California regulators are poised to decide soon between two proposals on how to calculate the exit fee charged to customers moving away from California’s investor-owned utilities (IOUs) to new electricity providers. The result could determine the near-term viability of California’s budding customer choice movement.
Regulators face three big questions on how to calculate the Power Charge Indifference Adjustment (PCIA), a small per-kWh amount added to the bill of a departing customer that compensates the utility for investments made in anticipation of serving that customer.
The first question is whether the PCIA should include the cost of high-priced utility-owned generation the IOUs might long ago have sold off. The second question is whether it should include the cost of somewhat newer but still high-priced utility-owned generation added to IOU portfolios largely for reliability purposes. And, finally, regulators must decide how, if at all, to limit the size of changes in the value of the PCIA.
The answers could make the PCIA too high for new customer choice-inspired load serving entities (LSEs), including Community Choice Aggregators (CCAs) and direct access providers, to fulfill commitments to deliver cleaner energy at a lower cost. Or it could put the state's IOUs at financial risk.
Two alternatives in phase one
One approach to updating the PCIA calculation can be found in an Aug. 1 proposed decision by California Public Utilities Commission (CPUC) Administrative Law Judge Stephen C. Roscow; another approach in an Aug.14 alternate proposed decision by CPUC Commissioner Carla Peterman.
Both found that the CPUC's current PCIA methodology cannot prevent cost shifts between customers. But that's where the similarities end. On Sept. 27, the commission is poised to vote on what the new PCIA calculation should be.
But while the decision will be important to the continued expansion of the customer choice movement, it is just one phase in the process of updating how the PCIA is calculated and even bigger challenges lie ahead.
A second phase will take on bigger questions like how utilities can cost-effectively eliminate the older utility-owned generation from their portfolios and how the PCIA calculation can appropriately value elements of LSE power portfolios that deliver other system services or meet California policy goals.
The rise of customer choice
California's 2002 Assembly Bill 117 established CCAs to give residential and small business customers a non-utility option for buying electricity. Direct access was shut down after the 2000-2001 California energy crisis, but 2009’s Senate Bill 695 re-established it.
There were nine CCAs in operation in 2017 and eight are expected to launch by the end of 2018, according to a July paper from California think tank Next 10. The just-passed Senate Bill 237 increased the cap on direct access from 13% of IOU load to 15.4%, further expanding customer choice.
IOUs served 70% of California's load in 2017, but will fall to 57% in 2020, Next 10 forecasts. By the mid-2020s, over 80% of the state’s retail electricity load will be served by CCAs, direct access or distributed generation, according to a 2017 white paper from the CPUC.
CCAs and direct access providers have thrived by committing to deliver more renewables and lower bills to customers than IOUs. But if the PCIA is too high, new load serving entities may not be able to fulfill those commitments. Choice advocates say the present PCIA calculation inputs result in a charge that unfairly imposes costs on their customers. IOUs say it unfairly imposes costs on their customers.
Proposed vs. alternate proposed decision
The PCIA, now in the range of $0.01/kWh to $0.04/kWh, is intended to "equalize cost sharing" between customers who leave their IOUs for new load serving entities, called "departing load," and those who stay with their IOUs, called "bundled load," Roscow wrote in his Aug.1 proposed decision.
California’s IOUs have made enormous investments in generating infrastructure over decades to serve anticipated customer load. Some investments met the traditional "least cost, best fit" standard. Others had higher than market costs but were necessary to meet state mandates. Most of that generation capacity can today be obtained at significantly lower prices but remains in IOU portfolios.
"If departing customers pay less than their equitable share, remaining customers have to pay more, and that's not good public policy or consistent with the law."
VP of energy procurement and management, Southern California Edison
Judge Roscow made decisions about many factors used in the calculation of the PCIA. Commissioner Peterman’s Aug. 14 alternate proposed decision reversed three important ones.
Roscow's proposed decision excluded imposing a price in the PCIA for legacy pre-2002 utility-owned generation and excluded imposing a price for post-2002 utility-owned generation and storage that is over ten years old. Peterman found they should be included. Third, the proposed decision established a PCIA collar, or limit on any increase, of $0.005/kWh per year, with an upper cap starting at $0.022/kWh in 2019. Peterman's alternate proposed decision collar is 25% of the PCIA and is not implemented until 2020.
The current Pacific Gas and Electric (PG&E) PCIA is $0.027/kWh and it is forecast to go up to $0.029/kWh in 2019, Nick Chaset, CEO for the East Bay Community Energy (EBCE) CCA, told Utility Dive. Under Peterman's alternate proposed decision it will be about $0.036/kWh, driven largely by the utility-owned generation. Under Roscow's proposed decision, it will be $0.022/kWh because of the cap.
The Southern California Edison (SCE) PCIA is currently $0.017/kWh, VP Colin Cushnie told Utility Dive, "If the CPUC votes to accept Commissioner Peterman's alternative, SCE's PCIA rate will be between $0.02/kWh and $0.03/kW in 2019, depending on other assumptions, but if the commission accepts the proposed decision, SCE’s PCIA would be close to or less than $0.02/kWh."
"But it's not the prices that matter," Cushnie said. "If departing customers pay less than their equitable share, remaining customers have to pay more, and that's not good public policy or consistent with the law."
How the commission votes on the three major factors will determine the size of the PCIA and could impact CCAs ability to meet the Next 10 and other forecasts for significant growth.
Factor 1: Legacy utility-owned generation
The Peterman's decision allows costs for legacy utility-owned generation procured before the 2002 CCA law was passed to be part of the PCIA price. It includes nuclear, natural gas and large hydropower resources procured largely at prices higher than current market prices. The Roscow decision's PCIA is lower because it does not include legacy utility-owned generation.
"There is very clear evidence that AB 117 excluded utility-owned generation from the PCIA calculation to push the utilities to begin changing their resource portfolios."
CEO, East Bay Community Energy CCA
In the alternate proposed decision, Commissioner Peterman cited arguments made about legacy utility-owned generation by the California Community Choice Association (CalCCA). She also cited arguments made jointly by SCE, PG&E and San Diego Gas and Electric (SDG&E).
CalCCA argued that lawmakers intentionally excluded legacy utility-owned generation in AB 117 and "no statute passed since that time has imposed legacy utility-owned generation costs on CCAs or any other departing load customer class."
Citing "Expressio unius est exclusio alterius — the expression of one thing implies the exclusion of others," CalCCA argued utility-owned generation should not be included in the calculation of the PCIA, Peterman reported.
"There is very clear evidence that AB 117 excluded utility-owned generation from the PCIA calculation to push the utilities to begin changing their resource portfolios," Chaset said.
CalCCA also argued the above-market cost of legacy utility-owned generation has increased their customers' bills. Their filing reports it contributed "$545 million in uneconomic costs to PG&E's 2018 PCIA."
The state's three largest IOUs reframed CalCCA’s argument, suggesting that AB 117 could have explicitly excluded legacy utility-owned generation costs, Peterman wrote. SCE, PG&E and SDG&E also argued that the basis of both AB 117 and 2015’s Senate Bill 350, which "clarified" AB 117, "is the absolute prohibition on cost-shifting between customers."
SB 350 increased the IOUs’ renewables obligations at the same time the customer choice movement gained momentum, Cushnie said. "The bill made it clear procurements by the IOUs for bundled customers should not result in higher costs for either departing or remaining customers. That is customer indifference."
CalCCA’s statutory arguments were "unconvincing" and the legal arguments from the utilities, especially those about the superseding importance of SB 350, were noteworthy, Peterman wrote.
"Exclusion of those costs [for utility-owned generation from the PCIA] while they are above-market amounts to an invitation to shift costs to bundled customers that were incurred to serve CCA customers who later departed," she concluded.
Factor 2: Post-2002 utility-owned generation
Peterman's alternate proposed decision concluded the PCIA should include costs for utility-owned generation and storage that was procured after the 2002 law was passed but is over ten years old. Roscow's proposed decision produces a lower PCIA by excluding it.
That utility-owned generation, largely natural gas generation, is an important factor in the PCIA price now because it supports system reliability.
"The CCA argument against including post-2002 utility-owned generation is even stronger than the one against legacy utility-owned generation because it's supported by law, by 16 years of precedent and by state policy," Chaset said. "The commission has continuously excluded it from the PCIA calculation for CCAs, so the alternate proposed decision’s interpretation sets a new precedent and makes all previous rulings on it wrong."
The precedent was set because the only significant departing load between 2002 and 2010 was the capped departure of direct access customers, which the CPUC wanted to protect, Cushnie said. "As CCAs grew, the commission made it clear utilities could petition for a reconsideration of the ten-year limitation if circumstances warranted it."
With current forecasts that as much as 85% of IOU load could be gone by the early 2020s, "circumstances have clearly changed," he said. "It's not feasible to have the remaining 15% of customers pay for utility-owned generation that provides much of the system’s essential reliability services."
On the precedent question, Peterman concluded the IOUs cannot now be expected to have known the current wave of departing load would strand most of their supply portfolio.
More importantly, she added, CalCCA’s argument of "alleged portfolio mismanagement of post-2002 utility-owned generation would simply place the burden of cost recovery solely on bundled customers." There is "no justification to continue a ten-year limit" on including costs for post-2002 utility-owned generation or energy storage resources in the PCIA calculation, she concluded.
Factor 3: Collars and caps
The alternate proposed decision leaves the current PCIA in place for 2019 and establishes a collar limiting the change in the PCIA value starting in 2020. It caps the annual change at 25%. Roscow's proposed decision sets the 2019 value at no more than $0.022/kWh, limiting the near-term increase, and establishes a collar of $0.005/kWh/year, which would slow the rise of the PCIA more.
"The cap and the collar are important," Chaset said. "It gives me certainty and allows me to plan."
Peterman's 25% cap is close to the $0.005/kW increase in Roscow's proposed decision initially but starts at the much higher current PCIA of $0.029/kWh for PG&E, he said. That means the 2019 PCIA is uncertain and could be too high for CCAs to meet their commitments to customers. It also allows greater growth over time.
"If there's going to be a collar and a cap, we'd prefer the one in the [alternate proposed decision]," Cushnie said. But that works against customer indifference because a true-up against actual market values could find money due to bundled customers from departed customers. That could give "customers opportunities to avoid costs and creates inequities among different customer classes," he added.
Stakeholder testimony convinced Peterman a cap and collar, with regulatory oversight, could work against cost shifts, prevent PCIA volatility and increase transparency. This "supports adoption of a PCIA collar," she decided.
What the gavel will decide
Stakeholders expect a final ruling on how the PCIA should be calculated from the commission any day and a commission vote on it at the September 27 CPUC meeting. The big questions are what phase one will decide, what will be left for phase two, and how both will impact customer choice viability.
Both the proposed decision and the alternate proposed decision report a "general consensus" for "quick but incremental action in the short-term" on the calculation of the PCIA and "portfolio optimization" in the second phase, Chaset said. Portfolio optimization would include ways the IOUs can sell off the controversial utility-owned generation or share it most cost-effectively with other LSEs.
Reforming the calculation of the PCIA is a multistep process, and the proposed and alternate proposed decisions are just the first steps, he added. Calculations of the resource adequacy value, the greenhouse gas emissions-free generation adder and other PCIA factors are not sufficiently handled by either. "The phase one ruling should leave the more difficult challenges to phase two," Chaset said.
Cushnie partially agreed. "The key issue is equity among all customers and protecting customer difference," he said. "If that issue is resolved, phase two will be limited to providing guidance to the utilities on how to manage or unwind their portfolios over time."
That is Peterman’s objective. "The task before us here is an equitable division of the portfolio costs incurred to serve customers who have since departed," she wrote. "Portfolio optimization will be taken up in the second phase."