by Phil Davis, Schneider Electric
Utilities face a rapidly changing energy landscape. Stranded investments, aging systems and more active customer demands challenge the traditional business model. Many in the industry predict an orderly transition from command and control processes to an agile grid-a grid of diverse resources. To ensure reliable, consistent power delivery, the Department of Energy predicts utilities could spend nearly $2 trillion by 2030.
The agile grid, so termed by the Cooperative Research Network, contemplates the maturity of evolving trends: integrating renewable resources, right-sizing the grid through virtual power plants, and mining demand-side gold in the form of microgrids that can support resiliency needs. The capital investment emphasis is shifting from generation and transmission to distribution and integration. “Control center to customer” is where the action is or will be soon.
Customer engagement is the challenge. Most folks are fine with business as usual. Generally, the public doesn’t understand how changing energy and environmental policies soon will make that impossible. Utility integrated resource planners are scrambling to understand how to build a 20-year plan in a three-year world. Perhaps the granddaddy of customer engagement, demand response, has been the answer all along.
Dating from time-of-use rates and direct load control, demand response programs have been in play for decades. Participants have learned how their energy use produces positive and negative impacts. As a group, demand response enrollees have a clearer understanding of the complexities of grid management and a greater sympathy for inevitable changes. Even better, the savings with demand response can be significant: from 5 to 25 percent of annual energy costs.
Modern large-scale demand response developed in response to wholesale price volatility and congestion issues. Practitioners soon learned it could be useful in more localized grid issues, as well as a handy tool to avoid power restoration damage. More recently, demand response has demonstrated value in regulation and power factor applications. Demand response has become the Swiss Army knife of grid management, but that sells it short.
The U.S. has made great progress in energy efficiency. Energy demand is flat, despite a growing population. Unfortunately, these efficiency gains also decrease utility revenue, hobbling the industry’s efforts to provide service to expanding populations and to accommodate proliferating energy devices. Demand response offers every utility a strategy to take control and prosper if it understands demand response is the language of the smart grid.
Demand response isn’t fading away but evolving in response to new energy sources and customers expecting on-the-go access to information and control. Techniques learned in older programs have been applied at retail to avoid demand charges, defer capital investments, integrate renewable resources and redefine energy efficiency. Demand response is a new, bidirectional flow of information that rewards customers who use it to shape their demand profiles to match local grid conditions better.
Moving to a Smart Grid
With 5 percent of the world’s population and traditionally low-cost energy, the U.S. consumes some 20 percent the world’s energy output. This contributes to high gross domestic product growth but is not sustainable. As more economies develop, they also increase energy consumption. Unchecked, global growth in energy demand will lead to even more challenging global politics. The U.S. must take a leadership role in sustaining growth while developing a smart grid that exemplifies best practices for a sustainable energy future.
Demand response must evolve so that it enters the control room as a method of dispatching customer-side resources with the same reliability, verification and integration as traditional generation. That does not mean it should be managed the same way. It means moving to a model in which customers will be active participants in the minute details of energy supply and reliability. Because those customers are not utility employees and their demand response and local generation capabilities are not utility assets, the utility cannot manage them the same way. Whereas utilities use deterministic planning for traditional assets, they must grow more comfortable with probabilistic techniques on the demand side.
Next-generation Demand Response-Virtual Power Plants and Agile Grids
In the past, demand response referred to peak clipping actions that were confined to a limited number of hours per year. More recently, the term has evolved to describe a more consistent active energy management approach. Now demand response is synonymous with active demand management. Rather than being used only to mitigate emergencies, it allows consumers to respond to price and reliability conditions as they change even second by second.
As smart grid technologies blend traditional electric grid functions with a high-speed communication infrastructure and intelligent devices, active demand management is including more real-time automation capabilities. This allows energy management systems to communicate instantly with the utility or demand response broker through electronic signals. Demand response has entered a new reality through better metrics, better equipment, faster feedback and a mechanism for wide-area coordination provided by the smart grid. Now utilities must build on these new-era tools and customers.
Microgrid pilots are a helpful learning tool. They are microcosms of distribution grids, often using many of the same technologies and techniques. Early results show them to be key to resiliency and storm recovery as demand response practices serve to match generation and load. The industry’s smart grid interoperability panel also is making great strides in developing use cases and standards-based practices for integrating these “agile control districts” into the larger distribution grid. This isn’t new. The RTOs and ISOs have been doing this with distribution grids for some time; however, it is refined, scaled-down and involved nonindustry resources.
The utility of the future might become an aggregator and operator of many such agile control districts and transform them into virtual power plants by making future capital investments on the demand side. There are current regulatory dockets underway, notably in New York, that seek information on doing this.
One municipal utility, EPB in Chattanooga, Tennessee, has seen success with the implementation of smart grid innovations. Serving more than 172,000 homes and businesses across 600 square miles, EPB began constructing a smart grid in 2008 and is deploying smart grid applications to allow customers greater control of their electric power usage. The company is leveraging Schneider Electric’s Energy Profiler Online (EPO), a cloud-based energy management information system (EMIS), to take large volumes of customer usage data-near real-time usage, load and cost information-and turn it into actionable information for customers. Branded as EPB’s Business Power Tracker, the system provides customer data at 15-minute intervals and serves as a platform for customers to monitor and manage their energy usage.
Advanced metering nodes sample the grid thousands of times per second and upload detailed analysis to software systems when problems are detected. As a result, EPB can monitor potential power quality and reliability issues in near real time and provide that information to customers. This allows customers to make operational changes throughout the day or analyze the data over time.
For example, EPB customer Signal Mountain Cement is using the Business Power Tracker in conjunction with the utility’s Key Accounts Program to maximize energy efficiency without hiring an energy management consultant. Chattanooga has become a prime example of how a smart grid can be an economic engine for cities by reducing power outages, improving reliability, preparing for power demands and offering next-generation communications.
Other utilities are deploying advanced distribution management systems (ADMS) coupled with sophisticated standards-based feeder and substation automation. This makes possible the creation of virtual microgrids with greater agility to react to and manage grid conditions. An ADMS system can dispatch hundreds of thousands, even millions, of points and manage response metrics. System automation one day could manage demand shaping on local circuits to balance conditions and contain disruptions to minimize outages. Imagine a substation controller that uses Aunt Minnie’s water heater and dryer element to help balance cousin Joe’s solar panels, and you get the concept.
Demand response is far more advanced than it was in early demand response and from the tariffed programs of the mid-20th century. As demand response evolves, next-generation agile control district will provide more real-time automation capabilities and better communications. The technology exists now. It’s time to get the humans up to speed.
Phil Davis is senior manager of demand response solutions at Schneider Electric.
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