AutoGrid’s software will integrate 400 megawatts of C&I load in New York, small businesses
in Massachusetts, and non-wires alternatives in Rhode Island.
by Jeff St. John
May 10, 2017
AutoGrid,the startup that says its software can integrate, analyze and control lots of distributed
energy resources on the grid, has a new challenge — integrating three unique state programs
into a single interface.
That’s what National Grid, the utility serving more than 7 million customers across New York,
Massachusetts and Rhode Island, has hired it to do. Over the course of the next 12 months or so, the grid
analytics startup will implement its “flexibility management” software to manage about 400
megawatts of demand response — from old-school emergency commercial and industrial load
control, to aggregated DERs as alternatives to traditional grid investment.
AutoGrid was picked out of an initial list of 27 companies responding to National Grid’s RFP last
year, Fouad Dagher, National Grid’s manager of new products and services, said in an interview
this week. The company has already been working on integration with the utility’s existing
software systems in all three states, starting with capturing the data they’ve collected on the
hundreds of large transmission-connected and smaller commercial customers enrolled in
today’s programs, he said.
But National Grid is looking ahead to other challenges, such as integrating rooftop solar, plug-in electric
vehicles, and behind-the-meter batteries into its grid operations, Dagher said. “Can we duplicate
this, can we scale it, can we use it across different jurisdictions without using something new
every time? The ownership and sharing of the data we’re going to be sending back and forth is
very important to us. Can we scale it up to focus on additional technologies?”
National Grid is also looking for new opportunities outside traditional utility business models,
which will require different relationships with its customers. “How do we look at it from the
customer point of view, the information-sharing, the messaging that goes with it, the analytics
that goes with it?”
“From the AutoGrid perspective, this was very well aligned with our capabilities,” said Shane
O’Quinn, AutoGrid’s strategic accounts director.
The startup, which has raised about $40 million, has deployed its software for utilities including
Sacramento Municipal Utility District (SMUD), Oklahoma Gas & Electric, Austin Energy,
Florida Power & Light, and Hawaiian Electric.
The Bonneville Power Administration has been usingAutoGrid’s software since November 2014
to manage itsmulti-party demand response efforts. And Dutch energy company Eneco Group
is running a 100-megawatt virtual power plant, tapping customer-sited combined-heat-and-power systems
and industrial demand response, using the company’s platform.
With National Grid, “we’ve already gone through all the steps to identify the work involved,” said
O’Quinn. “This is a cutover of existing DR customers. It’s a lot more simple than going out and
getting new customers. The various aggregators in the market are already connected to the
assets with direct telemetry in many cases — we’re communicating to them through OpenADR
and other standard communications protocols to give National Grid a standard platform to
aggregate all these aggregators.”
Even so, “it does create a lot of challenges as well, making sure you have the proper integration
ties into the aggregators, and the National Grid systems that exist,” he said.
Once that’s complete, however, National Grid, aggregators, and customers have access to a
common store and source of data, along with a “platform that allows you to tap into that
flexibility for various use cases.”
AutoGrid’s software modules include demand response optimization, distributed energy
resource management, virtual power plants, and energy storage management systems,
integrated with the startup’s predictive controls engine — a network modeling software suite
that aims to predict, alter and optimize as many distributed energy resources as possible to
help meet the utility’s goals.
National Grid plans to implement five programs in the first year of operation. In New York, these
include the Emergency DR Program, the Distribution Load Relief Program, and the Commercial
System Relief Program. In Massachusetts and Rhode Island, the utility will use AutoGrid for its
Connected Solutions programs.
All told, the portfolio includes about 400 megawatts of utility-controllable load, mostly in
existing DR programs, Dagher said. But the utility is also seeking new commercial and industrial
customers, which enroll through demand response vendors such as EnerNOC, CPower, NRG,
IPKeys, and Direct Energy.
It’s also looking beyond current methods of managing demand response, particularly in Rhode
Island, where it’s testing a targeted demand response program as part of its non-wires
“We started our first demonstration non-wires alternative, where we try to leverage customer
DERs — both residential and small commercial — to see what we can do to reduce demand on a
couple of feeders,” said Dagher.
DERs as replacements for grid investments are being used in New York as well, under the
state’s Reforming the Energy Vision effort.
National Grid runs a demand response program in Massachusetts, mostly with smaller
commercial customers. It is using this customer base as part of a three-year demonstration
project, aimed at understanding the costs and benefits of utility investment into distributed