California settles CCA exit charges
The California Public Utilities Commission issued a highly-anticipated decision in October revising the formula for calculating exit fees that the three investor-owned utilities in California can charge customers who leave the utilities to become customers of community choice aggregators and other retail power suppliers.
The exit fees may determine how many customers move ultimately to CCAs.
The CPUC staff estimated last year that as many as 85% of California electricity customers may abandon the utilities by the mid-2020s for CCAs and other retail suppliers. Forecasts are for 25% of California electricity customers to be served by CCAs and other non-utility suppliers by the end of 2018.
The commission made changes that are expected to lead to an increase in the exit fees charged by the utilities, but it also set a cap on the potential increase. The decision tees up a second phase of the proceeding to consider competing arguments over how best to redistribute resources in the utilities’ portfolios given a significant over-supply situation facing the utilities.
CCAs are legal entities formed by cities, counties or a combination of cities and counties in order to provide electricity to local residents.
The incumbent utility, which no longer provides the electricity, still remains responsible for transmitting and distributing the power, as well as for billing, collection and other customer services.
The California legislature authorized the creation of CCAs in 2002 with the passage of AB 117. The first CCA was formed in 2010 and, since 2016, CCAs have been rapidly proliferating all over the state. Seven new CCAs have launched this year alone, bringing the total number to 19.
California law requires that the utilities’ remaining customers be held harmless from the departure of other customers for a CCA.
Given the potential for huge load defection, the commission has been wrestling with what exit charges to require customers who abandon the regulated utilities to pay to help cover the cost of stranded assets that the utilities are left holding.
The commission determines annual values for the “power charge indifference adjustment” or PCIA (the formal name for exit charges) for Pacific Gas & Electric, Southern California Edison and San Diego Gas & Electric in each utility’s annual energy resource recovery account forecast proceeding. In the years since adoption of the PCIA methodology, dissatisfaction has grown among the utilities and CCAs, both with the methodology of calculating the PCIA as well as with its numerical outcomes. In June 2017, the commission issued an order opening a rate-setting proceeding to review the current PCIA methodology. Over the course of the ensuing 14 months, the commission received comments from 28 entities or groups.
Pared down to its essence, the PCIA is a calculation of the above-market costs of power contracts and utility-owned generating assets that are no longer needed by the utilities to serve departing load. Above-market costs are calculated by subtracting market value from gross costs of the relevant resources. Underlying most disputed issues in the proceeding was the question of portfolio valuation or determination of market value. The methodology for calculating market value varies depending on whether the resource is fossil-fuel based, renewable or resource adequacy. As discussed in further detail below, the commission made four changes to the former methodology.
Valuation of resources
The first change was to revise the inputs used for calculating the market value of renewable and resource adequacy resources in utility portfolios.
Instead of relying on administratively-set benchmarks, renewable resources will now be assigned a value based on actual prices for purchases and sales of renewable energy by the three investor-owned utilities, CCAs and electric service providers.
Beginning in 2019, to ensure the commission has access to the necessary data to support the calculation, all retail electricity providers will be required to submit (under seal) price, volume and quantity data for purchases and sales of renewable electricity to the commission on an annual basis by January 31. The commission will then calculate market values based on transactions entered into during the year two years before the forecast year for delivery in the forecast year. For example, the PCIA for 2021 (which is calculated in 2020) will use data from transactions concluded in 2019.
Similar to renewables, resource adequacy resources in the utility portfolios will now also be assigned a value based on the sale price for such resources. A resource adequacy resource is a capacity commitment (utilities, CCAs and other load-serving entities must show state regulators that they have enough capacity commitments to be able to meet all of their customers’ energy requirements plus a minimum reserve requirement). The data will be pulled from the commission’s most recently published resource adequacy report, which compiles price data provided by retail electricity providers on a confidential basis. For example, the 2017 resource adequacy report reflects data from 5,347 monthly contract prices reported by the three investor-owned utilities, 14 other retail electricity suppliers and 12 CCAs.
The second change the commission made was to order the utilities to conduct an annual true-up process to reconcile differences between the actual versus the forecast above-market value of PCIA-eligible resources.
Each utility will need to establish a balancing account with three sub-accounts to track the costs and revenues associated with fossil fuel, renewable and resource adequacy generating resources.
At the end of the year, the net costs of PCIA-eligible resources will be calculated based on the recorded gross costs of the resources minus the revenues such resources earn in relevant markets, as tracked in the balancing accounts.
Any year-end under-collection or over-collection will be incorporated into the PCIA rate calculation in the following year.
The third change the commission made was to adopt a cap limiting increases in the PCIA from one year to the next to 0.5¢ a kilowatt hour. In the past, significant annual swings in energy prices have led to significant annual swings in the PCIA rate, making it challenging for the CCAs to engage in long-term resource planning. The cap is supposed to protect against such volatility.
The commission also authorized prepayment of the PCIA.
CCAs now have the option of prepaying the PCIA on a one-time basis on behalf of their customers so that the customers will be relieved of the PCIA burden going forward.
This approach has some historical precedence. In 2007, the commission directed the investor-owned utilities to permit California municipal utilities to prepay departing load obligations as a negotiated lump sum (see CPUC Resolution E-3999).
Several commentators noted that in practice, making a prepayment will be tricky because of the uncertainty involved in forecasting the above-market costs over an extended time frame. However, the commission emphasized that it was not requiring the utilities to accept any estimate of a customer’s long-term cost responsibility, only that they negotiate in good faith with counterparties.
Any prepayment arrangements will need to be submitted to the commission for approval on a case-by-case basis.
The fourth change the commission made was to lift an existing limit on cost recovery to costs incurred during the first 10 years of operations for utility-owned power plants built or acquired after 2002.
The trade association CalCCA, which represents all of the operating CCAs in the state, says lifting the 10-year limit will cause system-average PCIA rates for 2019 to increase by 17% for PG&E and 42% for SCE. The commission tried to mitigate against such increases by requiring utilities to recognize CCA load in their resource planning and directed they not sign power purchase agreements that might create new liabilities where available information suggests the power might not be needed.
The commission will now turn to considering longer-term solutions to redistribute excess power supply held by the utilities in phase two of the proceeding.
Several proposals are on the table.
One is to hold an auction in which power purchase agreements held by the utilities would be sold to CCAs. Another is to assign the utility power contracts to the CCAs.
A third proposal recommends allowing the utilities to securitize buy-outs and buy-downs of contracts the utilities signed to comply with the state renewable portfolio standard through a bond offering and then pass through the bond payments in customer rates. Under such deals, a party selling power to the utilities would accept cash consideration in exchange for terminating a PPA (in the case of a buy-out) or in exchange for reducing the price for electricity sold during the remaining years of the PPA term (in the case of a buy-down). The costs of such buy-outs or buy-downs would be recovered through a special surcharge on utility bills. The utilities would issue bonds backed by ratepayers’ obligations to pay the surcharge.
Utility bonds are considered very low-risk due to the non-by-passable nature of the surcharge supporting the debt. As such, they pay lower interest (around 3% to 4%) than the utilities’ cost of capital (around 7.5%). According to the trade association CalCCA, this approach has been successfully implemented in New Hampshire and authorized for use in Vermont. California also used a similar approach to cover utility stranded costs after the California energy crisis in the early 2000s.
Impact on power projects
Lenders and investors in private power projects that have power contracts to sell electricity to CCAs are aware of the risk that the exit charges could drive customers back to the regulated utilities.
In the face of this risk, some lenders require cash sweeps in credit agreements that get triggered if customer opt-out rates increase beyond a certain level measured from negotiated baseline levels.
The commission’s decision could be seen as lessening the risk of opt-out because, among other things, it places a cap on year-on-year increases in the PCIA and allows one-time prepayment of the PCIA. The commission itself noted that the new methodology ensures a reasonably predictable outcome in the level of the PCIA, which will provide certainty and stability for all customers within a reasonable planning horizon.
It remains to be seen whether lenders will be willing to relax their requirements tied to changes in opt-out levels.
In terms of PPAs, it is too early to tell if the commission’s decision will affect pricing.
In terms of credit support, CCAs have historically resisted posting security and providing collateral support to sellers under PPAs despite credit and regulatory risk, and we do not expect the commission’s decision to affect this position.
On an operational basis, the historic volatility of the PCIA has led many CCAs to establish significant reserves and rate stabilization funds to buffer rates in the event of increases to the PCIA so that the CCAs can remain cost-competitive with the utilities. If CCAs perceive the PCIA as less volatile and more predictable following the commission’s decision, then some of these funds could get re-deployed toward investments in energy and infrastructure projects and wholesale power procurements.