Exit fee: Deciding the fate of California’s utilities and customer choice movement

EDITOR’S NOTE: This story has been updated to include a recently filed Alternate Proposed Decision by Commissioner Carla Peterman.

Promised more renewables and lower utility bills, customers in California are flocking to newly-emerging Community Choice Aggregation (CCA) programs and Direct Access (DA) providers.

But the transition — and the savings — are not that simple. Someone has to pay for the power that investor-owned utilities (IOUs) procured to serve the customers moving to new load serving entities (LSEs).

The California Public Utilities Commission (CPUC) is determining how ratepayers should compensate utilities for procured generation if they move to customer choice organizations. The latest development came on Aug. 2, when the CPUC issued a proposed decision that would redefine the charge CCAs and DAs have to pay when customers migrate to them from traditional investor-owned utilities. And the old-school power companies are not pleased.

The CPUC’s decision fails to assure “customer fairness in the division of the costs of long-term renewables contracts,” Southern California Edison (SCE) Vice President Colin Cushnie told Utility Dive via email.

As customer migration to new LSEs accelerated over the last two years, procurement of new renewables has virtually halted until a charge for the transitioning customers is determined.

The ‘hundred years war’ over choice

State law requires departing customers to pay IOUs a cost for moving to new LSEs. That cost, known as the Power Charge Indifference Adjustment (PCIA), promises to be intensely disputed between choice advocates and the IOUs.

The PCIA is intended to “equalize cost sharing” between customers who leave their IOUs for new LSEs, called “departing load,” and those that stay with their IOUs, called “bundled load,” California Public Utilities Commission (CPUC) administrative law judge Stephen C. Roscow wrote on issuing the proposed decision. Direct Access porviders must similarly maintain fairness to all customers, he added.

If the PCIA is too high, the new LSEs are not certain they can fulfill promises of lower customer bills.

“The decision goes a long way to resolving our uncertainty,” said Nick Chaset, CEO of the alternative provider East Bay Community Energy (EBCE). “We don’t know what the present PCIA will be year to year, which makes it extremely hard to plan.”

But the IOUs say a lower PCIA would not compensate them fairly for generation procured in the expectation it would be needed to serve customers who now are moving to new LSEs.

SCE’s Cushnie said the decision does not “preserve the value of current utility portfolios” or “ensure that departing load does not disrupt California’s energy markets.”

The IOUs want a PCIA that includes the cost of utility-owned generation (UOG). The alternative providers reject this idea because new renewable generation is more cost-effective.

“The CCAs are going one way and the IOUs are going the other,” former CPUC Commissioner Mike Florio told Utility Dive. Florio, who co-authored a June 2018 GridWorks white paper on CCAs, said the “tweak” in the PCIA formula “was the straightforward thing to do without taking a side in the hundred years war.”

The customer choice groups and the IOUs say the proposed decision needs improvements.

On Tuesday, CPUC Commissioner Carla Peterman, who is in charge of the PCIA proceeding, filed an Alternate Proposed Decision (AD). The AD differs from ALJ Roscow’s PD in four fundamental ways, according to her.

The most important are that it found legacy UOG should be included in the PCIA calculation and there should be no limit on when that legacy UOG was added to the IOUs’ portfolios. The AD also alters the proposed cap and collar on the PCIA and proposed adders in the calculation of charge in ways that could allow the PCIA to reach a higher value.

California regulators’ final ruling could decide their financial viability as customers are increasingly migrating away from IOUs, as shown in the figure below.

Balancing competing interests

New LSEs look to the current PCIA calculation as a burden that is likely to worsen.

The current charge would shift $492 million from Pacific Gas and Electric (PG&E) customers and $25 million from SCE customers to the CCAs’ 2018 customers, according to the California Community Choice Association(CalCCA). “That will increase as more customers switch to CCA.”

PG&E argues it allowed CCA customers to pay only about 65% of what they should have paid in 2017. The result was “about $180 million in costs being imposed on remaining utility customers, an amount that could grow to $500 million by the early 2020s.”

If the cost of an IOU’s portfolio, including UOG, is above market value, it shifts more of it to departing customers through the PCIA. If the PCIA is below market value, it shifts the cost burden of the IOU’s portfolio to their remaining customers.

The objective of the PCIA proceeding is to address “widespread concerns” that the current PCIA’s “existing cost allocation and recovery mechanism is not preventing cost shifting,” the proposed decision’s author, Roscow, wrote. That would violate the laws empowering CCAs and DAs that require customer fairness, he added.

On behalf of the CPUC, Roscow found that UOG purchased before AB 117, the 2002 law establishing CCAs, should not be included in the PCIA calculation. The law included a specific list of costs “for which departing CCA load would be responsible, and pre-2002 legacy UOG is not on that list,” Roscow wrote.

The legislature and the CPUC “expected that the utilities would work diligently to reduce or eliminate future liabilities,” he added. Simply because they did not do this yet “is not a reason to impose these costs on CCAs.”

“The law is clear,” EBCE’s Chaset said. “There can be no cost shift, because CCA customers cannot shift a responsibility they do not have.”

But “clearly those assets were built for all customers,” former CPUC commissioner Florio said. “It was a strange reading of the statue.”

Both Florio and SCE’s Cushnie said the CPUC regulatory judge failed to consider history subsequent to AB 117. “SCE’s first CCA didn’t start until 2015,” he said. SCE’s UOG was “approved by the Commission for the benefit of all customers.”

The CPUC regulatory judge also failed to recognize that a significant portion of UOG “is in critical local reliability areas and provides local reliability services for the benefit of all customers,” Cushnie added.

The best way to protect all customers is “to allocate all benefits and net costs of the existing utility portfolios to all customers, regardless of their load serving entity,” Cushnie said.

Attorney Matthew Freedman, representing customer advocacy group The Utility Reform Network (TURN), agreed with Cushnie and Florio. The cost of the UOG should be shared by all customers because “the governor and this Commission were leaning hard on the utilities to bring as many new generating resources online as possible.”

Calculating the PCIA

The CPUC’s decision imposes several new mechanisms. One is a “rate collar with a floor and a cap that will limit the change of the PCIA from one year to the next” and protect against “the potential for volatility” in energy prices. “The cap will provide a degree of stability and predictability.”

The initial EBCE analysis shows the proposed decision will set the PCIA “at or near its current level,” Chaset said. “But the cap and the collar are important.”

As EBCE computes it, the PCIA was about $0.026/kWh, but is capped for 2019 at $0.022/kWh, Chaset said. Because of the collar, the maximum increase of the charge for 2020 would be $0.005/kWh. That means that the 2020 PCIA cannot be higher for EBCE than $0.027/kWh, and the 2021 charge cannot be higher than $0.032/kWh, he said.

“This will not hinder our ability to operate,” Chaset said. “But the most important part is it gives me certainty and allows me to plan.”

The cap seems inconsistent with laws protecting against cost shifts, Cushnie said. It will also “be subject to customer gaming unless applied on a customer-specific basis — which is also highly impractical.”

Another mechanism is an annual “true-up” to correct inaccuracies from forecasts with actual market data. “The true-up will ensure that bundled and departing load customers pay equally for PCIA-eligible resources,” the CPUC’s Roscow wrote.

The true-up is one of the most important provisions of the proposed decision, TURN’s Freedman said. It will “reconcile actual resource costs, recorded generation volumes, and realized market revenues” and ensure that net costs are tied to actual market revenues and not “theoretical long-term planning values.”

SCE’s Cushnie and CalCCA Executive Director Beth Vaughan also want the decision’s true-up mechanism to reflect actual market results. This appears to be a sign of potential common ground in “the hundred years war.”

Can California wait?

CCA growth is accelerating, according to a new paper from California think tank Next 10. There were nine CCAs in operation in 2017 and eight are expected to launch in 2018. Their impact in the longer term “depends on their energy procurement strategies and their local investments.”

And Senator Robert Hertzberg’s Senate Bill 237 would allow DAs to serve all commercial industrial customers, significantly expanding the impact of the customer choice movement.

IOUs served 70% of California’s load in 2017, but will fall to 57% in 2020, Next 10 forecasts. Passage of SB 237 would add to the likelihood of the CPUC forecast that IOUs could lose as much as 85% of their current load by the mid-2020s.

Filings by the CCAs in the CPUC’s integrated resource planning proceeding are “a mixed bag,” Union of Concerned Scientists senior energy analyst Laura Wisland told Utility Dive. The aggregated CCA portfolio contains a lot of large hydro and out of state wind, and “what grows over time is mostly solar,” she said. “That does not address the state’s need for resource diversity or relieve its solar over-generation.”

But, she added, “we should be doing everything possible to accelerate their ability to invest in California’s clean energy future.”

CCA offerings range from 37% to 100% renewables, but they are new entities with unestablished creditworthiness, limited balance sheets, and uncertain customer loads, Next 10 points out. The think tank reported great potential in renewables growth from the CCA trend, as shown in the figure below.

However, CCA’s have relied largely on “short-term and out-of-state” contracts for existing renewables.

That “is not adding a lot of value,” V. John White, Executive Director of California’s Center for Energy Efficiency and Renewable Technologies, told Utility Dive. “They are well motivated, but it is not clear they will be able to procure what is needed to help meet California’s clean energy and climate goals.”

Wisland and White agreed a central procurement authority might help CCAs overcome their limitations.

However, it takes two years to three years for a CCA to establish the balance sheet and credit it needs, Next 10 paper lead author Julien Gattaciecca of the UCLA Luskin Center for Innovation told Utility Dive. “The debate about CCA procurement should not look at the past, it should look to the future.”

CalCCA’s Vaughan and EBCE’s Chaset said a key driver for CCA procurement would be to accept CalCCA proposals to auction older vintage, above-market IOU renewables contracts and securitize UOG.

The auction could move viable long-term renewables contracts into CCA portfolios at more affordable prices, Vaughan said. Securitization would help IOUs optimize their portfolios, which would minimize the burden of the proposed decision’s finding on pre-2002 UOG.

“Our initial assessments suggest securitization would save bundled customers more than any potential costs of exempting CCA customers from paying for pre-2002 assets,” Chaset said.

The proposed decision calls for “a second phase” of the PCIA proceeding to take on “a comprehensive solution” to optimizing utility portfolios.” It will include “a ‘working group’ process to enable parties to further develop a number of proposals,” the CPUC’s Roscow wrote.

A CPUC ​final ruling is expected September 13. The working group process would follow.

It is unlikely the commission will change the regulatory judge’s basic approach, Florio said before Peterman filed her AD. Florio had foreshadowed that the CPUC might offer “a different conclusion” on the pre-2002 UOG.

A central buyer might streamline procurement, but the newer CCAs, led by those that preceded them, seem to already be moving faster, he added. “Clearly there is a lost opportunity because this a good time to be a renewables buyer. But waiting for the CCAs “may be the only choice now.”

And the shift away from the IOUs may not be as big as the CPUC foresees, he added. The proposed decision could put the PCIA at a level that will discourage some CCA efforts to beat utility prices.

“Until now, a blindfolded baby could beat the utilities’ prices, but the gap between what CCAs can buy for and what the IOUs are paying is likely to close,” Florio said.