The customer choice movement in California is about to take a giant step, but it has two starkly different choices regarding which direction to go.

The movement is driven by the promises of more locally developed renewables and lower rates than investor-owned utilities (IOUs) can deliver. But California’s Customer Choice Aggregations (CCAs) can only deliver on those promises if they resolve the question of who will pay for the generation procured by IOUs to serve customers now departing to CCAs.

One new direction for how to cover that cost was recommended April 2 by California’s IOUs in a filing with the California Public Utilities Commission (CPUC). An even newer direction was proposed in a filing the same day by CalCCA, the organization that represents CCAs.

Their movement resulted from a 2002 law that allows CCAs to act as load serving entities (LSEs) for IOU customers. There were nine CCAs serving load in California at the end of 2017, and 12 more are expected to launch this year, according to CalCCA Executive Director Beth Vaughan.

By the end of 2018, CalCCA forecasts more than 4.5 million CCA customer accounts, Vaughan told Utility Dive. Large electricity users can also become direct access customers by obtaining their power from independent energy service providers (ESPs).

A 2017 white paper from the California Public Utilities Commission (CPUC) reported that more than 85% of the state’s retail load could be served “by sources other than the IOUs” by the middle of the 2020s.

This is a looming market disruption of unprecedented proportion.

One knotty problem

The one knotty problem of who will cover the IOU's costs stands in the way. It is knotty because utility-owned generation (UOG) was typically procured by IOUs, often under state mandates or regulations, at higher costs than CCAs pay today to procure generation for their customers. 

Resolving that knotty question will require a new Power Charge Indifference Adjustment (PCIA). The PCIA is a bill charge that compensates IOUs for generation procured in the past at what are now above-market prices to meet anticipated electricity demand being lost to CCAs.

Because the present PCIA calculation is based on an estimate of the future market value of each IOU’s portfolio, it is imprecise because the estimated values only approximate actual market prices and costs. Both CCAs and IOUs argue that disadvantages them. IOUs claim the approximation undercompensates them. CCAs claim it overcharges them.

In June 2017, the debate over the best way to calculate the PCIA turned into CPUC proceeding R. 17-06-026. The uncertainty created by the still unresolved proceeding has inhibited procurement by both IOUs and CCAs, essentially idling California’s utility-scale renewables developers.

Stakeholders on both sides in the proceeding say it is urgent to restart renewables development because federal tax credits for wind and solar will soon step down. That will make it more expensive for the state to meet its rising renewables mandate and use renewables to replace its soon-to-be-shuttered 2,200 MW Diablo Canyon nuclear plant.

A Joint Utilities (JU) April 2 filing proposed an innovative methodology that eliminates the estimated value in the PCIA with actual market costs and benefits. The JU are Pacific Gas and Electric (PG&E), Southern California Edison (SCE) and San Diego Gas and Electric (SDG&E), the state's three dominant IOUs and electricity providers.

A CalCCA proposal is even more innovative. Its methodology combines securitization of IOU assets, an auction mechanism and revisions to the PCIA definition to get at actual costs and benefits.

Elements of the CalCCA proposal are “worthy of serious consideration,” Matthew Freedman, staff attorney for consumer advocate The Utility Reform Network (TURN), emailed Utility Dive. It is “an innovative approach to lowering costs for all ratepayers,” he wrote.

Regulators are expected to end the debate by the end of the summer. The future of the choice movement hangs in the balance.  

The joint utilities proposal

The JU proposal eliminates estimates. It uses actual market prices where it is practical to do so and actual costs where that is a more workable approach.

When it functions as designed, the PCIA should balance costs appropriately between customers who depart to CCAs and remaining utility customers, according to a PG&E statement.

But an “imbalance,” due to the way the PCIA is calculated, allowed CCA customers to pay only about 65% of what PG&E calculates they should have paid for its 2017 generation costs. That resulted in about $180 million in costs being imposed on remaining utility customers, PG&E reported. That could grow to $500 million by the early 2020s.

The forecast in the PCIA calculation makes it “inherently inaccurate,” the filing by the JU reports, because forecasts depend on estimated values instead of actual prices or costs. Their new proposal expands on the Portfolio Allocation Methodology (PAM) mechanism, which they put forward last year to correct the imbalance by replacing the forecast of market value with actual prices.

Their new Green Allocation Mechanism (GAM) and Portfolio Monetization Mechanism (PMM) divide the elements of the PAM, according to PG&E spokesperson Ari Vanrenen.

The GAM would be used to allocate costs and benefits of long term energy contracts for renewables and large hydro resources, she told Utility Dive. The PMM would be used for fossil fuel and nuclear resources.

“We would give CCAs the actual attributes of the renewables and large hydro resources rather than selling them on behalf of the CCAs or retaining them for PG&E’s customers,” Vanrenen said. “The CCAs would pay the utilities the actual cost of the resources and attributes, and they could use them to enhance their existing portfolios or start new portfolios.”

For fossil fuel and nuclear generation, “the utility would sell the attributes of those resources on behalf of CCAs through an approved sales process,” she said. Using the PMM, the utilities “would charge CCA customers for the total cost minus any residual revenues.”

It is important to also use actual values for attributes like Renewable Energy Credits and Resource Adequacy, the JU filing reports.

The GAM “retains the PAM concept of a pro rata allocation of benefits and net costs,” the filing adds. The PMM “is similar to the Current Methodology in that it only collects the pro rata share of above-market costs of the PMM resources from departing load customers.”

The new proposal does not use “administratively-set benchmarks to estimate the above-market costs of the portfolio,” the filing reports. Instead, it uses “actual market transactions to calculate the cost responsibility of departing load customers and establishes an annual true-up of above-market costs.”

This protects the right of electricity customers to stay with a CCA or choose an ESP, Vanrenen said. But “the costs and benefits of the utility investments would be shared with all the customers they were built for.”

Under GAM, “costs recovered from all customers, including departing load customers, will equal the actual costs incurred,” the filing reports. That includes “contract costs owed to the generators, UOG capital costs and California Independent System Operator (CAISO) generation-related charges."

Actual revenues received from the markets would be “allocated pro rata to all customers,” the filing reports. The “attributes” of renewables and large hydro resources, like ancillary services and resource adequacy, would be allocated “pro rata” to the CCAs and ESPs that sell the electricity.

“The cost recovered from departing load customers will equal their pro rata share of the above-market costs of the PMM portfolio,” the filing continues. Those costs include energy, ancillary services and resource adequacy.

CCA innovations

Despite the debate about the PCIA, CCAs are pushing ahead on renewable generation procurement, according to CalCCA’s Vaughan. They had 1,136 MW of new renewables in construction in January 2018 and expected online by 2021. It is big progress for the new and still financially uncertain CCAs, but a fraction of the 2.4 GW already built by the state’s IOUs. Only a resolution of the PCIA question will free up real generation growth.

The Joint Utilities argue that imposing more of the above-market cost for existing generation on CCA customers eliminates a shift of the cost for UOG to customers who remain with the IOUs. California law prohibits “cost shifts” between customer groups,” SCE spokesperson Robert Laffoon-Villegas emailed Utility Dive.

The CalCCA filing disputes the Joint Utilities' conclusion that there is a cost shift. Based on “flawed methodology” used by the CPUC, PG&E “has publicly claimed an annual cost shift of $178 million,” CalCCA says.

“The analysis is based on untenable assumptions,” CalCCA adds. “A roughly equivalent cost shift of $173 million in the other direction — from bundled customers to departing load customers — can be calculated by changing only two assumptions using values approved by this Commission.”

The actual numbers “are probably somewhere in the middle,” Vaughan said. “We want to figure out those numbers.”

CalCCA’s proposal essentially reinvents the handling of existing generation. “It shrinks the pie and the pie is the IOUs’ PCIA-eligible portfolios,” Vaughan said. “This would reduce the cost of electricity for all customers.”

There are three elements to the CalCCA plan. One is a voluntary auction for older-vintage, above-market-cost PCIA-eligible power purchase agreements (PPAs). CCAs could acquire those IOU contracts. The price would likely be less than the IOUs’ original PPA prices but support CCAs in building their renewables portfolios, Vaughan said. It would also reduce IOU stranded costs.

TURN’s Freedman said the above-market-cost of utility PPAs is the major factor in the PCIA. Allowing CCAs direct access to them could be a solution, if priced equitably, he added.

A second element in the CalCCA proposal is optimizing utility portfolios through modifications to the PCIA calculation. The modifications include using a long-term resource adequacy capacity value, a more accurate value for providing emissions-free generation, recognizing the value of ancillary services and the value of a wider set of resources, and excluding uneconomic costs.

The third element, securitization of utility assets, could be controversial.

Securitization

CalCCA proposes allowing – but not requiring – the rate-based UOG in the IOUs’ PCIA-eligible portfolios to be securitized.

Securitization is a financing tool that replaces debt at a high interest rate with debt at a low interest rate, said CEO Joe Fichera of Saber Partners, the financial firm that assisted CalCCA with the proposal.

Long-term, low-risk bonds secured by UOG would be sold to investors. Because customers typically pay their bills, the bonds would be AAA rated and the interest rate paid by the IOUs would be low, Fichera told Utility Dive. Investor returns would be repaid through a special dedicated component of rates that would go almost directly to bondholders.

IOUs could do two things with the resulting cash infusion to reduce their costs, Fichera said. They could either pay off their existing, lower-rated, higher-interest debt or invest in less expensive generation and infrastructure.

“The calculation of the adjustment charge includes the cost of financing the assets that generate electricity,” Fichera said. “Lowering that cost lowers the charge.”

“Securitization of the PCIA-eligible UOG rate base could potentially produce net present value (NPV) savings to PG&E customers from $1.3 to $1.6 billion,” according to Saber calculations reported in the CalCCA filing. Savings to SCE customers would be “approximately $589 million.”

“Additional savings may also be achievable through the an [sic] average price reduction of $0.13/kWh for 2,000 GWh/year of purchased power,” Saber found. Assuming a securitization cost of $0.094/kWh produces “net savings of $0.36 cents/kWh in the first year” and “could result in NPV savings to bundled, CCA and direct access ratepayers of $449 million.” 

Many IOUs have effectively made use of securitization, Fichera said. “PG&E used it in the mid-2000s to reduce the interest on a $1.3 billion bankruptcy obligation.”

IOUs may not want to reduce the costs of capital that go to shareholder earnings and that is reasonable, he added. “It should not be forced on them, but why not make it available?”

This is not securitization of risky assets in highly leveraged situations that was at the core of the 2008 recession, Fichera said. “Securitized utility assets went through the credit crisis and were never downgraded.”

TURN’s Freedman speculated that the IOUs would reject securitization. “They won’t like the idea of reducing their rate-based investments.”

SCE confirmed his speculation. Securitization is not a “practical” or an “effective” solution, Laffoon-Villegas said. It would require legislative authorization and shift the cost for the securitized assets to a “future generation,” he told Utility Dive. And “securitization would not eliminate the PCIA because it would apply to only a subset of SCE’s portfolio.”

Vanrenen said PG&E is reviewing all proposals and will respond in written comments, which are due by the end of April. Hearings will follow, from May 7 through 11. A proposed decision is scheduled to come by late July and the final decision by the end of the summer.