In Part One, we discussed community choice aggregators (CCAs) and 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.
Let’s take a look now at three main issues with the PCIA.
First, the PCIA has a potentially unlimited duration. This follows from a 2004 California Public Utilities Commission (CPUC) decision allowing utilities to recover stranded costs associated with renewable contracts over the entire term of the contract. By contrast, the recovery period for fossil-fuel contracts is limited to 10 years.
This means that liability for PCIA fees ends only after the last renewable energy contract in a utility’s portfolio expires. PG&E has indicated that customers who switched to CCA service in 2012 and later could continue to see PCIA charges until 2043 due to three renewable contracts signed in 2010 that expire in 2043. Whether customers end up in fact paying a PCIA charge depends on whether the contract prices are above-market in any given year.
The CPUC’s 2004 decision was supposed to encourage utilities to contract for renewables on a long-term basis, thereby supporting renewable energy development. The renewables industry has since matured and CCAs have argued to the CPUC that the recovery period for all resources should be limited to 10 years.
The second issue is that the rate is volatile. As part of its 2016 energy resource recovery account application to establish 2017 rates, PG&E is proposing to increase the PCIA by 24 percent to 2.937¢ per kilowatt hour for customers with a 2012 vintage year. In 2016, the PCIA rate for residential customers rose by as much as 95 percent compared to the previous year’s rates, depending on vintage year.
PG&E has said the increases are due to reasons outside its control, such as lower market prices for both natural gas and renewables. As discussed earlier, the PCIA represents the above-market portion of generation costs, so when market prices fall, the PCIA increases.
To counteract volatility, CCAs are proposing that the market price benchmark for fossil-fuel energy be based on a five-year forward price instead of the current one-year spot price. Utilities, on the other hand, are pushing for changes to the renewable energy and capacity components of the market price benchmark, though not for reasons of volatility. They argue that the market prices yielded by the current methodology are too high, resulting in an underestimation of uneconomic costs. As shown in Figure 1, the market price benchmark for renewable assets is determined in part based on the average cost of RPS-compliant resources coming on line in the current year and the previous year. According to utilities, many contracts starting deliveries in real time were signed many years earlier when prevailing prices for renewable power were significantly higher than what they are now. They are calling for the present formula to be replaced with market indices for California RECs, such as those published by Platts.
The third issue is a lack of transparency around PCIA inputs. Without visibility into the pricing, volumes and terms of the utility contracts that underlie the annual calculation, CCAs are finding it hard to predict values and plan around potential changes to the rates.
As shown in Figure 1, the market price benchmark for renewable energy is based on the average cost of renewable resources in all three IOU portfolios that are starting deliveries in the year in question and the next year. This information is submitted by the IOUs in October each year and used by the CPUC to establish market price benchmark values for rates that take effect on January 1 of the following year.
The information is confidential under CPUC rules. CCAs can gain access through the use of arms-length “reviewing representatives,” who sign non-disclosure agreements with the IOUs limiting what they can reveal to the CCAs. CCAs are finding it hard to find consultants who qualify and are willing to act as reviewers, leaving them to resort to other methods, such as data requests and discovery, meet and confer sessions and motions to compel. The IOUs want to maintain tight confidentiality requirements because they say this information gives away their dispatch strategies, contract terms and load requirements to CCAs that are competing with them for market share. The CCAs have pointed out that they do not sell power to utilities and so cannot use price and contract information to utilities’ or bundled customers’ disadvantage. In addition to advocating for more relaxed data access rules, CCAs have also asked that IOUs provide 10-year forward forecasts of total portfolio costs and portfolio mix as these factors also influence the annual adjustment.
In its 2012 decision establishing the current PCIA methodology, the CPUC explicitly left open the possibility for reform. The commission said it would be willing to modify the calculation methodology and process based on changed circumstances in order to ensure that community choice aggregators can compete on a fair and equal basis with IOUs. Indications are that the CPUC will be receptive to proposals to reform the methodology.
In March 2016, the CPUC’s energy division held a workshop bringing together IOUs, CCAs, representatives of direct access consumers and other stakeholders to discuss PCIA reform. Proposals ranged from what can be considered granular revisions to the methodology to more fundamental, structural changes to the utility model.
One of the more fundamental proposals is to replace the annually adjusted PCIA with an up-front, fixed valuation for each vintage year. The valuation would be negotiated and agreed in a formal settlement between each CCA and the relevant IOU, and be subject to approval by the CPUC. CCAs want the flexibility to pay the fixed fee on a lump-sum basis and recover the cost from their ratepayers or amortize the payment over a period so as to cap annual increases at a fixed level.
Los Angeles County is proposing more structural changes in light of the large departure of load that would be caused by its anticipated CCA program. It argues that the appropriate way to allocate procurement costs is to transfer power contracts from the IOUs to CCAs, replace IOUs with CCAs as providers of last resort and grant CCAs reciprocal powers to charge exit fees to departing customers to recoup uneconomic generation costs. (Los Angeles County is different from the City of Los Angeles, which has its own municipal utility.) The CPUC may not have jurisdiction to require transfer of contracts, however, so this proposal may require legislative action that is not considered likely. Furthermore, the question of which contracts will be subject to assignment and whether counterparties will agree to assignment are issues that would need to be worked out.
Following the workshop, the energy division issued a report summarizing the discussions, but declined to adopt any of the proposals. Instead, it has invited stakeholders to petition the CPUC for the changes they would like made.
This article was originally published in Chadbourne & Parke’s Project Finance NewsWire and was republished with permission.