Dan Fuller, Director of Strategic Planning discusses Demand Response in the November issue of IEEE Smart Grid Newsletter

November 17, 2017 / Media, News & Updates

By: Dan Fuller

The markets for power grid reliability are relatively constrained and inflexible across the North American control areas. While the causes are diverse, the impacts are similar: limiting broad participation of demand response resources and access to the efficiency they offer as assets of reliable power at minimum cost.

Over the past decade, integration of intermittent renewable generation and, more generally, distributed generation resources have posed new reliability challenges to transmission and distribution grid operators of the North American power grid. Further, loading factors (average/peak power consumption) have been decreasing across most major regional power markets, implying higher capital and asset maintenance costs per unit of power consumed.

The low-cost solution to these challenges may be demand response, which also offers potential for significant capital and operating expenditure savings. Integration of low cost computing and communications technologies offers the technical potential for its automated realization. However, to ensure broader participation of demand response in wholesale power markets requires transparent, near-real-time pricing.

What is Demand Response?

Demand response is any dynamic action taken to make a temporary change in load as a response to a market signal. Market signals may include the price of electrical energy, transmission, distribution, or reliability. Currently, the vast majority of responsive power demand is sold and bought on the reliability market –approximately 30 GW across North American markets (around 10 GW in the area of control of PJM). Considered in aggregate, this amount of capacity would rank amongst the top 10 North American power generation companies. Individually, these responsive loads might be a large industrial furnace, a commercial HVAC system, or a residential water heater.

Features differentiating demand response from generation assets reveal a few roles in which this resource is favorable.

  1. First Response. The cost of demand response starts at zero (or possibly less) for the first marginal megawatt and exhibits a positive correlation with the required capacity size (vs. generation resources’ inverse relationship). This implies that it should be the first resource called to handle marginal energy, transmission, distribution, or reliability concerns.
  2. Rapid Response. The marginal cost of sub-minute response from automated demand response resources is much lower than that from thermal generation assets (requiring consumption of fuel as “spinning” reserves to enable rapid ramping) or for electricity storage resources (i.e. chemical battery or pumped storage capital costs).
  3. Short-duration. While the cost of demand response from many load resources begins at zero, it also relates to the opportunity cost of whatever activity the “interrupted” electricity supply is powering. At 10 seconds of interruption, many processes experience no practical cost, whereas at 10 hours, the cost to the consumer may be great.

In summary, demand response represents the least cost, rapid, short duration resource for meeting the transmission, distribution, and reliability needs of interconnected North American grid. Integration of additional demand response resources also offers the potential for broader system benefits in reduced capital, operating, and financing costs.

The solutions to broader engagement of demand response resources are techno-economic in nature. While low-cost computing and communications technologies enable the potential for wide-scale use of this asset, on the same time, transparent, near-real time prices are required to incentivize its deployment. In this respect, most electrical wholesale power markets are essentially backward looking; this is because they design programs “that encourage the right investment in the right infrastructure, in the right places, and at the right times…”, rather than thinking beyond infrastructure to engage behavior of demand, so as to balance the physical constraints of supply.

As the largest wholesale power market in the world, PJM offers a good example of this phenomenon. More demand response participates in PJM market for reliability (“Capacity”) than any other single market. However, despite the advantages of demand response over generation for reliability, it has provided only between one and five percent of the energy in this market, during the past five years. Generation resources have been providing the remainder. This discrepancy can primarily be attributed to market design favoring (generation) asset-based solutions through conditions such as:

  1. Significant collateral requirements for participation in the three-year advance capacity (reliability) market auction, which advantages providers with large balance sheets (to finance collateral) and long-dated/amortizing assets (for planning purposes).
  2. Annual “standby” capacity price provides predictability, but consumes all of the economic value – preventing lowest cost capacity from offering in on a shorter term (day ahead/hourly basis) and being compensated for providing support when most needed.
  3. Reliability – The PJM reliability pricing model (“RPM”) construct weighs more the long-term predictability versus any short-term flexibility and does not seem to recognize that demand response resources are just as – if not more – reliable than generating assets (as historical experience demonstrates). While generator outages in PJM last peaked during the Polar Vortex in early 2014 at 22%, PJM demand response assets in the same performance year performed with just a 6% effective outage rate.

While many markets with scarcity pricing have experienced significant efficiency gains through technology-enabled price discovery over past decades (airline tickets, concert tickets, vacation rentals, car services, etc.), North American power markets have mostly resisted this trend. Current markets for electricity transmission, distribution, and reliability are centrally controlled, highly constrained, and relatively inflexible across North American regional grids. This generally limits the participation of demand response resources and access to the benefits they offer for reliable power at minimum cost. Through integration of automation there may now exist the potential to invigorate liquid markets with continuous, transparent pricing for standard transmission, distribution, and reliability products.

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