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Technology Makes Demand Response a Viable Asset Option

Issue 8 and Volume 110.

Steve Blankinship, Associate Editor

When electricity supply is short, reducing electric usage and utilizing distributed generation on short notice is a solution that is gaining more and more market acceptance. This ability is often termed demand response and is increasingly seen as a dependable resource akin to new peaking generation capacity. Demand response that either reduces load on a moment’s notice, adds generating capacity on an emergency basis or does both, isn’t a new idea. But up until recently, communication and remote control technologies were not up to the task of maximizing its potential.

Today’s remote monitoring, command and control communication technologies are making demand response a valuable capacity addition to individual utilities and to regional grid operators. With its recent acquisition of Seattle, Wash.-based Celerity Energy, Boston-based EnerNOC has more than 1,000 MW of electrical capacity, including more than 300 MW of proven demand response resources, under its management. In essence, of the 1,000 MW of electrical demand that EnerNOC manages, it can reduce demand by 300 MW within minutes of notification. EnerNOC provides additional technology-enabled energy management services to help customers better manage all 1,000 MW of their demand. This includes such measures as identifying better building management system control set points, opportunities to install variable frequency drives and changes to procurement strategies or utility tariffs.

Gregg Dixon, vice president of marketing and sales for EnerNOC (which stands for Energy Network Operations Center), says the company is now able to bring demand response to any utility or grid operator who values it as a capacity resource. “We’re working with a number of vertically integrated utilities now to develop a totally outsourced demand response program that lets them avoid transmission, distribution, and generation investments,” he says.


EnerNOC’s control center is staffed continuously. Photo courtesy of EnerNOC.
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The company is working in regulated and deregulated markets in New England, New York, California, the Midwest, the South, and in foreign markets including Canada and Australia. “We believe demand response stacks up very well – and even outperforms – simply adding peaking resources in integrated resource plans (IRPs),” says Dixon. “Demand response should be a part of the long-term IRP, representing a minimum of 5% of peak load.” He says it’s also a viable stopgap measure in high load growth areas like China.

EnerNOC aggregates customers who wish to participate in a demand response program in conjunction with a vertically integrated utility, independent system operator (ISO) or regional transmission authority (RTO). Customers can either choose to shed load when requested – thus lowering demand – or make their on-site generating capacity available to the grid – adding capacity. The technology used is relatively simple. It consists of a real-time metering and control device and real-time communications equipment, installed at a customer site. EnerNOC couples the device with application software that allows them to “see” customer assets and coordinate with grid operators both customer curtailments and the dispatch of customer-owned capacity.

What makes EnerNOC’s demand response program so attractive is the transparency the system provides to the system operator. “The output of a utility gas-fired peaker is directly controlled from an ISO or utility control room,” he explains. “You can see if it’s on or off, its exact production, frequency, voltage and so forth. Demand response with EnerNOC provides that guaranteed level of performance as well. There have been lots of demand response programs over the years but typically, they haven’t measured performance well when compared with more traditional resources, like peaker plants. And if you don’t measure it well you’ll have a hard time managing it and knowing you can really count on it.”

When ISO New England calls for any or all of the 200 MW EnerNOC has under management in New England, ISO operators can see all of it in real time, rather than relying on data that might be days or weeks old and collected via interval meters. Real-time metering and control is provided via broadband network wireless, over a customer’s LAN or by other means, and fed to EnerNOC’s operations center. There, EnerNOC’s system integrates with the grid operator’s rules and protocol, creating a market for the demand response resource. “Data for ISO New England and each of the markets where we work comes into us where it is filtered according to each markets’market’s rules. Our ‘DNA’, or device-network-application architecture, has a set of rules that comply with any market or conform to any utility’s requirements for their demand response program and tailored to their specific system needs.”

Requests to turn off demand or turn on capacity come through EnerNOC. The system operator declares a shortage event by sending an encoded e-mail, activating EnerNOC’s network operations center. When EnerNOC receives notification from an ISO or utility, a proprietary technology platform starts the automated communication process. This system places thousands of calls to individual customers. Detailed e-mails are sent as well that contain specific instructions, again to whomever the customer designates. “In cases where we remotely control customer assets, we inform them by a phone call and e-mail within minutes, and within the designated time frame of the event – a 30 minute response is typical in New England – we take operational control over the Internet. We can turn it on and off and measure it in real time,” Dixon says. New York and California need the resources within two hours.

EnerNOC seeks to aggregate large commercial and industrial customers, typically with a demand of 400 kW and above. These customers typically already have interval meters installed by the utility and therefore are rarely able to communicate in real time.

The message to utilities and regional system operators is that maximizing all existing demand response resources would represent a massive amount of potential value for a typical region. In recent testimony before the Connecticut legislature, Dixon stated that, assuming a utility or regional operator presently has no demand response in its control area, adding it would equal adding between 5 and 10 percent of the peak load capacity, depending on the region. “If you haven’t fully developed your demand response resources, you need to do that first before you invest in new T&D and generation,” he says.

The logic is simple, he says, because for less than one percent of the hours in the year, peak demand in many control areas is typically 15 percent higher than at any other time. “That means there’s 15 percent more capital on the ground needed to deliver less than 1 percent of the kWh. It’s an asset utilization issue. You’ve got all this capital sitting on the ground that only runs 50 hours a year. So why would you go build more of it if demand response can provide the same level of performance in a more environmentally friendly way? It’s a lot faster and more economical.” Dixon says demand response serves both the shareholders and customers. “Shareholders love it because it avoids capital investment and regulators love it because it avoids rate increases.”

Celerity made its mark in California by selling its services to regulated utilities, whereas EnerNOC started in New England working directly with the ISO to provide aggregated curtailment and back-up generators as a capacity resource. In a small number of cases, EnerNOC has installed backup generators for a customer when then takes a long-term lease. EnerNOC takes 100 percent of the market revenue derived from grid use, while the customer gets the value of the backup generator. “We can do all kinds of creative things, but, by and large, we work with existing assets,” says Dixon.

Curtailment represents about 40 percent of the company’s demand response resources while generation is about 60 percent. “The greenest kWh is the one never used,” says Dixon. Eighty percent of the generators under the company’s management are small gas-fired units, but most of the output consists of large diesel-fired engines. “We use the diesels as a last line of defense,” says Dixon. “When we do, it’s considered for emergency purposes only. And our value proposition for diesels isn’t that we run them only when the lights go out. Instead, we run a portion of the installed base in order to prevent 100% of them from running if the grid fails. These resources prevent a blackout, rather than allowing one to happen resulting in the entire fleet of diesels being fired up.”

He also notes that an Environmental Protection Agency study conducted by Synapse Energy Economics shows that even when 100 percent of the demand response comes from diesel backup generators,generators; the system has lower emissions than running in traditional utility mode where many central generation plants operate as spinning reserve.