The DER pivot: Grid Edge Forum illustrates utility shift toward a distributed grid
Momentum is gathering behind a utility sector turn to distributed energy resources, conference attendees said.
There is a reason attendance at the Grid Edge World Forum 2016, a leading distributed energy resource (DER) convention, doubled from 2015 to 2016, prompting organizers to move it to a conference center next year.
A fundamental transition is underway in the utility system, GTM Research Grid Edge Director Steve Propper told the audience. Increasingly, the old grid model one-way power flows from centralized generation to the customer is being supplanted by a more distributed energy system, where consumers produce and store their own energy, as well as manage their usage.
“The utility industry is not new to change but today we are at a fundamental shift,” Grid Edge Director Steve Propper said on the opening day. “The entire electric system architecture is changing and we are redefining the future.”
The grid edge — the intersection of the utility distribution system and consumer usage — provides new opportunities for a variety of stakeholders. For consumers, it’s a place where they can enhance their electric reliability, lower their costs and help serve grid needs. And for utilities, the grid edge offers the opportunity to avoid massive system investments, strengthen consumer relationships and create a more sustainable grid.
“This change means very different things to different stakeholders,” Propper said. “For utilities, much depends on their business model.”
Change is not new to the utility industry, Propper said. It has been evolving for the last 40 years.
In the 1970s, the industry responded to the energy crises. In the 1980s, it saw demand side management and time of use prices emerge and changed in response.
In the 1990s, wholesale markets opened, utilities began to diversify their portfolios, and energy service companies started to flourish, Propper went on.
But after the California energy crisis in the early 2000s and a great deal of volatility in energy markets, a number of states halted deregulation activities. More recently, utilities have been responding to new resources, advanced meter rollouts, and business model reforms.
While those changes were all significant, today’s emerging DER markets are not simply more of the same.
“In the world before distributed energy, generation went through utility distribution systems to customers,” Propper said. Advanced metering and deregulated markets did not change the architecture.
“After distributed energy, consumers in smart homes and smart buildings and with electric vehicles have become suppliers,” Propper said. “They have to be integrated into the grid with intelligent switches and other utility equipment that has to be understood, deployed, secured, verified, and measured.”
Utilities are working to be “the navigators of the new resources,” he said.
“It is requiring them to look at new nodes, new intelligent devices, and they are seeing the new architecture emerge,” he said. “It is also the changing flows of energy supply and demand.”
These are changes that utilities like Florida Power & Light and Duke Energy see clearly, even if they largely characterize them in terms of reliability, rather than sustainability or consumer choice, Propper said.
“There probably aren’t utilities that don’t understand that DER are coming and causing this shift in grid architecture,” he explained. “But they still have their other master, regulatory and policy constructs. Without incentives to go toward the innovation, the safe place to go is toward advocating for safety and reliability.”
Reliability is the "gotcha," said Michael Edmonds, U.S. business division president at S&C Electric Company. “A company called Blackberry had a four-day outage and we changed to iPhones. As the grid moves to a platform to enable services, if the platform is not there, nothing else matters.”
Utilities move toward DERs
To Florida Power & Light, the transition to a more distributed grid means the ability to improve reliability and keep its rates among the U.S.’s lowest.
“We have deployed almost 40,000 intelligent devices, smart switches and relays and that has improved our platform and given us more visibility,” FPL Smart Grid & Innovation Director Dave Herlong told a conference audience. “With the changes we have made, our system is 40% more reliable.”
The public power utility of the Village of Minster, Ohio, seized the grid edge opportunity in a very different way, according to Edmonds.
S&C Electric provides electric services for a 7 MW battery energy storage system to compliment Minster’s 3 MWac solar array. It is likely the first U.S. public power solar-plus-storage installation, Village of Minster Administrator Donald Harrod recently told Utility Dive.
The storage system was only financially viable because of using its position at the grid edge to stack three services for the utility, Edmonds said. By contracting to provide frequency regulation to PJM, shifting solar generation to get more value from the array, and also doing power corrections for the local grid, the economics work for Minster.
“A stacked value chain is key,” Edmonds said.
For Duke Energy, the transition to a distributed grid “starts with maintaining the safety and reliability of the system.” Vice President of Grid Solutions Lee Mazzocchi said. “We have to make sure we have the right standards in place. We have to invest in the right infrastructure for the technical integration of DER.”
If some say utilities are slowing progress at the grid edge, that is a fair assessment, he said.
“We cannot afford to take risks that would threaten [the grid],” he said. “Think of what is at stake. My phone drops calls several times a week. We can’t tolerate a poorly performing electric system.”
But, he added, “not acknowledging what is coming is just as negligent.”
Last year, Commonwealth Edison began a push to secure approval from the Illinois legislature for its own grid edge projects — notably a group of six public purpose microgrids at strategic infrastructure locations.
Using DERs for reliability as opposed to using DER for a wider array of services is not a conflict of purposes, said Shay Bahramirad, Director of Distribution System Planning and Smart Grid Technology for the Chicago utility.
“They are complimentary,” she said. “We see value in both.”
California’s regulators are also working to put the pieces together.
Matthew Tisdale, a staff assistant to PUC Commissioner Mike Florio, said he agreed reliability is important, but said there are other priorities that must be addressed as well.
“The quest to deal with climate change is both a moral imperative and good business so we are creating a regulatory framework that works for utilities, customers, climate goals, and DER providers,” he said.
Customers are a crucial addition to the list of stakeholders, Propper, a former Pacific Gas and Electric executive, told Utility Dive.
“Technology has pushed these stakeholders toward this grid edge where all the innovation is happening. Innovation usually leads,” he said. “But now customers are starting to push toward the edge.”
The investment community seems convinced, he added. “Investment is once again rising in the DER sector. It went from $483 million in H1 2015 to $577 in H1 2016,” Propper said during his presentation. “The new emphasis is on customer energy management and about giving customers, every customer class, from large industrial customers to residential customers, the ability to become more proactive.”
The business model pivots
There are three key areas where utility business models are starting to pivot toward innovation, Propper said.
First, value is shifting from “rates of return” on capital toward new performance-based and network-driven incentive models and “the idea of the utility as a platform that delivers services.”
Second, additional products and services from retailers and third-parties are challenging utilities to look beyond kWh sales and create new value streams.
“It is possible to place a premium on reliability or offer products and services associated with making renewables or DER more accessible,” Propper said.
Third, and most exciting, he said, utilities and energy providers can now derive revenues in ways other than selling electricity. This is being clarified in ongoing regulatory and policy discussions, such as the REV docket in New York and similar proceedings in California.
“Where this will wind up in three years is going to be very important,” he said.
Technology advances are giving customers more power and choice. The huge growth in
Advanced Metering Infrastructure (AMI) deployment between 2013 and 2016 is giving utilities more data, more analytics, and more potential to engage customers, Propper said.
Smart thermostats, networked appliances, and other products and services are going beyond the information from AMI to understand customer usage, grid performance, and opportunities to "upsell" products and services. The industry, he said, “is moving not only from a decentralized architecture to a decentralized world of devices that provide information about electricity usage.”
Technology is also speeding market adoption of new concepts like micro-grids by making them viable. And it is leading to “a wholesale-customer nexus,” Propper said.
Grid operators are increasingly offering customers and DER aggregators the ability to engage directly in their markets in ways that were traditionally only available to larger customers, he explained. “That will have implications for the utility business model and for the value of DER in the future electric system.”
The key question: value
New business models that will support these changes are emerging in regulatory and policy proceedings, Propper said. The California commission is leading the way, closely followed by New York.
“The value of DER is one of the most important questions still to be answered,” Propper noted.
Energy, capacity and, to some extent, ancillary services have long been the measures of the value of traditional generation. DER adds value streams in risk mitigation opportunities, grid services, preventing transmission and distribution losses, and providing societal benefits, he said. “This is moving to the value of locational and performance-based services to the grid by DER.”
In California’s Distribution Resource Planning proceeding, utilities are required to be able to show how they value DER in their general rate cases, the CPUC’s Tisdale said. In the Integrated Distributed Energy Resources proceeding, stakeholders are modernizing planning "to value DER by where they are, when they produce, and how reliable they are."
Among new business models being considered is a proposal to compensate utilities for expenses incurred procuring DER to offset the need for traditional infrastructure, Tisdale added. This would be similar to the return utilities would earn for building new infrastructure.
Discussions about creating a risk free rate return for utilities have been “surprisingly prickly” because utilities are sensitive about the subject, Tisdale said. “But we will keep talking about it. This is about incremental steps to get around the corner to DER. We think of this process as walk, then jog, then run. It can be frustrating to private sector providers but we will get to the run eventually and we will get there together.”