California regulators have released a plan that could radically change the way demand response is managed in the state.
In an Aug. 30 proposed decision (PDF), the California Public Utilities Commission laid out a path for fuel-fired generators to be phased out of the state’s demand-side resource mix by 2018, and for today’s utility program-centered model to shift toward an open market for third-party energy services by decade’s end.
Last week’s proposed decision is the result of a years-long process aimed at improving the state’s poor performance in demand response (DR) -- the business of controlling buildings and machines to reduce power use and help the grid. In California today, demand response is almost completely run by utilities through individual programs that have been approved over the decades, ranging from commercial and industrial interruptible loads, to mass-market residential programs.
That’s an old-fashioned way to bring demand-side resources to bear in a state that leads the country insolarPV, energy storage and energy efficiency. The CPUC said from the beginning that it needs to change. So far, it has imposed two requirements on utilities, starting last year, seeking out a set number of megawatts' worth of third-party demand response, and opening a Demand Response Auction Mechanism, or DRAM, program.
Under its new proposal, however, these pilot programs will serve as a model for switching over hundreds of megawatts of traditional DR, and opening the grid to an entirely new class of distributed energy resources (DERs) -- the smart thermostats, building automation systems, behind-the-meter batteries, plug-in electric vehicles, and other agents of grid edge capacity.
“Slowly but surely, California is going green and letting competition ensure reliability,” GTM Research analyst Elta Kolo said. “If the decisions get passed, from 2020 onward the role of the utility will become much smaller and third parties will take over the procurement and implementation of DR programs.”
Kolo laid out three key features of the new proposed decision, which could be considered by the CPUC’s five-member commission in late September.
No more BUGs in the system
First, in an upset for the traditional practice of firing up backup diesel generators for demand response, the CPUC wants to set a January 1, 2018 deadline to ban certain fossil-fuel backup generation resources -- anything using diesel, natural gas, gasoline, propane or liquefied petroleum gas.
As CPUC judge Karen Clopton wrote: "Standalone storage and storage coupled with renewable generation should be allowed to be used during demand response events but must meet the relevant greenhouse gas emissions factor thresholds adopted for the Self-Generation Incentive Program.”
As we’ve noted in previous coverage, California’s SGIP has been updating its greenhouse gas regulations in ways that could preclude natural-gas-fed fuel cells, as well as fossil-fueled generators and combined-heat-and-power systems.
The proposed ban comes over objections from both utilities and demand response providers that the CPUC should collect data on backup generators -- or BUGs, in the parlance -- before it makes a move that could undercut valuable resources in the state. But in a terse reply, Clopton wrote that the commission has “been waiting for this data since 2011 and [has] been unsuccessful for five years,” adding that it’s ready to move ahead, under the general rule that demand response should serve the state’s overall environmental goals.
That decision is backed up by the fact that the CPUC’s proposal would make reducing greenhouse gas emissions and supporting renewables integration part of the CPUC’s mandate for demand response. The CPUC’s main jobs are to regulate utilities, ensure energy and grid reliability, and protect consumers’ pocketbooks -- making the addition of environmental goals a noteworthy addition.
CPUC Commission President Michael Picker has long been talking about making the connection more explicit, given how tightly energy and environment are entwined in state policy.
A roadmap to third-party competition
Second, the proposal calls on utilities to create “newer model programs to enable fast-response demand response and help meet California’s future capacity and ancillary service needs.” While the precise form of those models has yet to be determined, last week’s proposed decision does lay out a set of principles that would radically open the state’s market.
Take, for example, the final principle on the CPUC’s list:
Demand response shall be market-driven leading to a competitive, technology-neutral open market in California with a preference for services provided by third parties through performance-based contracts at competitively determined prices, and dispatched pursuant to wholesale or distribution market instructions, superseded only for emergency grid conditions.
This statement of “preference” describes a demand response market more akin to those run by mid-Atlantic grid operator PJM, where the “negawatts” of demand-side resources can compete against generators in capacity markets, or hook up fast-responding loads or batteries to play in frequency regulation services, all through common market structures. It’s a far cry from the programmatic approach in place today in California.
The proposal also wants to see pertinent data shared between utilities, third parties and customers: “Demand response customers shall have the right to provide demand response through a service provider of their choice and utilities shall support their choice by eliminating barriers to data access.”
The CPUC noted that state grid operator California ISO led the call for this open market framework, while some utilities balked. San Diego Gas & Electric, for example, commented that "new markets could create cross-jurisdictional issues and suggests that accurate price signals must be developed for demand response,” the proposal noted.
The CPUC agreed with CAISO, however, that “promoting market-driven demand response solutions is fundamental to growing reliable demand response.”
By December 31, 2016, utilities will need to file applications for 2018 demand response portfolios for existing programs and activities, based on commission guidance. By March 2017, the commission expects to issue its guidance for new “advanced" demand response programs. And by fall of 2017, the commission expects to issue a decision on how utilities should modify their existing programs for their 2018 portfolios.
The data for the CPUC’s rulemaking will come from its 2015 demand response study, which is being delivered in two phases. The first, delivered in April, focuses on meeting system and local peak capacity needs with existing programs. The second, due in October, will deliver newer model demand response like flexible resource adequacy, ancillary services and reverse demand response, or taking extra power when the grid has a surplus of solar power.
It will also be informed by the ongoing DRAM pilots, which are the first time distributed energy resources have been able to bid against each other in a standard way on California’s grid. So far we’ve seen behind-the-meter battery providers like Stem and Green Charge Networks, traditional demand response providers like EnerNOC, electric vehicle aggregation from eMotorWerks, household behavioral demand response from EnergyHub, OhmConnect and Chai Energy, and commercial battery-load control projects from Advanced Microgrid Solutions, winning bids for the program.
GTM Research’s Kolo noted that “DRAM is a unique approach already as a pilot, and if it indeed becomes the sole DR procurement mechanism, this opens up many opportunities for third-party aggregators and the marriage of various grid edge DERs at scale.”
The open question of the utilities’ future role
Kolo said that it’s not clear how much of a role utilities will retain in this transition. “Once information is gathered, which will measure the success of various DR efforts where the utility plays a key administrative role, then a proper assessment can be made,” she said.
Judging from commentary in the CPUC proceeding, however, “The sentiment of third parties is clear -- they want utilities to play a smaller role.”
In a section on the role of the utility, the CPUC did share some thoughts on the subject. Back when demand response programs were first established, utilities "were the natural administrators of demand response with significant experience in marketing, outreach and rate design,” it wrote. While some parties, including CAISO and some third-party vendors, suggested getting rid of this utility involvement, they agreed that getting rid of utility control is "premature."
“Because we have adopted a principle of market-driven demand response with a focus on competition, we will encourage the use of fair competition between the utilities and third-party providers in demand response and will adjust accordingly to the outcomes of the competition," wrote the CPUC.