National Grid’s Flexible Grid-Edge Assets: One Platform to Manage Them All

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Customer demand response (DR) — the ability of utilities to connect to customers’ electrical equipment and shed or shift electricity load in order to reduce undue grid strains and avoid outages– is playing an increasingly important part in creating a more reliable, efficient and cost-effective, as well as more environmentally benign, power grid. National Grid, for example, offers voluntary DR, also known as demand side response (DSR), programs to its larger customers in Massachusetts, New York and Rhode Island, compensating them to the degree their peak-period electricity demand is reduced or deferred when regional grid managers call upon wholesale market participants to do so.

An early crop of innovative distributed energy systems integration companies is among those playing a pivotal role at the forefront of this fundamental wave of change. Yesterday, National Grid and Redwood City, Calif.-based AutoGrid announced they’re engaged in the initial one-year phase of a three year-long initiative that aims to bring both business customer DSR and distributed energy resource (DER) capacity throughout National Grid’s service footprint under management of the AutoGrid Flex platform.

The project partners aim to consolidate remote monitoring, analysis and management of 400-MWs of DSR capacity in New York, Massachusetts and Rhode Island on AutoGrid Flex over the course of the next 36 months– 185-MWs of that this year.. That encompasses implementing unified systems management of five programs: the New York Emergency DR Program (EDRP), the New York Distribution Load Relief Program (DLRP), the New York Commercial System Relief Program (CSRP), the Massachusetts Connected Solutions Program, and the Rhode Island Connected Solutions Program.

Bringing Management of All Grid-Edge Assets Under One Roof

National Grid’s contract with AutoGrid is the latest illustration on the part of utilities to take advantage of the latest in digital power/energy and information-communications technology (ICT), developments taking place amidst a profusion of distributed energy resources and new smart grid infrastructure that convey automated remote monitoring and management capabilities for “behind the meter” grid assets located on customer sites, as well as across their own growing distributed renewable energy, energy storage and energy Internet of Things (IoT) networks.

Regional grid manager ISO New England began evaluating the use of DR management way back in 1999, well before regulators began permitting DR participation in U.S. power markets. In a landmark legal opinion, the US Supreme Court in late January 2016 paved the way for utilities and aggregators to offer DR resources in New England’s wholesale electricity market.


National Grid runs DSR programs for business and residential customers in Massachusetts, Rhode Island, and Upstate New York. In Massachusetts, participants receive up to $20 per kW enrolled and $0.75/kWh during “Peak Energy Events.” As the utility explains:

“This program is designed to reduce the demand on the electric system on the hottest summer days. The program is designed to call 20 hours of Peak Energy Events per summer. These events will be between the hours of 11am and 5pm, on weekdays. Peak Energy Events will never last more than 4 hours.”

Connecting to 400-MWs of Customer-Side Grid Assets

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Working with AutoGrid, the utility aims to consolidate monitoring, analysis and management of an initial 185-MWs of its business customer DSR capacity on the AutoGrid Flex platform in 2017 and 400-MWs over 36 months. That’s a large, complex and daunting task, but it’s more straightforward and less resource-intensive than some similar contracts AutoGrid has won to date in that others require the distributed energy systems integration specialist to reach out to utility customers and coax them into participating in DSR programs, director of strategic accounts Shane O’Quinn explained during an interview.

Though hesitant to deem it a “landmark” contract for AutoGrid, O’Quinn said:

“It’s certainly an important one. It’s particularly significant in that it gives us the opportunity to expand beyond the ‘pure’ demand response market space into the broader concept of comprehensive grid-edge flexibility management.”

A fast growing range of legacy electrical equipment commonly used in commercial and industrial facilities – boilers, HVAC and lighting systems, refrigeration units and emergency back-up diesel or gasoline generators– can serve as a utility DR asset given they are equipped with the wireless sensors, networking capacity and actuators required to monitor and manage their energy usage remotely. So can new or existing customer-side combined heat and power (CHP), solar PV and battery-based energy storage systems (BESS).

Looking out beyond phase one of the DSR project’s time horizon, National Grid and AutoGrid already are discussing plans to expand the initiative to incorporate the latter.The boundary distinguishing DR resources and DERs is a fine, if not at times unclear one. More substantively, the distinction is of minor import from a “big picture” systems integration perspective.

“Managing all DERs and programs from one unified, hardware-agnostic platform allows utilities to optimize large and varied portfolios of DERs and programs — DR, batteries, thermal storage, CHPs, EVs, BTM solar, etc. — in real time and at scale,” marketing director Elise Benoit explained.

Just what that entails with regard to AutoGrid’s current DR program systems integration work with National Grid, as well as the associated risks, rewards, challenges, benefits and opportunities, were among the issues O’Quinn and Benoit discussed during our interview that will be reported in part two of this post.

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