If demand response is going to be used to help meet climate goals, then it makes little sense to allow a program participants to fire up backup generation, often diesel-powered, when the utility calls an event.

That's one of the central premises of a proposed decision before the California Public Utilities Commission that could be adopted later this month. But while the decision continues to nudge more demand response towards competitive markets, there are advocates who say the state is not working fast enough on that front. And enforcement of the provision on backup generation — known as BUGs — is light on oversight.

The decision, issued Aug. 30 by Administrative Law Judge Kelly Hymes, lays out a transition for demand response that includes less of a role for utilities, who currently manage the bulk of the state's resources, and more for third parties.

Last year the state kicked off a new Demand Response Auction Mechanism process and since then has completed two auctions. In the first, California's three investor-owned utilities acquired 40 MW of demand response — about twice what they were required. The second time around, they acquired 80 MW (but faced some criticism for not acquiring more than the minimum).

Next time, the targets will be higher. The draft order directs the three IOUs to accept all complying bids but sets a price ceiling using the simple average August capacity bid price. And in total, the utilities are not obligated to procure more than 1 GW annually — 400 MW each for Pacific Gas & Electric and Southern California Edison, and 200 MW for San Diego Gas & Electric.

Additionally, the order would exempt utilities from having to to accept bids priced above the long term avoided cost of generation at the time of the auction.

The auction is a big step forward for California, which has been a leader on climate change and renewable energy, but historically has trailed on the integration of demand response. But the order stops short of tackling some big questions, say environmental activists.

“The real question in California is, at what point do we finally transition demand response to being a prime-time resource?" said Environmental Defense Fund Senior Economist Jamie Fine. "Maybe not the same way we do in PJM, where there’s a capacity market, but at what point can we get demand response effectively and appropriately scheduled?"

Under the proposed order, utilities will file applications for 2018 demand response programs by the end of this year, and the CPUC expects by March to issue a report on more "advanced demand response" programs. That data will help inform a decision next fall, on how existing utility programs can be modified.

“The most efficient way is through a competitive marketplace," said Fine. But he says what's missing is a setting for that marketplace and a level playing field.

Now, utilities are purchasing demand response through the DRAM, but Fine said the more efficiency way would be to have the state's grid operator directly take over.

"It really should be through CAISO," said Fine. "This decision doesn’t get us there. It still puts scheduling in hands of utilities, who have some complicated interests."

The grid operator wants just that, and in the proceeding has pressed for the utility administrator model to be phased towards a competitively-procured framework more widely focused on overall grid needs. But the draft order is hesitant there. California is still waiting on a demand response study, due this fall, and ALJ Hymes is advocating the commission wait to see what the data presents. 

"[I]t is unknown what the new advanced programs will entail, including the implementation time and potential need for increased ratepayer funds," Hymes wrote. "Because of this lack of experience and the unknowns, we anticipate many questions and concerns by all stakeholders regarding the new advanced programs. One of the many unknowns is whether the CAISO will be ready to accept ancillary services and reverse demand response into its wholesale markets." 

Getting rid of BUGS

Back to the BUG problem.

The commission's draft order would prohibit certain distributed resources from being used during a demand response event, including diesel, natural gas, gasoline, propane, or liquefied petroleum gas. In a previous docket, the commission determined fossil-fueled back-up generation "is antithetical to the efforts of the Commission’s Energy Action Plan."

There are exceptions, however: waste-heat-to-power to be used for load reduction, storage coupled with renewable generation, and stand-alone storage. Stand-alone resources, however, must meet the relevant greenhouse gas emissions standards adopted for the state's Self Generation Incentive Program. 

But Fine says the rule could use some work. It is unsteady on how to enforce the BUG prohibition, and ultimately the problem itself implies a market that isn't fully functioning.

"As an economist, I’d like to think it’s not a good investment to turn on a BUG to avoid using power off the grid," Fine said. But "from an enforcement perspective, how do we make sure folks aren’t doing that?”

The rule orders utilities to jointly hire consultants to tackle that same question. The consultants would assess how to evaluate whether customers are complying with the prohibition, and provide recommendations on a verification plan. A report on verification will be due to the commission by April.

"There’s just too many sources out there" to check manually, Fine said.

Who should administer the programs?

While the long-term vision for California includes a competitive market for demand response, some utilities say it is too soon to take the traditional power provider out of the equation.

"First and foremost, customers should be allowed a choice in whether they participate in DR through their utility or a third party," Pacific Gas & Electric argued in July comments. A customers’ familiarity with their utility may make them more likely to participate in demand response, as opposed to a third-party, PG&E said. And the IOUs already have an obligation to enroll any qualifying customer in a demand response program — something the third parties do not.

"The IOUs also have a demonstrated history of DR administration, and have been developing infrastructure to enable third parties to participate in CAISO markets," PG&E noted, in addition to conducting research and development on emerging technology assessments and pilots to advance the resource.

SCE has maintained in its comments that utilities should continue to serve as administrators because they possess important electric system experience, and experience with customers and third party providers.

"There’s always been a debate about how quickly the utilities can transition out of demand response programs to a more market approach," said Fine.

Other questions focus on the split between load-modifying and supply-side demand response, only one of which can be dispatched into the market. California is also working to better understand that split.

One danger, says Fine, is that if load-modifying DR is not properly assessed then there is the possibility of overbuilding on capacity solutions.

"We’ve done a great job understanding supply-side DR, but we haven’t made nearly the same progress in connecting load-modifying demand response to the big money that supply-side resources can get," said Fine. "The key is linking that demand response to resource adequacy."

“Supply-side demand response shows up on the ledger, but is load-modifying DR being legitimately reflected? And if it’s not, you could end up building supply-side stuff to meet peak demand that never shows up," he said.

But no one disputes there is progress being made. California's DRAM pilot has allowed a new slate of providers to get involved in managing California demand: companies like EnerNOC, Nest and OhmConnect are now able to develop innovative programs from traditional DR to residential thermostat control and electric vehicle charging integration. And now that the genie is out of the bottle, most say it is a matter of how and when, not if, more demand response is moved into areas where the utility role is limited.

"If you look at the DRAM results, you see wonderfully innovative suppliers, said Fine. "This decision supports all of that, except the timing."