Demand Response Optimization and Optionality

by Ron Chebra, Utility-Subject Matter Experts

Historically, demand response (DR), demand-side management (DSM) or curtailment calls were made to help satisfy resource imbalances at control areas within a transmission or distribution system or in many cases to have the capacity to do so if needed.

Significant changes are occurring in the demand response marketplace.

“We are experiencing the demand response markets move from DR 1.0, primarily manual, to DR 2.0, an automated approach, and now starting to touch on DR 3.0, which utilizes demand response to optimize price signals, renewable fluctuations, distribution system issues and building management,” said Peter Weigand, CEO of Skipping Stone. “The optionality that demand response provides is finally becoming a core component of a wider variety of market participant strategies.”

Among the triggers that will unlock DR 3.0 will be advanced tools that include communication networks, sophisticated demand response management software and intelligent end devices, all of which will support modes where more granular control can be exercised. This suite of tools will enable far more choices for demand response by independent system operators (ISOs) and load-serving entities including distribution utilities and retail commodity marketers, as well as end-use customers.

These advanced tools will unlock new methods to optimize the way loads can be controlled beyond the traditional load control switch connected to a water heater or HVAC system. Key attributes that these tools and technologies will enable will target controls that can address issues on specific distribution networks, substations, feeders and even loads on overloaded secondary distribution transformers.

For an example of this need for greater granularity, one can look at the New York ISO where there are 11 ISO control zones labeled A thorough K (see Figure 1).

Zone J covers all of New York City; however, in New York City there are more than 50 area substations with more than 1,000 feeders. Exercising an event in Zone J has a wide-ranging impact. Issuing a single demand response event in Zone J might be effective to avoid constraints into that control zone; however, lowering the demand in such a wide area is equivalent to shining a floodlight when a spotlight or laser might be more appropriate.

Ross Malme, a partner at Skipping Stone, highlighted the impact of broad-reaching demand response.

“One of the biggest reasons for surgical demand response for reliability is the impact that a reliability call has on market prices,” Malme said. “Back in the early 2000s, the NYISO only had one way to call DR, which was essentially all of it or none of it. As a case in point, when the ISO had a need for just 100 megawatts of DR in the city, they had to call the entire zone, which was 1,500 megawatts. As a result, the NYISO solved the reliability problem but market prices, which were forecasted to be about $500 per megawatt-hour, fell to nearly $50 per megawatt-hour.

“The generators screamed ‘customer market power,’ and they were right. Soon afterward, the ISO obtained software that gave them the ability to call DR down to the substation level.”

There will be cases where a scramble in a large zone is essential to maintain system stability; however, as noted in the example, many cases exist in which localization of an event would achieve the desired goal without affecting all the loads in the zone. To isolate troubled subareas, the information of localized congestion must be known and understood, and the technology must be in place to segregate the control and must be effective.

With the proliferation of communications networks and intelligent end devices–many of which are at the roots of most smart grid projects–these assets can form a strong foundation of enablement. To leverage these investments, however, there must be an overall architecture and the use of a system-of-systems approach to realize the benefits of maintaining system stability with finer granularity.

These new enabling demand management methods include: conservation voltage reduction (CVR); volt/VAR optimization (VVO); scheduling and controlling demand and load at specific connection points through building and home automation systems; deploying and leveraging short- to medium-term storage devices at critical points in the network; making use of customer-operated or potentially utility-operated microgrids; leveraging intelligent power electronics in distribution transformers; and using renewable energy resources stabilized with storage.

The block diagram in Figure 2 shows how and where these options fit into the overall electric supply transmission and distribution network.

The new DR toolset now can include:

Bulk storage. The growing use of large-scale storage, such as as compressed air energy storage (CAES), pumped hydroelectric, and large-scale battery and flywheel installations, have a role to play in the supply side, especially as a means of offsetting intermittency of many renewable resources. “Energy Storage for the Electricity Grid: Benefits and Market Potential Assessment Guide,” a 2010 study by Sandia, identifies 17 applications of storage for grid benefits, including three categories for electric supply, ancillary services and grid system. The applications include: energy time-shift, supply capacity, load following, area regulation, supply reserve capacity, voltage support, transmission support, transmission congestion relief and T&D deferral. California AB 2514, which was finalized in late 2013, has set the stage for storage as a grid asset.

In the “Order Instituting Rulemaking Pursuant to Assembly Bill 2514 to Consider the Adoption of Procurement Targets for Viable and Cost-Effective Energy Storage Systems” issued Oct. 21, 2013, a summary chart (see Figure 3) highlights where the 1,325 MW of storage will be deployed by application and utility.

More than 50 percent of the storage procurement will be applied to transmission support, and more than 30 percent will support distribution.

Home automation. Innovations that integrate intelligent load management schemes within residential premises will grow as the migration from manual or fundamental actions move toward more holistic envelope treatment. For instance, the Nest thermostat learns the thermal inertia of a home and estimates how long it will take to get from one temperature to another set point. This information can be included into a more intelligent control scheme that optimizes the energy savings while reducing the comfort impact on occupants. Because this device also senses occupancy and automatically places the home into an away mode, more intelligent controls scenarios can consider any impact that commanding a device to shed load will have when it is already in a full set-back condition.

Renewable energy resources. Effective integration of renewable resources that are distributed throughout the network can help achieve localized congestion relief. Storage might be required to offset intermittency, but these localized resources might provide a relief valve in areas that have issues consistently or that happen on an exception or fault basis. Here is where timely telemetry and analytics will play a key role in maintaining a near real-time load forecast and connectivity model. In addition, the advances in monitoring, control, prediction and ramping will need to be orchestrated in concert with other grid assets to ensure this integration operates in a holistic, overarching system manner.

Smart transformers. The ability to incorporate hardened solid-state power electronics into the traditional distribution transformer might be at the epicenter of the next wave of grid modernization. By optimizing this local medium- to low-voltage transformation function, these units can help upstream balancing and power flow through innovative voltage/current and VAR management. These tools will provide capabilities such as series-connected voltage sources and shunt-connected current sources and bring support to demand-side areas such as voltage regulation, reactive power compensation, harmonic cancellation and power quality monitoring.

This is innovative, but the magnitude of possibilities are more significant when these assets can be coupled locally with peer-to-peer communications and uplinks to wide-area communication that enables control software to bring a new level of improved service point management. This is a domain that for many years has been served mostly by copper and iron while elements such as advanced metering infrastructure that are downstream and elements upstream, which are controlled by distribution automation, have grown in intelligence and greater general use.

CVR/VVO. With the deployment of advanced metering systems and infrastructures, the ability to measure and manage end-of-line feeder voltage and power quality has come of age. Load tap changers, voltage regulators and line compensation are realizing the benefit of closed-loop control with end-point measurements. More sophisticated algorithms, control logic and distribution management systems can more accurately meet minimum end-of-line voltage specifications with little or no impact on customers. Ohms’ law translates the ability of lowering the voltage to lower energy needs.

Community energy storage. As battery technology continues to improve in performance and lowering the total cost of ownership and operation, the growth of community-based storage units are making headway as valued assets in the low-voltage distribution network. A core feature of these elements is to bring greater resiliency and power quality improvement, especially in conditions where short-term peaks can be leveled with fast response discharge and charging over many operational cycles. Demand response with energy storage management (DR-ESM) is covered in detail in the May 2012 white paper “Optimal Demand Response with Energy Storage Management” by Longbo Huang, Jean Walrand, and Kannan Ramchandran.

Building EMS. Building energy management systems (BEMS) have grown in sophistication and grid awareness. New levels of effective building or campus resource management systems are moving toward providing resource relief to demand requirements. This is done in response to a load requirement rather than individually controlling load elements (e.g., the call and delivery would be for megawatts, not for quantities of individual chiller controls). The BEMS is in a more strategic control environment to balance internal load against supply capability, not only from a pure economic perspective for the building owner-operator, but also in collaboration with the serving distribution utility to ensure reliability.

Microgrids. After recent events such as Superstorm Sandy in the Northeast, hurricanes in the Southeast, ice storms and snowstorms and events of nature, there is a growing desire and requirement for greater resiliency, higher reliability and energy independence that can be achieved through self-generation and islanding. For example, Connecticut is in the second round of funding projects that support critical infrastructures. This round will provide $15 million in project grants. Despite discussions about the impact of microgrids on the larger community grid, more microgrids can offset localized energy needs of buildings, campuses and other facilities that have contributed to system load. In some cases, the design of these microgrids falls short of their total resource need, but these generation facilities can support critical operations that free up the metagrid to serve others.


Demand response has become a strategic asset with newer tools that can provide the reliability and stability of the electric grid. The convergence of intelligent end devices, command, control and communication systems are providing all participants the opportunity to exercise the most practical, economical options. The ability to be selective in control and the types of control that can be exercised will require intelligence, automation and the use of sophistication that will transform and secure the grid.

Whether these tools are stand-alone or are orchestrated as an ecosystem, these methods bring new options to the grid operator, distribution utility and end user to fulfill the need for demand response. With all of these potential options, however, considerations must be evaluated fully to include the economic efficacy from both the perspective of cost to install and operate the solution, as well as the economic impact of such execution on the utility. An assessment of the system impacts should include the extension of asset life by operating the equipment within the rated or normal range, as well as the possible stress and life-shortening impact on other assets that could result from more frequent exercise than the design limit. The cost-benefit analysis can become even more complex when market prices are affected.


Ron Chebra is a member of the ELP Executive Forum Advisory Committee and is the managing director of Utility-Subject Matter Experts, a management consultancy focused on helping utilities and suppliers to the industry understand emerging trends, strategies to leverage these and practical ways to achieve business value through innovation. Reach him at ron.

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