Testing how microgrids and distributed energy can integrate with grid operations—and get paid for the service
By Jeff St. John originally published: September 28, 2016
New York’s first real-world test of its vision of a platform to connect customer-owned energy assets to a marketplace for grid services has launched in Buffalo, N.Y.
On Tuesday, utility National Grid announced it’s working with startup Opus One Solutions to field-test a distributed system platform (DSP). That’s the term created by the state’s Reforming the Energy Vision initiative for the combination of technologies and business models it seeks to create for utilities and distributed energy resources to work together in future years.
New York REV has already spawned a host of demonstration projects featuring microgrids, community energy projects and third-party efficiency, demand response and virtual power plant rollouts. But this new project is the first to explicitly test a core idea of the state’s energy regulatory overhaul — how these distributed energy resources (DERs) can be compensated for the energy, capacity and resiliency they can provide in lieu of utility-owned assets.
That’s a tall order, akin to creating a miniature version of the independent system operator (ISO) markets for transmission grids. But unlike ISOs, which have to deal with perhaps thousands of individual nodes and market participants, these DSPs will have to eventually include millions of individual customers and the energy-generating and load-shifting technologies they’re deploying behind the utility meter.
National Grid’s new project isn’t nearly that complicated, of course. The $4.8 million, two-year effort will start with several buildings owned by the Buffalo Niagara Medical Campus, each with its own set of DERs and the ability to manage its energy use, and link them up with two to six distribution feeders serving the campus.
But in the long run, this relatively small scope is meant to demonstrate a set of connected technologies that could theoretically be expanded to the utility’s entire distribution network, from long-range planning to day-to-day operations.
“The whole idea is not only to deploy the technology, but to develop the new business models that create a win-win for the customer, for National Grid, and the system as a whole,” Keyvan Cohanim, chief commercial officer of Opus One, said in a Tuesday interview at Greentech Media’s New York REV Future conference in Brooklyn.
Opus One’s contribution to the project is its GridOS software, which provides real-time, two-way power flow modeling of distribution circuits without the need for sensors, he said. The Ontario-based startup has already deployed several microgrids in Canada. Last week it was picked for a larger-scale project aimed at linking three separate microgrids to serve their local distribution grids, much as it’s doing with National Grid.
That starts with assessing the distribution circuits serving the hospital and university complex, and measuring the value that on-site solar, generators, and flexible loads can provide in easing those constraints, Joshua Wong, Opus One’s CEO, said on Tuesday.
What National Grid is looking for from the campus-based DERs participating in the project are “volts, VARs, line losses, capital deferral programs, maintenance and opex reduction resiliency — these are some of the distribution-based benefits,” he said. It’s a fairly comprehensive list of utilities’ needs for its distribution grids, which have always been managed internally in the past.
The project will be modeling these factors under both “blue-sky,” business-as-usual operating conditions, and scenarios of circuit constraints, such as during peak loads or in the midst of grid disruptions, Carlos Nouel, National Grid’s new energy solutions leader, noted.
“The DSP is basically working with a set of POCs, or points of control,” he said — the term it’s using for each individual grouping of buildings and their resident DERs and load controls. “By learning how to optimize the distribution system and leverage existing assets, and moving a lot of that to the edge of the grid on the customer side…if we bring them all into the DSP platform, we don’t have to make that capital investment.”
Turning to outside parties to supply these critical utility needs isn’t something that will be accepted without a lot of testing, he noted. “This program will allow us and Opus One and everyone in the community to test that out,” he said.
As for how to compensate DERs for these services, NY REV has created the term “LMP+D,” which combines the locational marginal price of energy at the nearest node of the transmission network, plus the “D” value of all these distribution grid needs.
That’s a hard calculation to come up with, starting with collecting the data on the interrelation of the grid and the DERs it’s seeking to bring into play, and then creating commonly accepted terms for how that should be translated into real money terms.
The biggest REV projects to date, such as Consolidated Edison’s Brooklyn Queens Demand Management project, have used contracts and auctions to secure DERs to meet a relatively simpler set of needs. But the state’s utilities are under pressure to at least indicate a path forward to delivering a “value of D” under their distributed system implementation plans, which are now under review at the state Public Service Commission.
Setting up the technology and business models to allow DSPs is part of these plans, but many steps remain to make them a reality. Such major changes are likely to take a decade to implement, and the end results are far from clear.
But early-stage projects like the one National Grid and Opus One have launched will be important proving grounds, first to show whether the technology involved can scale to meet the vision, and second, to show how the financial tradeoffs between utilities and their DER-equipped customers can be engineered.
As Wong said, “This is the first project within the REV framework that’s looking to do something all of us at this conference are trying to do. How do you unlock the value of distributed resources, and then use those values to optimize the distribution system? It’s a challenge, because it’s not something that utilities and the market are used to.”