California has lagged behind the rest of the nation when it comes to demand response, but now the state is preparing to open markets up to third party providers who can target large loads. That would represent a significant shift away from utility-led programs and could potentially help the state meet its energy demands cleanly by bringing millions of customers into the market.

The untapped potential of demand response (DR) in the state was identified years ago, and in 2014 the California Energy Commission issued a report saying that despite the potential benefits of DR “there has been insufficient progress toward meeting demand response goals set in the early 2000s."

The three largest utilities in the state all have demand response programs and combined budgets that total hundreds of millions, but for a variety of reasons critics say they are underutilized.

In 2012, the CPUC approved demand response programs and budgets through 2014 for Pacific Gas and Electric Co. ($191,886,588), San Diego Gas & Electric Co. ($65,806,526), and Southern California Edison Co. ($196,338,052). But for several years, California missed a goal that demand response would meet 5% of the state's peak demand. 

Now, state regulators are considering new rules which would open demand response to direct participation by third parties or energy consumers. The California Public Utilities Commission could authorize budgets at this week's meeting for the utilities to work with third parties to develop and integrate the technologies necessary to get the market off the ground.

The proposed outcome of the rule, according to the meeting agenda, is to establish "a multiple step approach to the implementation of third party demand response direct participation," but there will be no "mass market implementation" of the programs just yet — only initial steps to set up the programs.

If approved by the commission, PG&E would begin with a budget of $2.9 million to do so. SoCal Edison would begin with $2.7 million, and $1.8 million is the figure for SDG&E.

“We recognize the need to move forward with third party direct participation in anticipation of a demand response auction mechanism pilot,” wrote Administrative Law Judge Kelly Hymes in a proposed decision. 

The final decision also notes that regulators are “understanding the uncertainty regarding the amount of participation by customers,” and said utilities must get authorization before expanding the programs.

Background on regulator actions

Though the state has struggled to fully embrace demand response, the last year has seen a legitimate push to change that.

Last year regulators adopted a series of decisions designed to improve the efficiency of demand response and increase the use of demand response programs. And as the CPUC moves forward toward the implementation of demand response direct participation, the California ISO (CAISO) simultaneously moved forward in adopting tariffs and business requirement specifications that enable demand response providers to integrate into the energy market. 

The CPUC then adopted the policy to bifurcate demand response into load modifying resources, which reshape or reduce the net load curve and supply resources, which are integrated into the CAISO energy markets. 

The utility applications would have to be balanced against “the technical and regulatory requirements for the integration of demand response into the CAISO energy market.”

Timing is important, regulators note. Utilities were directed by the CPUC last year to set up a Demand Response Auction Mechanism, with the first pilot auction occurring in 2015 for a 2016 delivery. “The commission must ensure that the processes and tools for demand response direct participation are in place to allow the auction mechanism to be used,” the draft decision notes.

The new DR programs

The draft decision finds 7,000 customers to be appropriate for the initial phases at SDG&E, with PG&E targeting 10,000 customers and SCE about 14,000. The mix will include a combination of residential customers as well as commercial and industrial.

All three utilities requested to use manual processes for initial implementation, or at least until the number of customers using the process required automatic implementation, with that figure being around 750.

“A manual process by the utilities is reasonable until the CAISO Location API has been developed. However, the CAISO has provided timelines in this proceeding indicating that the Location API will be ready in early 2015,” the decision said. “Thus, we have little doubt that the CAISO Location API will delay the Initial Implementation Step.”

Each utility proposed fee schedules to facilitate the program, and regulators said there were no objections to any of the plans. PG&E asked the commission for a fee schedule pertaining to direct access services. Similarly, SDG&E also modeled its fees after the charges for energy service
providers. SoCal Edison proposed to establish a new tariff to establish the fees to third party demand response providers for customer information.

“We find it reasonable to model the fees for demand response direct participation after the fees for energy service providers,” the order said. “Nothing in this record indicates these fees are not
reasonable.”

Paying for the programs

Despite the relatively small budgets being considered, who pays for them was an issue for two group of direct access advocates.

While all of the utilities proposed the costs should be allocated to distribution customers, only the Direct Access Customer Coalition and the Alliance for Retail Energy Markets argued that cost allocation principles required that costs be allocated based on eligibility. If a program is available solely to bundled customers, they say, the costs for that program should be borne solely by bundled customers through generation rates.

Regulators disagreed, writing in the proposed order that “the direct participation rule requires the investor-owned utility to act as the meter data management agent for all community choice aggregation customers. Hence, the cost for implementation of direct participation shall be allocated to distribution
customers.”

DACC and AREM have jointly filed comments on the proposed decision, saying while they are the only parties disputing the cost allocation, it does not come as a surprise.

The utilities and groups “presented no unified position to substantiate their conclusions, and instead set forth a number of varied and often conflicting rationales to attempt to justify having direct access customers, who are exempt from an IOU’s rule, nevertheless be required to pay for the rule’s associated implementation costs. “

“This is not surprising, because each of these entities represent constituencies that, in whole or in part, benefit when direct access customers are required to pay costs that should be borne by bundled customers,” the groups said.

The Utility Reform Network also filed comments, saying the budgets for real time and ancillary services may require additional review. The proposed decision requires the utilities to include functionality for third party submission of bids into the real-time and ancillary markets, and orders the utilities to submit a proposed budget within 30 days.

"TURN is concerned that a 14-day comment period may not offer adequate opportunity to conduct any factual discovery and address any issues," the group said. "It is not clear how difficult providing ancillary and real-time services may be; however, the record in this proceeding indicates that at a minimum the utilities would have to program residential meters to collect and transmit 15-minute interval data, rather than the current one-hour data."