This year has already brought a lot of regulatory activity around distributed resources in California. Much of it is happening at the nitty-gritty level where working groups hash out metrics and methodologies, or administrative law judges weigh the merits of data access and market openness.
With some of the key policy efforts reaching their halfway mark in terms of schedule, there’s still a lot of work left to do.
California hasn’t yet delivered on the broader vision of a grid that connects utilities and customers in an interactive, integrated way. The CPUC is still working on a framework to value DERs as distribution grid assets. The role for distributed energy as a market participant is currently limited to pilot projects, and CPUC and grid operator CAISO have yet to decide how to manage their overlapping responsibilities when it comes to DERs.
Technology-specific proceedings -- net metering and time-of-use rates rates for solar, energy storage mandate for batteries, rebates for batteries and fuel cells, and demand response dockets for demand-side energy management -- aren’t yet well coordinated. The state’s Distributed Energy Resources Action Plan created in mid-2016 helps provide a framework for getting there, but still leaves gaps in creating a holistic regulatory framework.
This leaves us with plenty of context for discussions at this week's conference on California's Distributed Energy Future. (Squares can watch the live stream of the event here.)
Two key proceedings aimed at finding the value of DERs as replacements for distribution grid capital investments -- the Distribution Resources Plan (DRP) and integrated distributed energy resources (IDER) proceedings -- are bringing the most activity. Over the last few months, there have been some important updates on how these two efforts are coming along -- and where conflicts may be stalling progress.
Distribution Resources Plan: Finding the value of DERs
Commissioner Picker’s Distribution Resources Plan proceeding was created in 2014 as part of AB 327, the state law that led to the NEM 2.0 decision, as well as many other updates to state energy policy. The key goal of the DRP is to push the state’s investor-owned utilities -- Pacific Gas & Electric, Southern California Edison, and San Diego Gas & Electric -- to discover the value of DERs as part of their multibillion-dollar distribution grid budgets.
To get there, the DRP has asked utilities to create two key metrics:
- An integrated capacity analysis (ICA), which collects location-specific circuit data to determine how much new DER capacity any particular area can handle -- as well as improving interconnection procedures to help make that integration faster and cheaper.
- A locational net benefits methodology (LNBA), which is meant to identify the value of replacing distribution grid capital costs with DERs in terms of energy, capacity and reliability metrics.
To turn these mandates into action, the DRP asked each utility to create demonstration projects -- virtual testing grounds for ICA and LNBA methodologies that will model two different sections of their distribution grids, along with standard IEEE circuits
In late December, the IOUs delivered their reports on Demos A and B. Since then, the working groups formed last year to study these results, which include DER industry, environmental and ratepayer advocates, have suggested plenty of revisions. They've also filed a few complaints about how utilities have approached the task.
Integrated capacity analysis: Tools that DER developers can use
The ICA is one of the most promising developments so far. Brandon Smithwood, director of California state affairs for the Solar Energy Industries Association, called the ICA "the one place where the DRP is yielding some concrete and immediately usable pieces."
First and foremost, that's because the ICA has taken on the job of reforming the interconnection procedures for DERs on the distribution grid, noted Sky Stanfield, an attorney representing the Interstate Renewable Energy Council.
One of the long-range goals for this process is to enable what's known as a “click-and-claim” procedure for interconnecting new distributed energy projects. These online utility maps are designed to show accurate hosting capacity by address and circuit, and provide tools for developers to connect with the grid in a few easy steps.
“What we’re looking for is an automated or semi-automated process that would allow someone to proceed with a lot less manual review from the utility,” Stanfield said.
That's still far into the future. But the CPUC has agreed to reopen its Rule 21 proceeding, which deals with grid interconnections, later this year, to implement many of the ICA working group’s recommendations.
On the grid investment planning front, Demo A has been working on two different methodologies for how to calculate the capacity of distribution circuits, said Stanfield. In simple terms, the "iterative" methodology looks more like traditional utility power-flow modeling, while the "streamlined" method relies on algorithms to accomplish some of the same tasks with far less computing power involved.
Unfortunately, “the results in December showed that the streamlined method did not get very accurate results," she said, casting doubt on its usefulness for expanding ICA metrics to circuits across each IOU's distribution grid.
At the same time, "There’s pretty wide consensus that the iterative method is the more accurate tool -- but it requires a bigger computational burden,” said Stanfield. And that means additional costs.
That's important for determining whether the ICA maps being created by each utility are capable of describing real circuits in real time, or serving more as planning tools. “Our long-term goal for this is that there would be some way to have a fairly real-time updating of a full system model that would take into account all the changing factors. We’re not there -- and nobody’s saying it has to happen by tomorrow," she said.
Locational net benefits analysis: Conflicts over identifying and sharing values
The utilities' LNBA Demo B projects have gotten less of a warm welcome from industry and environmental participants, however. "The LNBA is not usable at this point -- and you can quote me on that," said SEIA's Smithwood.
While each utility has picked two pilot sites that may need some capital investments in the coming year, none of them have revealed the precise costs they're hoping to defer with DERs. That’s justified on the grounds that it’s market-sensitive information. But it makes it hard to understand how the spreadsheet that creates the localized values for DER capacity -- E3’s DERAC software -- comes to its conclusions, said Smithwood.
The other big problem is that utilities have limited the value of DERs to their ability to defer specific projects at a handful of sites. “The utilities are arguing [that] if you can’t defer a specific project, you have no local value. That’s been a big point of contention from the beginning,” he said.
SEIA isn't alone in this critique. The Environmental Defense Fund has called for alternatives to the avoided-cost method, such as applying the distributed marginal cost values being developed by California’s utilities and software providers like Integral Analytics.
EDF also laid out some areas where the DRP needs work: methods for evaluating location-specific benefits over timespans that match offer durations of the DER project; location-specific grid services of advanced inverter functions that California is mandating this year; and measuring the ability of DERs to act “in concert” with the same electrical footprint of a substation, increasing their total value.
Finally, Smithwood worries that the methodologies and applications provided by utilities so far in their LNBA work aren’t yet ready to serve the needs the CPUC has set for them. For example, NEM 2.0 requires new net metering rates to be based in part on LNBA-based locational values. But the product of the LNBA proceeding so far hasn’t yielded the data that would support this kind of calculation.
Integrated Distributed Energy Resources proceeding: Turning DRP grid values into DER monetary values
The DRP proceeding doesn't address how to convert values into dollars and cents for DER developers. To bridge that gap, CPUC Commissioner Michael Florio launched the Integrated Distributed Energy Resources proceeding in 2015.
In December, right before Florio completed his six-year term, the CPUC's five commissioners voted unanimously to approve a new IDER decision that sets up a blueprint for continuing work after his departure. The key mechanisms for this are the "development of a competitive solicitation framework for distributed energy resources," and the creation of a new set of "regulatory incentive mechanism" pilots, set to roll out at each investor-owned utility over the next 18 months,
“I think he wanted to do more,” said Brian Korpics, policy director at the Clean Coalition, of Florio’s final filing. "[But] this is what he wanted to do to begin with."
Specifically, the IDER proceeding’s main follow-on task is to create financial values for distributed resources that could stand in for capital projects, he said. The pilots will test out the methodologies for identifying multiple distribution deferral locations to help “get utilities comfortable with how DERs can perform, that they can be relied on and can displace or defer those traditional grid investments.”
It will also test out how the valuation methodologies align with DER costs and capabilities, according to Erika Diamond, vice president of energy markets for EnergyHub, a frequent commenter on DER proceedings.
“There are two things we’re testing,” she said. “One is whether these incentives will draw DER procurement, and the second is, does this framework for procurement work?” That’s going to become increasingly important as needs grow from single megawatts today to hundreds of megawatts in the next decade, she added.
Bringing in compensation adds a lot of new complications absent from the DRP proceeding, Diamond added. One is the need for pro-forma contracts for different types of DER solicitations, which would help clarify just what values utilities are seeking to achieve from different classes of DER technologies.
Another is dealing with the issue of additionality -- making sure each new project isn’t being double-counted as part of some other proceeding in ways that give it an unfair advantage against competing alternatives. “Most of these procurements in the past have said these projects have to be incremental -- but the definition of that has always been very loose," said Diamond.
Korpics noted that the IDER pilot projects may also face some of the same information-sharing challenges that have caused problems in the LNBA part of the DRP. “Projects are supposed to be in areas where there is significant opportunity to defer a traditional capital investment,” he said. “We don’t know where any of these locations are, because that’s sensitive information. [...] Something we are looking ahead to, after the pilots, is to make sure these utilities don’t serve as the sole gatekeeper to identifying these projects That could stop the DER market from developing."
To hash out these issues, the IDER has committed to bringing third-party providers into the Distribution Planning Advisory Group that's helping to guide progress on these issues.
DRAM, TOU rates, and other odds and ends
The DRP-IDER track isn’t where all the action is taking place. Amidst the many worthwhile proceedings to cover, time-of-use (TOU) rates and the demand response auction mechanism (DRAM) are moving along.
We covered the details of TOU rates last month, including the negative effects on solar valuation as beneficial rates are shifted later in the day, as utilities are asking for, a request the CPUC approved earlier this year.
To compensate for that shift, solar advocates and energy policy groups are looking for some innovative solutions, such as solar-storage rates that could help select customers cover the costs of behind-the-meter batteries that shift solar generation to later in the day.
The past few months have also seen some interesting developments with DRAM, including the CPUC’s decision to uphold a protest by DER providers that asked utilities Pacific Gas & Electric and San Diego Gas & Electric to open more megawatts up to the auction. The CPUC’s decision also opened the “DRAM III” program, which will differ from the previous two versions of the auction in several important ways.
But the bigger question hanging over the DRAM is the prices that are being bid by DER providers. “One mystery that remains to be solved here is the pricing of the bids in this pay-as-bid auction,” GTM Research analyst Elta Kolo noted. “It is my understanding that the undisclosed clearing prices are low and that the vendors who declined contracts when they were awarded capacity did not see a profit margin to participate. If this is the case now, how will DRAM attract participants past the pilot phase?"
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