A Regulatory Construct for Demand Response

According to year-end 2011 findings published by the Federal Energy Regulatory Commission (FERC), in the United States the aggregate impact of demand response (DR) is estimated at 58 GW, or 7.6 percent, of the peak demand—up 42 percent from two years ago. FERC views the potential for further cost-effective DR to reach as much as 20 percent of the system peak.

Moreover, regardless of the form of DR that a utility might seek to pursue, the reasons for doing so are fairly consistent: there is consensus in the electric industry that DR can create both system and societal benefits by reducing the need for traditional generation sources. In fact, EPA restrictions on traditional power supplies and the onerous challenges of siting new power plants in most U.S. locations have collectively called into question the future viability of nuclear, coal, and renewable sources. The alternative of DR has become increasingly attractive to utilities when DR gains equal footing in among other integrated resource planning options. The decision to participate in a DR program, however, is driven primarily by economics—or, put more simply, when benefits of the DR program are greater than the costs.

Addressing regulatory barriers and limitations.
One of the primary obstacles for DR is the set of regulatory limitations created at both the federal and state levels. We would argue that the potential contributions that DR can make to the nation’s energy portfolio have been severely constricted by a number of regulatory barriers that continue to impede the growth of DR in the state (retail) market. The end result of these regulatory dynamics is that, despite the extensive documentation supporting the benefits of DR, the vast majority of utilities across the United States do not have what could be called robust DR program offerings available to their customers. Furthermore, they have not designed long-term resource portfolios in which demand-side resources have equal or comparable footing with more traditional resources. The reasons for this lack of growth in the DR market can be directly linked to regulatory barriers, which can originate from specific market rules or the unique features of a market or program design, as well as from the retail or wholesale levels.

Six regulatory barriers have the greatest negative impact on DR programs:

  1. Deployment of smart meters is not commonplace across utility populations—at least not yet.
  2. Dynamic pricing structures that enable DR programs are not generally in place across the United States.
  3. The traditional regulatory framework does not lend itself to DR investments by the nation’s utilities.
  4. There is a disconnect between electricity retail markets and wholesale markets, which has created regulatory limitations for utilities pursuing DR.
  5. DR still does not generally have “equal footing” along with traditional supply-side generation sources within the context of utility integrated resource planning.
  6. The uncertainty of how to treat and measure DR, both on the state and federal levels, has contributed to stagnated growth of this market.

Every utility pursuing DR should consider certain regulatory strategies as it navigates through the unique requirements of its own state PUC jurisdiction:

  • Seek to get any disincentive associated with DR removed from the state legislative and regulatory policies. The most common approach to this is to decouple revenues and profits from the amount of electricity sold.
  • Seek to have a decoupling mechanism established by the state PUC, if one does not presently exist.
  • When considering the investment costs for DR, include the “avoided costs” of measuring those traditional supply-side investments and other generating capacity that will not be built as a result of the load reduction created by the DR programs.
  • Work with the state PUC to ensure that DR (and other EE programs) receives equal treatment within the context of long-term integrated resource plans.
  • Encourage the state PUC to allow utilities to earn a portion of the benefits associated with the DR program under a “net benefits sharing” mechanism.

Finally, along with full-cost recovery, it is a good idea to negotiate a performance-based approach for DR with the state PUC, which would include additional bonuses paid to the utility for meeting established DR program performance targets.

For the full article on this topic, visit www.westmonroepartners.com. For additional information, contact Will McNamara at wmcnamara@westmonroepartners.com.

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