by Jeff St. John
April 12, 2019

Can tariffs, instead of utility contracts, bring out enough distributed energy resources to defer grid investment needs? California is now looking over a host of proposed experiments aimed at answering that question. 

Over the past six years, California has been on a slow march toward integrating distributed energy resources (DERs) like rooftop solar, behind-the-meter batteries, or grid-responsive loads into its utility power grids.

The effort began in 2014, when the California Public Utilities Commission (CPUC) launched its Distribution Resources Plan and Integration of Distributed Energy Resources proceedings, and guided Southern California Edison’s groundbreaking procurement of more than 100 megawatts of DERs to help replace the loss of the San Onofre nuclear power plant. 

Since then, we’ve covered the spread of DERs as alternatives to building new power plants or investing in grid infrastructure, as well as progress in California’s own version of a non-wires alternative process for its three big investor-owned utilities, the Distribution Investment Deferral Framework and Distribution Deferral Opportunity Reports, which culminated in SCE and Pacific Gas & Electric opening first-of-their-kind bids last month seeking DERs as grid replacements. 

While these DER-grid integration efforts have come out of different tracks of California energy policy, they’re all being done through the traditional utility approach of defining a big project through requests for offers and proposals, putting the project out for vendors to submit competing bids, and then selecting a winner to sign the contract and carry out the work.   

But for the past year, the CPUC and participants in California’s DER-grid integration efforts have been working on an alternative approach to solving this problem: creating tariffs to drive the investment in DERs that can meet grid needs. 

Tariffs as an alternative to DER-grid alignment 

Tariffs are standard rates that utilities use to charge customers for energy. But they can also be set up to pay customers for the energy, capacity or other grid services that DERs can provide, and calibrated to drive private-sector investment to meet the same needs now being filled via RFPs and contracts, proponents say. 

For DER providers, aggregators and developers, tariffs also offer advantages over RFPs and contracts. The RFP process forces companies to spend time and money competing for contracts that only a few will end up winning. It can also come with onerous requirements and hefty penalties for failure to meet the contract’s terms.

Tariffs, by contrast, could simply set the market terms for DERs that could help meet the grid needs in question, allowing utility customers and private-sector DER players to come together and meet that need.

Tariffs also have their drawbacks and challenges, of course.

From the utility perspective, the biggest may be that they’ve never been used before for this purpose, giving no real-world guidance on how to properly calibrate them to meet the targeted grid need.

Get the tariffs wrong, and utilities could face the prospect of under-procuring the needed assets, forcing them into rushed and expensive fixes, or over-procuring assets that aren’t needed, potentially wasting ratepayer funds. And that’s just the most obvious complication that could arise from this novel approach to meeting grid needs. 

In other words, before California begins using tariffs instead of contracts to bring DERs to market to serve grid needs, it’s going to have to test them out. In November, the CPUC issued a ruling asking utilities, DER developers and other parties to submit their own proposals for DER tariff pilot projects — small-scale demonstrations of different concepts for putting the tariff concept into practice. 

In February, the CPUC picked seven of the proposals it received to discuss further. Those included plans from utilities Pacific Gas & Electric and Southern California Edison, as well as proposals from some of the state’s key DER advocacy groups, including the Solar Energy Industries Association (SEIA), Vote Solar, the California Solar and Storage Association (CSSA), the California Energy Storage Association (CESA), and big rooftop solar provider Sunrun. 

Utilities are not convinced that RFPs don't work

These proposals cover a range of opportunities for tariffs to take the place of the standard contract process. The utilities have proposed relatively limited approaches — essentially, building on their existing customer programs for demand response, and taking a look at turning at least one of the Distribution Investment Deferral Framework projects they’re planning for next year into a tariff-based project. 

As PG&E noted in its DER tariff pilot proposal, it and the state’s other investor-owned utilities aren’t really on board with the idea that RFPs don’t work. As they pointed out in their initial comments to the DER tariff proposal being launched in March 2018, “PG&E’s existing competitive solicitation process rewards the most efficient market participants, ensures that any economic surplus accrues to customers, and is most likely to result in projects that are targeted and meet the full distribution deferral need.” 

PG&E wrote that it supports testing a cost-effective DER tariff for distribution deferral, but with the warning that “the measure of success for DERs should be the cost savings non-participating electric customers experience related to DERs serving as safe and reliable alternatives to traditional distribution “wires” investments, and not on creating a set-aside for megawatts produced by DERs or providing above-market incentives for benefits that are not needed or needed benefits that can be sourced at a lower price.” 

In other words, PG&E and other utilities are worried that the DER tariff proposals from industry groups could be aimed more at providing further financial incentives for the companies they represent, rather than solving the challenge of integrating DERs into grid planning and operations. 

Patty Cook, senior vice president of utility initiatives at ICF, a global consulting firm that’s working with PG&E on its “pay-for-performance” efficiency pilot, noted that utilities are leery of all the “unknowns” involved in using tariffs to meet their critical grid infrastructure needs. “DERs need to be integrated in an intentional way — it needs to be put in some places where it has the most benefit. If it’s an unstructured, random deployment of DERs, it makes it more difficult for the state to accomplish its decarbonization goals,” she said. 

But according to the DER industry groups, the benefits of tariffs over RFPs and competitive solicitations are far greater, and the risks far smaller, than the utilities may think. “The utilities tend to be more narrow in their view, and looking specifically to the [Distribution Investment Deferral Framework] process,” said Rick Umoff, regulatory counsel and California director of state affairs at SEIA.

The DER providers “have a little broader perspective on what DERs can do, and provide a little more assurance to DER providers that they’ll be able to enter into contacts with customers, to bring the DER projects online.”

Filling in the gaps in the RFP process

That’s because RFPs and competitive solicitations present many challenges for would-be DER investors and operators, potentially so many as to preclude them from taking part at all.

For example, San Diego Gas & Electric reported last year that its attempt to enlist DERs for a pilot project failed to find a single vendor that could meet the terms of its RFP in a cost-effective manner — evidence that the current RFP methods are too restrictive to get most DER vendors involved, according to CESA's comments on the matter.

According to CSSA’s filing, tariffs have four key advantages compared to competitive solicitations. First, “tariffs are much more streamlined than solicitations, significantly reducing the time between Commission approval of the final lists of deferral opportunities and acquisition of DER hosts.”

Second, tariffs “avoid significant transaction costs. Developers do not need to dedicate staff time to preparing bids and negotiating contracts.” 

Beyond that, DER providers may have real challenges in meeting the terms of a contracting process designed to support large-scale, single-vendor projects. DER providers have to go out and find thousands of individual customers to host their assets, a process that’s inherently uncertain in terms of how many devices will end up being deployed.

The utility’s rules for what these DERs have to do to earn their pay include significant financial penalties for failure to perform. It’s harder to ensure that thousands of customer-sited DERs are performing to specifications, compared to a single project. 

As ICF’s Cook noted, these kinds of performance obligations are a must for utilities, since they’re going to be on the hook for fixing any shortfalls in DER procurement or performance.  

“In order for the utilities to be comfortable with that approach, they’ve developed what they call a technology-neutral pro-forma contract,” she said, with features including upfront payments to cover potential penalties for failure to perform in the future, and other “performance obligations that are pretty hefty. For some of the startup companies, it will be interesting to see how long they can absorb some of these requirements.” 

But DER groups say that properly designed tariffs could incorporate this array of utility needs in ways that are far less costly and cumbersome, as well as help solve challenges that the current Distribution Investment Deferral Framework doesn’t handle well.

As CSSA’s filing put it, the DER tariff pilots should seek to answer two questions: “First, can tariffs enable successful deferral projects that aren’t feasible using a solicitation mechanism due to timing constraints and high transaction costs? Second, even for projects that lend themselves to solicitations, are tariffs more likely to result in successful deferral project completion?” 

For example, both CSSA and CESA have proposed pilots that would test out DER tariffs to replace a Distribution Investment Deferral Framework project, but with broader parameters and opportunities for DERs to participate than the competing utility proposals.

CSSA’s proposal is relatively simple — pick a utility-identified distribution deferral project, and offer a tariff that pays participants 85 percent of the utility’s annualized cost of traditional infrastructure.

In other words, it would test the proposition that DERs can beat traditional infrastructure at a 15 percent lower cost, with caps in place to stop offering the tariff once enough DERs were signed up — with a few extra to account for customer attrition — to meet the grid's need.  

Short-term problems, long-term solutions 

The CESA proposal would similarly target utility-identified distribution deferral opportunities, but look specifically at projects that are harder to solve with a competitive solicitation — projects that are too far in the future.

In terms of distribution grid investment, “utilities plan only five years ahead,” Jin Noh, CESA’s policy manager, explained. “Being part of that planning process, we’re seeing a lot of projects that are five years ahead that are not being pursued,” largely because there’s not enough forecasting certainty to know whether the investment is needed. 

But waiting a few years for that forecast to become clearer represents a lost opportunity to bring in DERs that could help solve the problem, CESA contends.

“Specifically, rather than eliminating projected needs that are beyond the three-year period to pursue an RFO due to forecast uncertainty, some of that forecast uncertainty risk can be hedged with a tariff,” offering solar- and battery-equipped customers payments for storing and discharging energy to reduce the time-based capacity constraints driving the need for grid investment, CESA’s filing noted.

The SEIA-Vote Solar joint proposal also highlights this challenge with RFPs: By the time there’s enough certainty to issue a contract, there’s often not enough time left to go out and procure the best, most cost-effective combination of DERs to solve the problem.

“As decisions in the [Distribution Resources Plan] proceeding have demonstrated, the value of avoiding these costs exists on two time scales,” the groups wrote. 

California’s current Distribution Investment Deferral Framework process has focused on using DERs as a “cost-effective substitute for specific, near-term projects that a utility identifies in its annual distribution planning process” — the shorter of the two time scales.

But it hasn’t yet addressed the “ability of DERs to reduce peak load growth over their lifetimes and thereby allow the utilities to avoid even the need to plan for upgrades in the much shorter time horizons of their distribution plans" — using a long-term solution that could eliminate the short-term problems before they emerge. 

To attempt this, SEIA and VoteSolar’s DER tariff pilot would go beyond the current list of utility distribution deferral projects, and instead provide payments and incentives to DERs being deployed in broad swaths of PG&E territory that the utility has identified as bearing the highest average marginal costs for keeping up their distribution grid infrastructure.

These costs, which average about $40 per kilowatt-year across PG&E’s system, have also risen to two or three times that cost in certain parts of PG&E’s system, such as Sonoma County, or its Central Coast or Sierra Nevada service territories. 

While these average costs can’t be linked to specific grid projects, they do indicate long-range challenges to be solved, the groups say.

By setting a tariff that offers complying DERs a payment that’s linked to, but always slightly less than, those marginal costs, the program should always come in at less than PG&E's comparative traditional costs. And capping payments once PG&E has procured enough DERs to meet its grid needs should limit over-procurement, along with the fact  that the targeted regions represent only 12 percent of PG&E’s marginal distribution costs, the filing noted. 

What’s more, most of these highest-cost regions are also the most at risk of devastating wildfires, like those that have driven PG&E into bankruptcy — and PG&E and the CPUC are already working on proposals to use DERs to provide grid resiliency and community backup power during fire emergencies.

Next steps 

Just what the CPUC will do with these DER pilot proposals is still an open question, both in terms of how many proposals might earn approval to move into real-world testing, and how quickly that might happen. The CPUC has a lot on its plate trying to manage PG&E’s bankruptcy and the broader wildfire risks for both the state’s utilities and their customers, and the Integration of Distributed Energy Resources proceeding, of which the DER tariff proposals are just one part, also has many pressing matters to manage, such as how to value DERs as grid assets. 

Still, DER groups are eager to see the CPUC move forward quickly with DER tariff pilots, based on the need to have them approved before a December 1, 2019 deadline to take part in the next round of utility distribution investment deferral projects.

They’ve also pointed out that the current path of utility RFPs hasn’t been very fruitful yet in delivering DERs that can meet the contracted needs. 

“The commission has been saying for some time that it wants to look at locational tariffs that consider DERs' long-run distribution value, not just short-term distribution value,” Umoff noted. In the meantime, he said, “There are a lot of avoidable grid costs out there, and we need to get DERs out there to start proving the model. We need leadership from the commission to show this works.”