by Andrew Burger
May 12, 2017
Leading utilities are scaling up investment in and deployment of customer-side demand response (DR) and distributed energy resources (DER) systems and technology amidst a broad-based drive to minimize emissions and environmental impacts while at the same time enhancing grid reliability, efficiency and resiliency. They’re also looking to the latest generation of digital DR, DER and flexible, grid-edge information-communications technology (ICT) in a bid to identify and develop new, sustainable business opportunities.
As reported in part one of this two-part series, National Grid is working with AutoGrid, a distributed energy systems integration and management specialist based in Redwood City, Calif., to consolidate management of an initial 185-MWs of DR program resources in three states on the AutoGrid Flex platform in 12 months; and a total 400-MWs over 36.
Here in part two we continue our discussion with AutoGrid director of strategic accounts Shane O’Quinn and marketing director Elise Benoit in order to gain further insight into National Grid’s ambitious DR, DER and “non-wire alternatives” grid systems consolidation plans, including the risks, challenges, benefits and opportunities it presents.
One Systems Platform to Manage Them All
Totaling 400-MWs over three years, the AutoGrid-National Grid project team intends to consolidate management of 185-MWs across a diverse range of customer-side grid resources spanning five demand side response (DSR) programs in Massachusetts, Rhode Island and New York this year. It’s an ambitious project schedule, but one that could substantially boost both project partners’ existing operations, products and services offerings and open up significant new business opportunities.
Neither National Grid nor AutoGrid are divulging the financial terms and conditions of the deal, which is in keeping with the general practice of keeping a lid on financial information germane to what amounts to a leading, if not cutting, edge power and energy industry tech project investment. That said, AutoGrid’s work with National Grid paves the way for the privately held company to fully realize its strategic vision of building a systems platform capable of linking to and managing flexible, grid-edge resources of every shape and size, O’Quinn explained.
Describing phase one of AutoGrid’s three-year contract with National Grid specifically: “The contract we won initially covers DR customers throughout National Grid’s services footprint — in New York, as well as in Massachusetts and Rhode Island. It’s a first step towards expanding the project’s scope to also include DERs – and prospectively all ‘non-wires alternatives’ on one shared platform,” O’Quinn said during a telephone interview.
In addition to equipping legacy power and energy equipment commonly found at commercial and industrial customer sites with network-enabled wireless sensors, this can include combined heat and power (CHP) units, stationary lithium-ion battery and solar PV systems, as well as new thermal energy storage solutions, such as Ice Energy’s Ice Bear technology.
“Our solution is designed to be equipment and technology agnostic. As long as it can be controlled via open protocols, we can integrate and manage it via the Flex platform,” O’Quinn said.
Flexibility in Managing Flexible, “Non-Wires” Grid Resources
Generally speaking, AutoGrid Flex customers are using the distributed, grid-edge systems management platform in either of two modes, he continued: to create and operate virtual power plants (VPPs) that draw on the aggregate capacity of “behind the meter” distributed energy resources and secondly, to consolidate management of a fleet of DERMs.
It’s not the first time AutoGrid has worked with a power utility to consolidate both DSR and DERMs management on a single platform, but it is the first instance in the context of incorporating all “non-wires alternatives” as defined in New York State’s strategic NY-REV (Reforming the Energy Vision) grid modernization plan, O’Quinn highlighted.
Initial results regarding utility DR, DER and smart grid roll outs being announced by utilities on the whole have been positive and encouraging, but it’s still early days.
Security ranks at or near the top of the list of concerns. ICT networks, as well as grid infrastructure, can and do fail, and DR and DER assets open up avenues to launch grid cyber attacks from customer computing and communications systems. In sum, wholesale reliance on grid energy Internet of Things networks could expose many as yet unknown vulnerabilities and open up power grids to a potentially vast, fluid vista of cyber threats.
Utilities, their commercial and industrial customers and DR and DERMs technology developer are addressing the cyber security challenge individually and jointly. They’re looking to leverage the strengths inherent to distributed computing and energy infrastructure to counter them and employ the latest “state of the art” cyber security products and services on the market. There’s also collaboration to develop customized solutions that can address the myriad cyber threats and vulnerabilities that come with creation of an industrial and energy Internet of Things.
Risks, Challenges and Anticipated Returns
O’Quinn discussed some of the other key challenges associated with AutoGrid’s work with National Grid and other utilities. “One of the main challenges with regard to commercial-industrial DR is that you don’t know how much load is going to be shed during peak energy events. AutoGrid Flex resolves the issue by making use of a machine-learning algorithm that’s able to accurately predict bot the size and timing of DR event notifications,” he explained.
In addition, National Grid employs third-party DR aggregators/services providers in running its DR programs. Known as Curtailment Services Providers, CPower, EnerNOC and IPKeys offer DR services on behalf of National Grid in Massachusetts, for example.
Typically, AutoGrid hasn’t had to work with third-party DR service provider-aggregators when carrying out utility DR systems integration and consolidation projects. Doing so on National Grid’s behalf increases the number of parties involved, but it also streamlines the project as doing so reduces the extent and degree to which the project team has to identify, define, assess and link in downstream DR network applications and other software, O’Quinn explained.
On balance, the prospective financial and organizational resources savings and returns on investment (ROI) conveyed by DR and DER systems automation and integration initiatives such as National Grid’s could be huge, and they extend to encompass broader-based social and environmental impacts. Included among the latter are the prospective and actual impacts on utilities’ employment, hiring and training practices.
The degree and extent of DRM and DERMS’ overall impacts won’t begin to be revealed until they pass through one complete calendar-year operating cycle at minimum, however; and they’ll only come to be recognized and valued more fully over the course of the 20-year time horizon utilities typically employ in making and assessing capital expenditure decisions for core grid assets. That said, the trend towards power and energy digitization, decentralization and “decarbonization” is well under way, and consolidation of DR, DERMs and other flexible, grid-edge energy resources is emerging as key, next step as utilities advance along that pathway.