Community choice aggregators (CCAs) could displace as much as 20 percent to 40 percent of electricity load in California. They are a new kind of offtaker of renewable power.
The utilities are bracing for the loss of so many customers and charging exit fees for customers that leave the utilities for CCAs to cover their stranded costs. There is controversy surrounding the calculation of the exit fees. CCAs must take the exit fees into account when figuring out how much they can charge customers for electricity and still have an economic proposition.
This article explains how exit fees are calculated, what issues have been raised about the current methodology and proposals for reform.
What is a CCA?
A CCA is a legal entity, usually a joint powers authority, formed by one or more counties, cities or towns for the purpose of purchasing power on behalf of the residents and businesses within their boundaries. The incumbent utility, which no longer provides the electricity, still remains responsible for transmitting and distributing the power, as well as for billing, collections and other customer services. Laws enabling this structure have been passed in California, Illinois, Massachusetts, New Jersey, New York, Ohio and Rhode Island.
In California, CCAs are subject to the same renewable procurement targets as investor-owned utilities under the state renewable portfolio standard program. At least 50 percent of retail electricity sales must come from qualifying renewable sources by 2030. However, in reality, CCAs strive for even higher levels of renewables by offering customers the option to purchase electricity that has a 100 percent renewable energy content. The default power mix offered by IOUs is currently around 29 percent renewable.
The focus on renewable energy makes CCAs a significant new class of offtakers, and the power purchase agreements they sign can provide the basis for financing new projects.
(For a further discussion of the financeability of PPAs with CCA offtakers, see Another Potential Offtaker: Community Choice Aggregators.)
CCAs in California
Although community choice aggregation is legislatively enabled in seven U.S. states, California has seen the most traction. Table 1 provides an overview of operational and emerging CCA programs within the state.
There are now five operational CCA programs in California, and at least 15 more are in various stages of planning, all together covering 23 counties.
Of the planned programs, Los Angeles County and San Diego City are ones to watch. If all eligible cities participate in LA County’s program, at full enrollment it will account for approximately 40 percent of Southern California Edison’s total load. (SCE itself accounts for about 27 percent of aggregate state load.) San Diego City accounts for roughly 44 percent of San Diego Gas and Electric’s total load. Pacific Gas & Electric has already begun to reduce its annual procurement targets to account for existing CCAs within its service territory as well as large planned programs like the one in Alameda County. PG&E’s latest procurement plan forecasts an incremental loss of 15,444 GWh in 2017 due to CCAs, the equivalent of 21 percent of its 2016 load.
As scores of communities in California explore the idea of forming CCAs, IOUs are facing the prospect of substantial stranded costs and the need to recoup these costs by charging departing customers large exit fees.
Exit fees are designed to cover costs of power procurement investments made by utilities on behalf of customers who later switch to CCAs or other alternative electricity suppliers. These costs would have been recoverable through electricity rates but become stranded when the customers leave. Exit fees are also referred to as non-bypassable charges because they cannot be bypassed by switching service providers.
The policy underlying exit fees has its roots in legislation passed in 2002 as part of electricity restructuring. When the electricity markets were restructured, the California Public Utilities Code was amended to provide that each retail end-use customer should bear a fair share of electricity purchase costs and obligations incurred by utilities on behalf of those customers and that there should be no shifting of costs from exiting customers to remaining customers. This policy was affirmed in S.B. 350 enacted in September 2015, which provides that bundled retail customers of an electrical corporation shall not experience any cost increase as a consequence of implementing a community choice aggregator program.
In 2006, the California Public Utilities Commission (CPUC) established a special kind of exit fee known as the power charge indifference adjustment, or “PCIA,” that applies to CCA customers and customers of other non-utility energy providers under the California “direct access” program. A different non-bypassable charge applies to customers of municipal utilities. The objective of the PCIA is to ensure that the remaining utility ratepayers remain economically indifferent, meaning no better or worse off as a result of customers switching from IOUs to CCAs.
The prevailing PCIA rate charged by PG&E is between 2.072¢ and 2.363¢ per kWh for residential customers, who make up the bulk of CCA customers. (The range is due to different vintage years.) For a typical residential customer using 500 kWh of electricity per month, PCIA charges will amount to about $11 a month. Because CCAs only offer generation services, the difference between their generation rates and the utilities’ generation rates is the only basis upon which they can compete with utilities. The PCIA, which is assessed on a customer’s bill as a generation charge, therefore directly cuts into a CCA’s competitive margin. To remain competitive, the CCA must procure power at a rate that is lower than the retail rate charged by the local utility plus the PCIA.
Figure 1 shows how the PCIA is calculated.
The PCIA is determined on an annual basis by comparing the actual costs of the utility’s portfolio of assets to the market value of those assets. Utilities cannot recover the entire cost of procurement, only the uneconomic portion, the idea being that they should mitigate losses by selling excess energy and capacity into the market.
The market price benchmark is a proxy for the market value of electricity. It is made up of a brown adder, green adder and capacity adder. These adders are estimates of the market value of fossil-fuel energy, RPS-compliant energy and resource adequacy (grid stability) obligations respectively.
If the total portfolio cost exceeds market cost, then the difference represents the uneconomic costs. If the costs of a portfolio are below market costs, then the difference is negative and effectively represents a credit due to the CCA customers. Negative amounts are “banked” or carried forward by the utility and used to offset the next year where there is a positive difference.
A customer is responsible only for net costs of commitments that were made before the customer departed utility service. The year the customer departed utility service is known as the customer’s vintage year. The rule is that the customer is responsible for resources committed by the utility prior to June 30 of the customer’s vintage year. Power contracts are considered committed when the contract is executed and physical resources are considered committed when construction begins.
In Part Two, we discuss some of the issues related to the PCIA and the possibilities for reform.
This article was originally published in Chadbourne & Parke’s Project Finance NewsWire and was republished with permission.