Technology + Data

Innovations on the Other Side of the Meter


New businesses models are redefining how technology is being used to control and manage energy on both sides of the meter. Part of that redefinition is the role technology is playing in creating value and profit for utilities and alternative suppliers. From traditional energy services to data analytics, Stem’s director of business development, Matt Owens, recently shared his insights into how utilities can collaborate with third-party marketers to offer the most value to a variety of customer segments.

Q. What is your past experience and your organization’s approach to energy, the grid and interacting with customers?

I’ve worked in the energy industry for over 20 years. My first job was at PG&E. I’ve worked at startups and most recently was at Itron for 11 years doing product management and product marketing around smart grid solutions and demand response. Recently, I joined Stem, an intelligent energy storage solutions provider.

I first was introduced to energy storage when I was at PG&E, which has the Helms pump storage facility. Storage has come a long way since then. It can now be deployed in a smaller, more-distributed fashion, and at a lower cost. What Stem does is deliver energy storage solutions to commercial and industrial customers that provide cost-saving benefits. When aggregated, our fleet of storage systems can be used as a firm, dispatchable demand resource to utilities.

For customers, storage is a straightforward, cost-savings offer. The customer doesn’t have to do anything – the battery clips their peaks and reduces overall demand, and customers save 10-to-25 percent or more of their total bill on a monthly basis. Stem also provides cloud-based, predictive software, which is accessible from computers and mobile phones. This data is different than a typical smart meter because instead of getting the data the next day, they get their data in real time at the second level. We also offer a lease program, so it can be deployed with no money upfront and start delivering savings on the first day.

The current regulatory model needs to be enhanced. The existing, asset-based, rate of return model can stay in place, but there are some new performance metrics that can be added to enable the utility to make money on new services.

We have hundreds of storage devices in California and Hawaii. Southern California Edison put out an all-source RFO after the closing of its nuclear power plant; and we were selected to deliver 85 MW of storage capacity in the Los Angeles basin over next few years.

We are also taking our storage systems from six customer sites and aggregating them together, 100 KW in total, and bidding that capacity into the CAISO wholesale market.

Q: There’s been a lot of talk and variation about the value of the grid. What is the value of the grid to your company?

The utility needs to be compensated for the grid services it provides customers; and customers need to be fully compensated based on what they deliver back to the grid. There has been a lot of discussion about net energy metering. I think it is flawed and is a byproduct from when there weren’t time-of-use meters that could measure energy flows at different times of day. I think there ought to be some reforms toward more cost-based pricing for energy flows in both directions. There should be a demand charge, fixed charge and energy component for all rates for all customers. It will be challenging for some customer classes because they’re used to a flat rate. But look at telecoms, airlines and others, which have dynamic pricing. Customers are more used to dynamic pricing than ever before. It puts utilities in a difficult place when they’re delivering energy during peak demand and not getting full compensation for it.

Today energy storage doesn’t get compensated for everything it can deliver back to the grid. For example, there are limited markets for frequency regulation. Power plants can ramp up or ramp down quickly to match that frequency. The challenge is that all these renewables are coming online, they don’t deliver that frequency regulation and they’re more variable. Power plants have to work harder to regulate that voltage. Batteries are a great solution, but until there is more market availability for frequency regulation services, they can’t be fully valued.

T&D asset deferral is another place where batteries can help. For example, the Public Service Commission in Brooklyn and Queens looked at a $1 billion proposal upgrade to a substation. They told the utility to look at energy efficiency, demand response and energy storage. They received approval for $200 million to do a non-wires alternative to the substation, and deferred the capital cost of $1 billion by five years.

Q: Transmission and distribution assets and those wires are the best ways for utilities to get recovery-based rates. What do we have to do to change the regulatory paradigm?

The current regulatory model needs to be enhanced. The existing, asset-based, rate of return model can stay in place, but there are some new performance metrics that can be added to enable the utility to make money on new services. Examples include offering information to third parties and letting them know where in the system there are constraints and where growth is happening. The third party can then offer services to customers in those areas that will benefit both the customer and the grid.

Intelligent Energy Storage System at the Holiday Inn in San Francisco’s Civic Center.

Q: With the use of personal battery storage, have you been able to offset the need to increase capacity? What level of participation would you need before we see changes being made to the wires?

For energy storage, it’s still too early. Our units range in size from 18 kW to 400 kW. In Hawaii, where there are fuel oil power plants and 40 percent solar, it’s hard for the utility to manage the solar output because it’s variable, so they’re looking into our grid services and energy storage solutions. If they can use storage, then they can avoid operating their peak generating facilities for those short periods.

Q: We didn’t move quickly for solar because it didn’t make economic sense. Now it’s EVs and storage. Is the electric utility industry going to make the same mistake on storage as it did with solar so it won’t be a player at the table?

We see positive signs on the piloting and exploration of storage by electric utilities around the country. There are utilities depowering coal stations and putting in solar, natural gas and batteries at those locations.

Behind the meter will be the trickier challenge. Storage is a threat to utilities in that it’s reducing customer demand charges, which reduces utility revenue. But it requires a new regulatory model where utilities can earn money based on enabling third party solutions, such as storage. SDG&E proposed a “bring your own battery” tariff, rewarding having a battery in the grid if they could control it. We’re in favor of that concept.

The interconnection process has been a challenge. But we’re streamlining that. The price of batteries has come down 70 percent in the last 12-15 months, and it keeps coming down. Utilities need to think ahead two to three years and consider what the economics are if the price reduces further. The details are being sorted out, but all signs point to distributed storage resulting in meaningful benefits to customers, utilities and the grid.

This conversation is an except from an executive panel forum moderated by Michael Beehler, vice president of Burns & McDonnell, at the 2015 WEI Annual Meeting.

About the Author

Deston Nokes, Western Energy magazine
Deston Nokes is WE’s copy editor is an independent consultant for Western Energy Institute, Peak Reliability and Northwest Power and Conservation Council. He also works as a business and website copywriter for a variety of firms. He can be reached at