market and are getting paid for their balancing services.

SR: Can you give us an example closer to home?

JK: BPA is a customer of ours and they are a large wholesale provider. They use our software to work with several demand response aggregators. BPA provides power to over a hundred and forty utilities and other energy service providers and they use aggregators to manage multiple demand response programs across the region. Given the size of their power commitments, BPA needs to see something like 70- or 80-MWs of load shed from those demand-response programs. We’re also working with them to integrate additional DERs as well into their system.

SR: What kind of DERs do you work with?

JK: As I mentioned in connection with the MCE pilot, we have a lot of experience working with direct load control on things like water heaters and pool pumps and thermostats. We are expanding now into smarter DERs, like solar inverters. And we’re doing some early, early work on energy storage which is a rapidly emerging focus area. Energy storage is becoming quite the hot topic.

SR: How does your system match the dynamic conditions of the grid with all the various capabilities and limitations of those DERs?

JK: At the heart of our software, if you dig deep into the guts of it, there’s big data analytics and machine learning in there. And a lot of algorithms. We only focus on the energy sector, and we’ve got a deep understanding of the physics of assets and the network, as well as of energy customer behavior. We have optimization algorithms that can optimize on multiple objectives at the same time. So, if you take an energy storage example, we might be looking at a battery serving as a local grid-balancing asset as well as being used to reduce customer demand charges—at the same time. When we talk about developing a “monetization strategy” for a DER, it often it means that your system needs to simultaneously address different rate structures and rebates. So our systems need to do co-optimization, where we actually optimize across multiple different business objectives. It’s not that hard to produce an optimal result if you are only trying to handle one issue at a time. But we’ve incorporated a lot of data science in our software, because in handling the Energy Internet the problem will not involve just handling only one objective. A number of different goals will need to be optimized at the same time.

SR: Does your company monitor some of the initiatives around the country that are trying to push the grid in the direction you call the Energy Internet? For example, do you pay attention to what is happening in New York with their REV program?

JK: We definitely keep an eye on New York, and our CEO is quite active in some of the industry discussions. We focus on a couple key organizations. For example, we’re pretty active in the OpenADR group because we do need to have open standards around controlling load. We’ve got folks on the board of the PLMA. We are also involved in the California ISO demand response auction program, the DRAM.

SR: Do you think you’re gonna see a whole lot more of more wide-spread demand response activity among utilities and distribution grids?

JK: Yeah, we think so. It will be influenced, of course, by the regulatory environment. And we see more and more jurisdictions starting to encourage demand response. But, we think that’s just one part of the larger trend toward the Energy Internet. It’s very early days right now, and certainly concentrated in certain regions of the country, but we think that in the long term, customers everywhere will become not just consumers but suppliers and storers of energy, and utilities and other service providers are going to have to figure out programs that will be able to service them. It will be about designing the pricing and control programs that make sense both for customers and for the grid.