News Article
July 29, 2010

Demand Response Ruling by Federal Energy Regulatory Commission Spurs Debate

Demand Response Ruling by Federal Energy Regulatory Commission Spurs Debate

The importance and relevance of demand response (DR) to the advancement of efficient and cost-effective grid management is undisputed. Successful programs can lead to more competitive electricity markets, cheaper responses to emergency system overloads, more efficient incorporation of distributed energy, increased reliability of supply, and greater information flow between the utility, customer and load serving entity (LSE).  There is much debate, however, over the best mechanism to scale such programs.



 

FERC’s Efforts to Advance DR in the Wholesale Electricity Markets

The Federal Energy Regulatory Commission (FERC), an independent agency regulating the inter-state transmission of electricity, gas and oil, prioritized removing barriers to DR in response to the 2005 Energy Policy Act passed by Congress.  This initiative is part of an expanded effort to increase the efficiency of electricity markets.  In doing so, they have focused largely on organized power markets, approving DR as a capacity resource and allowing large buyers to bid into day-ahead and real-time energy markets.  In recent years, they have published national assessments and action plans on scaling DR beyond existing programs for industrial and residential customers. 



In October, 2008, FERC issued Order No. 719: “Wholesale Competition in Regions with Organized Electric Markets,”1 with subsequent updates in July and December, 2009.2  This ruling requires Independent System Operators and Regional Transmission Organizations, tasked with monitoring regional electricity supply and demand markets, to “permit an aggregator of retail customers (ARC) to bid demand response on behalf of retail customers directly into the organized energy market.”3  Aggregators typically serve to pool together DR within a large number of residential and small commercial entities, compensating them for load shed and either bidding into wholesale markets with cumulative load shed, or entering into direct contracts with utilities.  Aggregators serve as middle men between utilities and their customers, and are most prevalent within DR wholesale markets in which customers cannot directly participate.



 

Order No. 719: The Debate

This ruling has attracted significant attention due to its potential impacts on the development and structure of DR programs across the country.  Aside from existing Direct Load Control Programs, in which a utility directly controls load shed within predominantly residential facilities, and Interruptible Tarrifs, in which a utility enters into a contract with high-consumption industrial facilities to curtail load upon request, DR markets are still in the nascent phase of development. There are several potential models on the table, each allowing for varying levels of control, flexibility and incentives for participating customers.  FERC has reasoned that this ruling removes a significant barrier to DR advancement, but opponents to the ruling argue that FERC is overstepping its role and that the ruling may have unintended consequences. 



While the final outcome and impacts of this ruling are yet to be realized, it has spurred an important debate around how to structure and regulate DR programs to avoid burdensome management and oversight by the administrator, and overly complicated methods of participation. The level of implementation (regional, state or local), program administrator (ISO or utility), and incentives (real-time pricing versus direct compensation) are key issues surrounding the debate.



DR can be implemented at the retail level through direct utility incentives or real-time pricing, a system in which the retail prices fluctuate according to the wholesale market.  It can also be implemented at the wholesale level through direct bids into the regional wholesale market. When implemented at the retail level, it falls under the state’s jurisdiction, and when implemented at the wholesale level, it is regulated by FERC.  The key area of contention around the ruling is the potential jurisdictional conflict with existing public utility commissions (PUCs) that regulate state retail electricity markets.  



Permitting aggregators to bid into regional wholesale markets, according to some PUCs and utilities, may undermine existing demand side management programs, particularly at the retail level.4   They argue that demand response oversight should be conducted exclusively by the states, in order to avoid the establishment of parallel DR markets at the regional level that would directly conflict with state DR programs and regulations.



 

How Does This Impact Customers?

One of the broader questions is whether DR wholesale markets will preclude dynamic pricing programs.  Dynamic pricing scenarios, in which retail electricity rates fluctuate according to the true cost of wholesale generation, are largely seen as the most efficient solution from a market perspective for spurring DR participation at all levels.  Within this model, customers identify price points above which they will reduce their load, and respond to the rate fluctuations accordingly.  The market functions efficiently, and demand is dispersed more evenly throughout the day, reducing peak load burden on the utility. 



If DR programs are facilitated through wholesale electricity markets, on the other hand, customers may be more inclined to contract through an aggregator to bid on their behalf.  This is due to two factors: many wholesale markets have minimum capacity requirements for bidding; and customers, particularly residential and small commercial, may not have the time or capacity to participate on an individual basis. Critics of this model claim that it lacks transparency and places too much control in the hands of the aggregators.



While it is difficult to predict how FERC’s ruling will affect which DR models win out in the future, removing barriers to DR is a priority. With so many stakeholders, regionalized markets, and state-based regulations, it seems likely that utilities and ISOs will experiment with different models. Coordination among all stakeholders and sharing of best practices will be vital to scaling DR within the U.S.

 

July 2010

 

 

1 FERC, Docket Nos. RM07-19-000 and AD07-7-000 [http://www.ferc.gov/whats-new/comm-meet/2008/101608/E-1.pdf]

2 FERC, “Electrical Competition” [http://www.ferc.gov/industries/electric/indus-act/competition.asp]

3 FERC, Docket Nos. RM07-19-000 and AD07-7-000, p.3

4 Klotz, Jason Salmi. “FERC Policy on Demand Response and Order 719.” ,” Bonneville Power Administration [http://www.gridwiseac.org/pdfs/forum_papers09/klotz.pdf]

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