As energy storage becomes more ubiquitous and projects grow in size and capacity, utilities of all types are exploring the best ways of putting it to use across the grid. The opportunities are large, but so are the challenges, according to a panel of executives who spoke at Energy Storage North America in October.
New York utility Consolidated Edison (ConEd) runs one of the densest grids in North America, serving several million customers in and around New York City. Its heavily urban service territory experiences its greatest demand in the evening, particularly in more residential areas of the city, often peaking around 10 p.m.
This presents a challenge for ConEd, explained Damian Sciano, its director of distributed resource integration, because the state is in the midst of a major push to expand renewable generation. This past August, the New York Public Service Commission officially adopted the state’s Clean Energy Standard (CES), which requires utilities to procure 50% of their electricity from clean energy sources by 2030.
Solar will be a big part of it, and there’s already a fair amount of solar on ConEd’s grid. But, Sciano said, “When you look at these residential networks, they’re all ramping up at 9 o’clock at night. Solar alone is not going to help you.”
How to continue meeting evening demand while simultaneously meeting the requirements of the CES? Storage is going to play a part of it, he said.
“If I’ve got storage deployed appropriately across [ConEd’s] 62 different networks in 19 different regions, I’ve got a tremendously powerful tool. It helps me not just with the intermittency of the renewable resources that we’re seeing, but it also helps me address capital needs on my system.”
Deferring T&D Investments
Sciano spoke at the Energy Storage North America conference in San Diego on October 5 as part of a panel of utility executives discussing how energy storage resources are playing a larger role in utility planning (Figure 1). Ever-greater amounts of solar photovoltaic (PV) generation coming on to the grid is part of the challenge, but storage has capabilities beyond addressing that.
One example is ConEd’s Brooklyn Queens Demand Management Program. The Richmond Hill, Ridgewood, and Crown Heights neighborhoods of New York City in north Brooklyn and southwest Queens are facing increasing congestion from growing demand. The subtransmission feeders that supply this network will soon be overloaded, and the traditional solution would be building a new substation, something that would cost upwards of $1 billion.
Instead, ConEd took a different route, Sciano explained. The utility opted for a mix of utility-sited and nontraditional customer-sited demand management, including battery storage. About 41 MW will be customer-sited with another 11 MW on the utility side. Services will be provided by a range of vendors including Stem, EnerNOC, Innoventive Power, Direct Energy, Power Efficiency, Demand Energy Networks, Energy Spectrum, and Tarsier, who all submitted successful bids to ConEd’s auction this past summer.
“So we can defer a $1 billion substation and the transformers and subtransmission lines that need to go there for 10 years,” Sciano said, “if we can get 52 MW of some kind of non-wired alternative in those three networks.”
The total cost is projected to be about half that of a new substation. ConEd is currently installing a 12-MWh lithium-ion battery system in Howard Beach, with operations planned for 2017.
Dealing with Peak Demand
San Diego Gas & Electric (SDG&E) is facing issues similar to ConEd’s, as customers in its service area continue adding rooftop solar at a breakneck pace. That’s been the case for years, but it took on special significance after the massive gas leak from the Aliso Canyon storage facility this year. Loss of that gas storage put major constraints on the area’s gas-fired generation, and that means that peaker facilities might not be available when they’re needed.
After Gov. Jerry Brown declared a state of emergency over the leak, the California Public Utilities Commission (CPUC) in May told the state’s utilities to expedite plans for meeting their obligations under the agency’s energy storage mandate. Josh Gerber, SDG&E’s manager of advanced technology integration, explained that the utility had already been evaluating storage options, and after the CPUC request, it opted to move up two of its planned projects.
In June, SDG&E ordered two large battery systems from AES Energy Storage through an expedited procurement process. “Contract negotiations that would normally take three to 12 months, we wrapped up in three weeks working 16-, 18-, or 20-hour days,” Gerber said.
The 30-MW, 120-MWh system in Escondido and the 7.5-MW, 30-MWh system in El Cajon are slated for operations in January 2017. That’s an impressively fast deployment: The utility published its request for bids on May 26, the CPUC approved the projects on August 18, and construction began on September 15.
Leveraging Multiple Technologies
Until recently, most of the large-scale activity in energy storage was in North America, but that changed in a big way in August when UK grid operator National Grid (parent company of the U.S. utility) contracted for 201 MW of storage projects for enhanced frequency response. The eight projects range from 10 MW to 49 MW and will collectively cost£66 million (about $85 million). All of that is a big jump for a nation whose largest battery system is only 6 MW.
Matthew Sachs, vice president of distributed energy development for National Grid, noted that the company has been active in energy storage for a while, and not just in the UK. “In addition to the frequency regulation project, we’ve had smaller demonstration-style projects with the REV initiative [New York’s Reforming Energy Vision program], and in Massachusetts and Rhode Island. We view energy storage as a very interesting option considering the impact of rising peak demand.”
Sachs said he sees integration of multiple technologies in distributed energy as one of the most significant trends in the power sector. “Solar has its advantages, but it is not dispatchable. Using energy storage to complement it is the best example. There are other technologies that will work well together.” This will be especially important as “energy as a service” and “infrastructure as a service” approaches gain traction over the next decade, he said.
National Grid’s new UK projects are projected to come online starting in April 2017, with frequency regulation services being supplied in four-year contracts.
No Cookie Cutters
How does a utility decide how to move forward with a project, whether it’s in-house or third party? The answer, not surprisingly, depends on the local market.
Sciano expressed a preference for utility-owned resources. “Consumers are already putting it in on their own,” he said. “We want to be aware of it and we don’t want to duplicate that dispatch. But the other reality is that utilities are the ultimate backstop for the system. We are in charge of the reliability, nothing lets us off the hook for the reliability. I’m trying not to make this sound too bad, but we like the control of ownership. It fits our rate-based model. It fits our control of operations. It means that we know those assets will be there.”
Gerber, by contrast, pointed out that SDG&E has a number of competing concerns—starting with the CPUC mandate—that don’t give it much luxury of picking and choosing. “In terms of procurement, it’s not just storage for storage’s sake. We’d rather meet that target.”
In addition, SDG&E had to scramble to replace lost capacity from the San Onofre Nuclear Generating Station, which retired unexpectedly a few years ago. The utility needs an array of options, and it has to make decisions based on what’s cost-effective.
“Energy storage, whether utility-owned or third-party-owned, has to compete on a net market value basis with every other resource,” Gerber said. But falling prices for storage have changed the calculus. “What we’re seeing now is that storage is competitive,” he continued. “Cost curves that we anticipated two to four years ago as being 2020 kinds of prices, they are happening now. That means that our forecasts for 2025 are going to be hit sooner than we expected. So, we’re seeing some successful projects on the distribution and reliability side, but again, we have to show that they are cost-effective when they are compared to a traditional resource.” ■
—Thomas W. Overton, JD is a POWER associate editor.