Distributed energy resources will play an integral role in the carbon-constrained grids of the future. But advances in technologies enabling this integration aren’t being matched by policy advances to enable it or the economic structures to align how they’re bankrolled, interconnected and operated with the needs of an increasingly renewable-powered grid.
State utility regulators and lawmakers are largely responsible for DER policy innovation. But progress has been stymied by the disconnect between existing policies and metrics for valuing customer-sited energy resources and those that could value the full range of what DERs can do. Federal Energy Regulatory Commission Orders 841 and 2222 mandate that DERs may participate in wholesale energy markets, forcing states and utilities to confront and find solutions to bridge these two disparate energy policy realms.
A new GTM Squared report will examine the complexities of state DER integration efforts. We'll start with California, which leads the nation in rooftop solar, distributed battery and electric vehicle deployments. The state serves a case study for how climate change is both forcing the need for faster decarbonization and opening up new opportunities for DERs to make the grid more resilient to global warming’s disruptions.
Last month’s rolling blackouts were a wake-up call to the fact that California hasn’t yet found a way to capture the value of its nation-leading share of rooftop solar, behind-the-meter batteries, electric vehicle chargers and digitally connected, flexible energy loads to serve its converging clean-energy and grid-stability needs.
California is ahead of most states in developing DER-friendly policies. But the complexities of adapting existing paradigms like net metering, demand response, resource adequacy or traditional grid planning to enlist DERs as grid agents have hampered much of the potential these policies were meant to unlock.
These problems are being tackled in proceedings before the California Public Utilities Commission, changing market designs from state grid operator CAISO and pilot projects and programs from the California Energy Commission. But these incremental changes aren't keeping up with the falling prices and increasing potential of DERs, and the carbon-reduction imperatives driving their integration.
These bottlenecks are leading many industry players and policymakers to consider more radical approaches, like pricing structures to connect utility customers with real-time grid needs in ways that could potentially cut the Gordian knot of regulatory barriers to DER integration.
The problems with demand-response paradigms
Almost all of the DERs serving California’s grid today do so under demand-response programs designed to shed load during peak grid demand. Load-reduction paradigms also inform DER participation in the resource adequacy regime managed by the CPUC and relied upon by CAISO for system capacity.
California’s approach to demand response is in the doldrums, however. CAISO has expressed concerns about its cost and reliability, noting high market prices and data indicating that resources are being bid into markets in excess of actual metered load.
But demand-response participants say California's approach undermines the value and profitability of the resources they’re aggregating. Problems include "a misalignment of expectations, reduced options, reduced value, higher implementation details and costs, higher participation requirements and more complex [resource adequacy] requirements,” said Mona Tierney-Lloyd, head of U.S. public policy for Enel North America.
Demand-response participation in California has declined from about 2,000 megawatts to about 1,500 megawatts over the past five years, according to CAISO data. That’s largely due to CPUC regulatory changes that pushed utilities to end programs that didn’t fit into CAISO markets, Tierney-Lloyd said.
Meanwhile, the Demand Response Auction Mechanism pilot program, which has enlisted hundreds of megawatts of DERs, has seen its budget cut over the past two years after receiving mixed reviews from CPUC staff. This, and stricter participation rules, means DRAM customers “are getting paid less, with an expectation of doing more in the form of more frequent dispatches,” Tierney-Lloyd said.
Multiple factors are at play in this state of affairs. But DER aggregators say a key problem is overly restrictive baseline methodologies, which project how much energy customers would have used if they hadn’t been dispatched to calculate their grid value.
Baselining is meant to ensure that demand-response providers don’t game markets by overestimating their load-shedding capacity. But its methodologies work against customers who are already striving to reduce peak usage, and change from program to program and from year to year in ways that make it difficult for aggregators to predict customers’ earning potential, according to Cisco DeVries, CEO of residential aggregator OhmConnect.
By way of example, during last month’s grid emergencies, OhmConnect asked its 150,000 customers to exceed typical load reduction to meet CAISO’s conservation request, DeVries said. OhmConnect has 66 megawatts of capacity approved for resource adequacy under CPUC regulations, but its emergency call achieved load drops that at their maximum equated to nearly 200 MW, according to the methodology approved for DRAM participants. Under CAISO’s baseline rules, however, that load reduction was only 101 MW.
“We got paid for some of it and not for other [parts],” DeVries said. “The system is set up in a way that incentivizes us to duck” CAISO’s call for grid relief.
Mismatch with California’s emerging DER assets and grid needs
The current rules also undermine the value of solar and batteries that reduce customers’ loads, which lowers baselines. Behind-the-meter batteries aren’t allowed to export power, which wastes the battery capacity being installed at record rates alongside new solar systems in California, including those oversized to provide backup power for customers facing California’s fire-prevention blackouts, according to Jin Noh, California Energy Storage Alliance (CESA) senior policy manager.
Efforts to change this are complicated by restrictions on net-metered solar-storage systems exporting battery capacity, as well as by the difficulties of reconciling exports with standards built around load reduction, Noh said. One potential change that could avoid those complications is allowing battery export during grid emergencies only, he noted.
Meanwhile, California is seeing behind-the-meter batteries aggregated for grid services, as Sunrun is doing with Southern California Edison and several San Francisco Bay Area community-choice aggregators. But the SCE project is primarily a test of batteries’ grid value, with unclear impacts on future policy. And the community-choice aggregator projects will see their grid value reduced by a recent CPUC decision centralizing local resource-adequacy responsibility with utility Pacific Gas & Electric.
All these rules are meant to ensure that DER aggregations can be predictable and reliable. But they’re ill suited to capturing the full value of the variable and incremental resource they’re representing, Tierney-Lloyd said.
That undercuts California’s need for resources to match California’s solar-inflected “duck curve” supply-demand conditions, she said. A long-running research project by Lawrence Berkeley National Laboratory finds that “load-shift” resources that can absorb excess solar power at midday and reduce consumption in the evening hours when the solar resource fades away — the same hours during which CAISO was forced to call for rolling blackouts last month — could replace gigawatts of batteries that would otherwise be required to meet this evening peak.
But “realizing this potential will require development of a technological and policy landscape that supports and values load flexibility," a Lawrence Berkeley National Laboratory document states. The CPUC’s Load Shift Working Group studied this issue and filed a report that was “supposed to result in a new CPUC rulemaking,” Tierney-Lloyd said. “Unfortunately, there hasn’t been any activity here for a long time.”
A chasm between behind-the-meter DERs and wholesale markets
This disconnect between today’s demand response paradigms and the potential value of DERs is part of the rationale behind the Federal Energy Regulatory Commission's Order 841 and Order 2222, which require the country’s interstate grid operators to open up their markets to DERs.
CAISO might appear to be ahead on this front because it has had a DER program available for years. But CAISO’s distributed energy resource provider program hasn’t signed up a single participant due to rules that make it unattractive for DER aggregators. Resources must commit to CAISO on a 24/7 basis, barring them from other revenue-generating opportunities. Requirements for separate meters and communications add excessive costs. And behind-the-meter batteries must pay both wholesale rates and retail rates for charging energy.
CAISO differentiates between retail and wholesale activities to prevent DERs from earning net-metering revenue or other retail-based compensation from distorting its markets. But this separation has also been a consistent barrier to DER participation.
For example, CAISO’s Proxy Demand Resource-Load Shift Resource product allows behind-the-meter batteries to earn money for charging when solar generation exceeds demand and must be curtailed. But it comes with many of the same restrictions that now make participating in CAISO’s distributed energy resource provider program unattractive, CESA’s Noh noted.
Drawing bright lines between wholesale market participation and other forms of grid services also restricts their potential to serve another valuable role — to defer or stand in for some fraction of the billions of dollars of distribution grid investments made by California utilities every year.
Realizing DERs’ grid value, from interconnection to distribution planning
Since enacted by the 2013 state law AB 327, CPUC’s Distribution Resources Plan and Integrated Distributed Energy Resources proceedings have led to a host of advances in DER-grid integration, from online integrated capacity analysis maps showing distribution circuit hosting capacity to pilot projects using DERs to defer grid investments.
California’s distribution investment deferral framework is part of this effort. But as with many “non-wires alternative” programs across the country, it’s been slow to identify and fund projects. The few that have been approved use large-scale batteries, not DERs, Noh said. DER providers have asked the CPUC to expand the framework's scope with tariffs that encourage DER development in areas expected to face future grid upgrade needs or which are at high risk of wildfires and fire-prevention grid shutoffs.
Grid resiliency is another value of DERs, primarily in the form of microgrids. The CPUC has a 2021 deadline to create microgrid tariffs that share costs and benefits between utilities and their customers and operators. While progress is slow, the state’s ongoing wildfire emergencies have put these efforts on a more urgent footing.
In the meantime, changes to California’s Rule 21 interconnection regulations approved by the CPUC last week allow new DER projects to “be designed in response to the grid,” said Sky Stanfield, an attorney representing the Interstate Renewable Energy Council. In simple terms, the new rules allow expedited interconnection for DER projects that can manage grid export on set schedules to reduce daily or seasonal stresses on circuits saturated with peak solar power.
That could avoid lengthy and expensive studies of their potential grid disruptions, or being forced to pay for grid upgrades to interconnect. But regulations still need to be worked out to limit utilities’ ability to restrict DER exports in ways that could degrade their value, Stanfield said. These kinds of utility-DER interactions are being enabled by Rule 21’s “smart inverter” requirements for all new solar and battery installations, which could allow dynamic controls that could help utilities and aggregators orchestrate their interaction to meet changing grid conditions.
The new Rule 21 revisions also lay the groundwork for vehicle-to-grid charging, although much regulatory work remains to be done before that's possible, CESA’s Noh said. EV chargers are projected to be the single largest class of flexible DERs in California as it pushes toward decarbonizing its transportation sector.
Most EV chargers in California are under time-of-use rates that discourage peak energy consumption in favor of off-peak hours. TOU rates also apply to behind-the-meter solar and solar-linked battery systems installed under California’s “net metering 2.0” regulations since 2016, and all customers are being shifted to these rates this and next year.
An even bigger shift toward aligning rooftop solar with grid-balancing challenges is expected to emerge from the CPUC's newly launched “net metering 3.0” proceeding, Utilities, solar industry advocates, environmental groups and ratepayer advocates are expected to file plans in the coming months to deal with the fact that net metering at retail rates may not make sense as distributed solar continues to flood California’s grid.
New pricing paradigms to connect disparate values
Aligning time-of-use prices, critical peak prices and other existing retail tariffs meant to shape mass-market energy consumption behavior with wholesale market prices — where California's solar disruptions are manifested — could help solve these problems. But wholesale prices don’t tell EV chargers when they might overwhelm the power lines and transformers they’re connected to, or direct behind-the-meter solar and batteries in how to support local distribution circuits and substations.
As court challenges to FERC Order 841 indicate, utilities and state regulators worry that DERs participating in wholesale markets will impact grid reliability and undermine the intended effects of retail-level tariffs and programs. We’ve covered pilot projects that are experimenting with technology to assess the real-time status of grids under the influence of DERs and control architectures to orchestrate mass-market DER operations to match those conditions.
Communicating time-of-use prices to household loads, batteries and EV chargers can help, as a San Diego Gas & Electric Smart Home Study with smart grid vendor Itron indicated. But as the final report on this California Energy Commission-funded project noted, “greater grid benefits can likely be achieved by further aligning distributed energy resource operations with dynamic (real-time) price signaling.”
That’s the goal of a proposal from CESA, OhmConnect, Enel North America and the California Solar and Storage Association, asking the CPUC to direct San Diego Gas & Electric to institute a real-time pricing tariff as part of its upcoming general rate case.
The idea is to use wholesale prices for the volumetric energy costs that customers pay, while retaining the fixed-cost portion of bills and creating time-of-use prices that reflect utilities' distribution grid needs, said Scott Murtishaw, the senior regulatory affairs adviser at the California Solar and Storage Association. “The combination of having customers exposed to the real-time energy price and giving utilities the flexibility to call events at any time of the year — not always the same hours, not always the same length of time — will allow the utilities to send much better price signals,” he said.
A similar concept informs the California Energy Commission-funded Retail Automated Transactive Energy System (RATES) project developed by TeMix, a transactive energy company whose CEO, Ed Cazalet, is a longtime electricity industry consultant and former member of CAISO’s board of governors.
RATES equipped 115 Southern California Edison residential customers with technology to automate DERs and loads to respond to pricing signals. Those signals combine real-time and forward-looking wholesale energy market prices with valuations of the loads on the distribution circuits that carry that electricity.
Customers subscribe to a fixed monthly bill based on their typical load pattern and existing retail rates in order to shield customers from super-high bills when wholesale prices spike, the biggest risk of real-time pricing, Cazalet said. But deviations from those set load curves are subjected to the RATES pricing, spurring homes to use less energy or export battery power to the grid when they’re high and consume more energy or charge batteries or EVs when they’re low.
Forward pricing and feedback mechanisms help avoid localized disturbances that can emerge with set pricing periods, such as multiple EV chargers on a single circuit all turning on at once when hourly prices drop, he said. That could reduce the need for utilities to “spend huge amounts of money to build software and technology to dispatch millions of distributed energy resources on the grid,” Cazalet said.
By paying customers directly, RATES could also reduce the need for aggregators to work with the flawed existing set of programs that allow DERs to try to make money from grid-balancing, he said. Of course, there’s a long way to go from a pilot project to a full-scale implementation.
“Where’s the signal? Where’s the tariff? It has to be deployed," Cazalet said. "That’s more of a political-regulatory issue.”