For more than 100 years, electrical generation, transmission and distribution have been built to meet expected expansion in customer demand. However, this historical pattern is changing. Due to more efficient use of energy and conservation, load growth is decreasing or flatlining, and peak periods are shifting, due to societal behavioral changes (e.g., dual income households) and the emergence of distributed energy resources (DER). To adjust to the changing times, multiple industry efforts are underway, including grid modernization to make better use of technology and communication systems, to upgrade infrastructure to enable DER, to increase reliability and resilience, and to improve power quality. Demand Response (DR) is a component of these initiatives, with the intent of interacting with customers to adjust their energy usage in the never-ending challenge to balance electricity supply and demand.

DR dispatches essentially request that customers deviate from their normal electricity usage pattern. This can range from a minor or even unnoticeable inconvenience, such as automatically or manually dimming lights and adjusting thermostat set points, to more substantial changes, such as deferring an industrial process. For example, I previously worked for Boeing Space Systems, engineering carbon fiber Delta rocket components. We had a large electric autoclave and were enrolled in an interruptible DR program. The interruptible program would incur a penalty if electricity demand was not curtailed down to a specified baseline during a DR event. Sometimes we could simply run the autoclave during the night shift when a DR event was called during the day. Other times, the delay would cost more than the DR program penalty, and we had to proceed with business as usual.

Demand response dispatch has essentially two catalysts: reliability and economic (or market) forces. DR has been utilized as a reliability resource for decades (e.g., overfrequency load shed) with programs like direct load control and interruptible load, as illustrated in the autoclave example. These programs were developed to respond and mitigate system conditions (such as capacity constraints) that could result in an outage. The intent of reliability DR is to minimize impacts to the broader base of customers through the incentivized DR actions of participating customers.

However, these programs offered little feedback on resource performance, and grid operators were typically appreciative of any load relief to mitigate system interruption. The more recent economic and market approach to DR was catalyzed by the Federal Energy Regulatory Commission (FERC) Orders 719 (Wholesale Competition in Regions With Organized Electric Markets, 2008) and 745 (Demand Response Compensation in Organized Wholesale Energy Markets, 2011). Subsequently, wholesale electricity markets – both independent system operators (ISOs) and regional transmission organizations (RTOs) – have been working for years to integrate DR resources as competitive alternatives to generation resources. Typically, market dispatch is triggered by market prices, or in some instances, contingency or reliability conditions.

More recently, the industry has been exploring a market approach, with a distribution system operator (DSO) utilizing DER non-wires alternatives (NWA), including DR, through competitive solicitation to compare overall costs and grid services with traditional distribution approaches like reconductoring to increase capacity.

The idea behind FERC Orders 719 and 745 is that electricity is a commodity. Commodity markets work when demand for the commodity varies according to the supply cost. For example, if corn has a bumper crop which results in increasing supply, the prices drop and the cost of ethanol, corn syrup, livestock feed and corn for dinner decreases. Fundamentally, the need for DR relates to the fact that electricity demand today is inelastic. The price of electricity consumption is known to be relatively constant by customers, and electricity use is not influenced by the real-time cost of supply (generation) unless there is real-time pricing (RTP). Even with RTP, customers’ desire to alter usage is limited. Typically, the price to customers does not vary with the cost of supply (although DR pricing tariffs like time of use [TOU] pricing align with “peak” demand, and critical peak pricing [CPP] align with the highest annual peak demand). In fact, customers have no visibility into their usage or cost until the bill arrives (although Smart Meter Texas and some other programs are exceptions).

Grid modernization initiatives are expanding sensing and control capabilities within the distribution system. These capabilities provide more awareness of grid conditions and visibility into how distributed generation variability can alter voltage along a distribution feeder when the distributed generation and electricity demand on that feeder are not balanced. In fact, the need for grid modernization is in part prompted by the increasing adoption and proliferation of DER. Variable output from distributed generation like solar, combined with changing electricity demand, results in an even more challenging task for a utility, ISO or RTO to balance electricity supply and demand in real-time. Fortunately, DR provides an opportunity to adjust demand to align with supply, making DR a potentially significant component in an evolving portfolio of DER including advanced inverters, energy storage and secondary VAR controllers.

To meet the needs of this more complex and variable balancing act between electricity supply and demand, DR must be able to achieve the following:

• Flexibility to respond quickly with the ability to either curtail or increase demand
   
• Precision with predictable and accurate performance, because imprecise DR that doesn’t respond as expected necessitates that other resources adjust to compensate
   
• Cost competitiveness to provide an alternative to generation when supply cost is high
   

Achieving all three criteria is not a trivial pursuit. For example, the challenge of precision is compounded by imprecise measurement and verification through DR baselines. Multiple studies have been performed on the inadequacy of DR baselines, and more studies have noted that the baselines are also insufficient for battery energy storage.

To develop successful DR programs, the business need and context for the DR resources must be understood. Developing DR to be a viable alternative to generation resources and competitive with other NWA resources depends on the investment required to enable DR program participation by customers. The economic overlay of ISO and RTO locational marginal pricing (LMP) can help determine the economic viability of DR investment, and the NWA solicitations provide insight into required capabilities and price competitiveness. DR program implementation and administration costs, as well as customer compensation for providing DR, can determine the bid price for DR resources in the ISO and RTO markets and proposals for DR as an NWA. However, the total of these DR costs may or may not result in a competitive resource compared to central generation, energy storage and other NWA.