The Future of Demand Response: The Practitioner’s View

By Ed Thomas, PLMA

Until recently, demand response was mostly considered a stopgap measure to be used during a peak load event. Recently, however, utilities are beginning to see demand response as a tool to be used in system planning and operations, especially when it comes to integrating renewable energy.

Peak Load Management Alliance (PLMA) Board Chairman Paul Tyno with Buffalo Energy Advisors, PLMA Board Vice Chairman Rich Philip with Duke Energy, and Extensible Energy President and CEO John Powers participated in a PLMA Demand Response Dialogue in early August. They discussed demand response’s move into the mainstream and how utilities are incorporating demand response into their operating and business processes.

“Many in the demand response community feel this is a transformative time for demand response as we’ve known it,” Tyno said. “I look at the future of demand response in terms of dynamic load management and what a collective group of customer-based assets could do, including a robust demand response capability. What could those assets provide back to the grid in a market that compensates them for the capability? We’re at a very interesting point. I think of demand response as a 24/7, 365-day resource proactively used to manage versus an emergency-only resource of last resort.”

Rich Philip, PLMA Board Vice Chairman, Duke Energy

Duke Energy looks at demand response as a transmission distribution planning tool, Philip said. In some situations, localized demand response activities are being used to address implications from the changing generation mix coupled with transmission construction constraints that can result in overloaded circuits.

“We are considering how demand management might be able to make a difference for a lot more days of the year than just the three or four “emergency” days that used to be applied in the traditional generation planning context,” Philip said. “In one circumstance, we might be able to impact how many days certain lines may be exposed and, hopefully, reduce that risk from 50 days at 85 degrees, or warmer, to a lower contingency, something like 30 days at 88 degrees.”

Demand Response is Growing Up

“Demand response is becoming less of a safety net and moving in the direction of becoming a mainstream resource,” Tyno said

Philip added that he believes it may be a key building block for where energy utility system planning is going in the future.

“Just over the last several years, it’s pretty astounding to see how the cost and capabilities of new control systems have evolved. Ten years ago, the idea of behavioral demand response was a nice concept, but today it’s been made real by our automated metering infrastructure,” he said.

Paul Tyno, Peak Load Management Alliance Board Chairman, Buffalo Energy Advisors

The emergence of AMI technology deployments across the country will enable utilities like Duke Energy to explore a shorter-term type of demand response in a more succinct way. With that will come more robust evaluation into the customer experience to verify that their comfort is not impacted, Philip said.

As demand response becomes more automatic and can be activated based on certain thresholds like temperature, load and frequency levels, and does not require real-time human decision-making, the more utilities will consider it a deployable resource that operators will trust and use for planning purposes, he said.

Powers looks at things a little differently.

“As an economist, I take the valuation question a little more literally. There is a lot of work still to be done in some markets on how to value demand response,” Powers said.

In areas where demand response, especially fast-acting demand response, is beginning to play in ancillary services markets, its value is starting to be recognized, he said.

Some examples of utilities operating in jurisdictions where demand response programs are being monetized include Pacific Gas & Electric service areas and others in California, as well as Great River Energy in the Midwest. Great River Energy has initiated a program with grid-interactive water heaters. The program has shown a higher valuation than many other programs because the utility has been allowed to tap into the market for ancillary services, Powers said.

While customer satisfaction is essential to a successful demand response program, utilities also must find a way to pay for the program, he said.

DR and Renewable Energy

Renewable energy integration is also a driver in the future of demand response.

Although controls and monitoring technologies are improving and their costs are going down, more will be required to make demand response a viable tool for renewable energy integration, Powers said.

“It will take a combination of technology, program design and redesign of business models, in particular pricing and risk sharing,” he said. “The problems presented by renewables integration are really very different than those presented by peak shaving. We shouldn’t be surprised that the solutions need to be different as well.”

Tyno believes demand response is becoming less of a safety net and moving in the direction of becoming a mainstream resource. It has the potential to work much better than it’s working now, but that potential is not tapped by most programs today. For demand response to be an effective tool for renewable integration, it must reach its potential, he said.

“I go back to what the objectives of the programs were and what the objectives under renewable integration will become,” Powers said. “We all talk about demand response in terms of a few dimensions, right? It’s how responsive the load is in terms of latency from when the signal goes out to when it goes down and to the duration of the impact or the frequency of the impact. Is it one way or two-way? Can you actually increase load as well as decrease load? What about the size of the impact depending on time of day or whether there are other constraints? All those dimensions shift from an emergency program or peak shaving program into a renewables integration program. A utility can’t simply assume its demand-response tactics for peak shaving will fit the bill for a renewables integration problem.

“If we’re willing to embrace some changes in technology program redesign and pricing, then I think we can provide a mainstream operational response to renewables integration. If we’re just looking to say, ‘Let’s take our existing program and call it renewables integration,’ I think we’ll miss huge opportunities,” Powers said.

A Focus on the Customer

No matter how well planned or implemented, no demand response program will be successful unless customers buy into it. And, as customers become more educated, look for more sustainable energy options and even opt to become energy providers, utility demand response programs must evolve to be accepted.

If utilities take a customer-oriented perspective, things will start to move faster, Tyno said.

“Customers, especially on the C&I (commercial and industrial) side, are thinking in terms of optimization and taking more of a holistic view on how they want to interact or function with the grid,” Tyno said. “They’re looking for market signals to make investments. Those investments might be in co-generation, renewables, storage, energy efficiency, certainly demand response and demand-management capabilities. That’s how you animate the market, by sending the right price/investment signal down to the customer.”

Powers agreed.

“The increased penetration of renewables is having a bigger impact on the grid than most of us have acknowledged so far,” he said. “When you look at the prices of renewables and how rapidly they’re dropping, it takes some people by surprise.”

In the most recent solar procurements in Texas and Nevada, some power purchase agreements are coming in at four or five cents per kWh, Powers said.

“That changes things a lot; the signals we’re sending to customers are still that energy is expensive-but it’s not. Energy is cheap, reliability is expensive and once we get that into price signals that are going out to customers we will get a lot more responsive load from customers,” he said.

Powers cited community solar as an example. Distributed photovoltaic solar adds variability to the net system load and a well-matched set of demand response options has the potential to offset or remove some of that same variability.

John Powers, President and CEO, Extensible Energy

“Community solar presents a special opportunity for utilities. I tell people that rooftop solar is something that happens to utilities; community solar is something that utilities can help make happen,” he said.

A utility can implement strategic siting and put a solar plant somewhere on the grid where it will do the most good rather than the most harm. It also can coordinate the output from that solar plant around demand response customers with whom it has existing relationships.

Appealing to customers is an important part of the equation. Market research continues to suggest that most customers want more renewables and they know little about demand response despite utilities’ best efforts to educate them. Designing a demand-response program that can tap into the popularity of renewables can pay off, Powers said.

“We think that community solar presents a special opportunity for utilities that are trying to accelerate that shift towards demand response as a renewables integration strategy,” he said.

The way forward will be to align the benefits to both customers and utilities with automatically enabled energy management where demand response is a “behind the scenes activity” that happens in ways that are often invisible to customers, Philip said.

“I really do think that’s the way forward,” he said. “Paying incentives to people to do something that they would never dream of doing otherwise is how demand response ‘grew up.’ We are getting away from that.”

The markets should take that approach going forward, he said.


Ed Thomas has been executive director of Peak Load Management Alliance since 2013.

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