Can California stakeholders meet the ultimatum issued by California Public Utilities Commissioner Carla Peterman at the close of the January 2016 sessions in California’s Net Energy Metering 2.0 proceeding?

“It is clear the commission is not comfortable with the variety of value and cost estimates for this resource,” she told the gathered solar industry and investor-owned utility representatives. Things that increase the cost shift from owners of distributed generation to other utility ratepayers are of "serious concern," she warned, even as she voted to temporarily leave the existing retail rate net energy metering (NEM) credit in place.

The commissioners are “troubled” by the diverging values for solar put forward by stakeholders in California’s landmark NEM 2.0 docket (14-07-002) and "we need to get to a number by 2019,” she told them. By that, she meant the commission expects a specific valuation for the electricity distributed generation owners export to the grid.

Since Commissioner Peterman's ultimatum, stakeholders have worked at many ways to value that generation, but have reached only a range of possible formulations.

Stakeholders debate a successor tariff

Utilities assert that more than 725,000 California electricity customers with net metered distributed generation shift costs for the system’s infrastructure and maintenance to non-distributed generation owners. Solar advocates argue the perceived cost shift disappears if all distributed generation's values are included in the cost calculation.

Since Commissioner Peterman’s ultimatum, stakeholders in California Public Utilities Commission (CPUC) proceedings on distributed energy resources (DER) have wrestled with the value question. Yet disagreement remains over what factors belong in the locational net benefit analysis (LNBA).

The LNBA is a comprehensive and complex methodology for valuing generation. It assumes generation at some locations, like where there is grid congestion, is of greater value to the system. 

California think tank Gridworks leveraged the influence of members like former CPUC Commissioner Mike Florio, who voted against the 2016 decision to extend NEM, to hold informal stakeholder talks on a successor tariff. It centered on five options to replace NEM in 2019.

Gridworks Executive Director Matthew Tisdale, a former CPUC staffer who led commission DER initiatives, authored “Sustaining Solar Beyond Net Metering,” based on those discussions.

Participants told Utility Dive the talks resulted in an increased understanding of one another's positions in the debate.

There was significant agreement among participants that NEM drives customer adoption but does not optimally align supply and demand,” Tisdale told Utility Dive.

There was disagreement on key questions about LNBA-derived values for distributed solar, about separating compensation for customers' use of their own generation and what they export to the grid, and about the value of distributed solar-supplied grid services to power markets, he added.

Because there is so much disagreement, "just getting the utilities and the solar companies together was a small miracle,” The Utility Reform Network (TURN) Senior Staff Attorney Matthew Freedman told Utility Dive. 

On one question, however, there is complete stakeholder agreement, Utility Dive interviews found: Sooner or later, retail rate NEM must go. But solar advocates say later, utilities say sooner, and therein hangs the tale.

The fight over the first option

NEM has driven nearly 6 GW of installed distributed solar capacity in California and it could become 16 GW by 2030. But that growth would aggravate two challenges already stressing the state's grid. One is midday solar over-generation burdening distribution systems. The other is a resulting over-reliance on natural gas generation to meet the spiking evening peak as the sun sets.

To drive solar growth in a way that supports the grid, the CPUC, in its decision to extend the successor tariff search to 2019, asked its staff to study alternative mechanisms to compensate distributed generation owners for exported generation.That compensation should account for “locational and time-differentiated values,” stakeholders and the commission agree.

The first option discussed in the Gridworks paper, referred to as NEM 2.0, was the existing retail rate NEM, with just-added time-of-use rates ordered by the CPUC in a separate proceeding,Tisdale's paper reports. The time-of-use rates, already in effect for some distributed generation owners, are intended to provide an actionable price signal to customers that matches grid needs.

Solar advocates say 2019 is too soon to eliminate retail rate NEM, especially with new factors threatening the solar value proposition. California's investor-owned utilities and ratepayer advocate say it is time to address the cost shift from distributed generation owners to other customers.

Sunrun Chief Policy Officer Anne Hoskins, Borrego Solar Senior Policy Director Ilan Gutherz and Vote Solar Regulatory Issues Managing Director Sachu Constantine agreed NEM is presently the best choice. Customers and the solar industry now face a solar import tariff and are just beginning to learn how to navigate the time-of-use rates, they argued.

Already solar growth numbers are dramatically off, Hoskins emailed Utility Dive. The 2017 installed capacity is 53% below the GTM Research forecast and the 2018 forecast has been reduced 57% due to the federally-imposed solar tariff and complications introduced by the time-of-use rates, she said.

San Diego Gas and Electric (SDG&E) spokesperson Joseph Britton said NEM took rooftop solar from a “nascent technology” to a “broadly adopted” one in 20 years. But it is time to “move past” it to one that “fairly balances the interests and needs of all customers,” he emailed Utility Dive. Pacific Gas and Electric spokesperson Ari Vanrenen and Southern California Edison VP Caroline Choi agreed.

NEM worked well for the solar business because it is easy to explain. “But that simplicity has translated into an intolerable cost subsidy,” Choi told Utility Dive. “Another pricing mechanism could be relatively easy for customers to understand but not shift costs to other customers.”

New options

TURN’s Freedman said NEM is a “non-starter.” TURN favors the paper’s “buy all, sell all option.” With it, customer-exported generation would be compensated at its locational value and distributed generation owners would pay the retail rate for all electricity consumption. 

Buy-all, sell-all (BASA) is probably “not politically sellable” but is a starting point in the debate, Freedman said. “We really want a rational pricing mechanism that links what customers are paid for exported solar over a fixed time-period to the value it provides to the grid.”

But Vote Solar’s Constantine called the paper’s buy-all, sell-all options “not acceptable” for residential customers because it eliminates the opportunity to offset the retail price for electricity with self generation.

Other new options include net billing and versions of buy-all, sell-all and net billing that include compensation for grid services.

Gridworks endorses net billing over the other options, Tisdale said. Net billing allows customers to use their own distributed generation output to offset retail-priced electricity use. Excess generation exported to the grid would be compensated at an LNBA-determined value.

“Locational value is dynamic,” Tisdale said. To balance it with the certainty investors need, customers would get net billing at the LNBA value for a fixed period long enough to support investment. “Then compensation is dynamic,” he said.

The 2018 net billing compensation could be different than the 2019 net billing compensation at the same location, he acknowledged. “The different vintages and tranches of solar reflect the changing needs of the grid. If LNBA correctly reflects those changing needs, it would encourage investment where and when it is needed.”

Vote Solar’s Constantine said net billing “could in principle balance the interests of the grid operators, solar customers, and non-solar customers.” But NEM should not be “consigned to history” until distributed generation penetrations impose a calculated and significant cost shift and the LNBA is “vetted by the market,” he added.

Sunrun’s Hoskins and Borrego Solar’s Gutherz agreed on the latter points. “Before we impose location-based elements on top of time varying rates, we need to make sure customers can understand the rates and respond to them appropriately,” Hoskins argued.

SCE's Choi also expressed doubts about LNBA-valued compensation, but for different reasons. “It could be administratively difficult,” she said. And the utility’s assessment is that “the locational differentials are not significant enough to add the additional complexity.”

TURN’s Freedman added that LNBA-valued DER could cause other distortions if it is above or below the real value distributed generation brings the system.

Net billing special features

The Gridworks-envisioned net billing option would include two credits to make compensation more workable for the solar industry and utilities.

One is a Market Transition Credit. It would guarantee compensation during the tariff transition, and then step down. “The scale and pace of the step down could be benchmarked to installed capacity,” the paper suggests.

The other is a Transferrable Credit that would allow LNBA-valued compensation earned by distributed generation owners to be credited to “any other customer.”

Tisdale said transferrable credits “take the edge off the location differentiation.” Because they can be transferred, “the investor does not have to be where the solar is to invest in solar,” he said. “The intention is to eliminate financial liquidity issues that would limit investment in solar where it is valuable to the grid.” With transferable credits, he added, “no customer is excluded.”

Both Vote Solar’s Constantine and Borrego Solar’s Gutherz endorsed credit transferability.

It is “critically important for California” because so many customers do not have access to solar, Gutherz said. It will also “help to make many solar energy projects more financeable.”

But Sunrun’s Hoskins argued transferable credits would add unnecessary complexity. TURN’s Freedman agreed, and added that it could lead to over-sizing distributed generation systems.

A last option adds compensation for grid services to the buy-all, sell-all (BASA) option. DER advocates argue that where it can help meet grid needs through aggregators, it should be compensated at the market rate. Such compensation would be an alternative to administratively-set export prices.

The paper proposes a demand charge that could be used with several options. “Demand charges are generally problematic, but this "Managed Demand Charge" is designed with customers in mind,” Tisdale argued.

“The objection to demand charges, which are used by utilities as cost recovery mechanisms, is that they are not predictable and can't be managed by residential customers,” he said. “This one assumes they will have the tools to anticipate grid needs, use their distributed generation to meet them, and avoid additional costs.”

If it is correctly designed, there would be no extra costs to the utility and therefore no need to recover costs through demand charges, Tisdale added.

SCE’s Choi said the utility’s rate experts agree. “The concept is workable. We already have rates of that type in place and working effectively.”

But Sunrun’s Hoskins and TURN’s Freedman unequivocally rejected the demand charge concept, agreeing it would not be manageable for residential customers because they lack the time and tools to manage the details of their usage.

Three outcomes for net billing

There are three potential outcomes for the net billing recommended by Gridworks, Tisdale said. 

If LNBA-valued compensation provides a return that is better than buying electricity from the grid, customers will adopt solar or solar-plus-storage where it is best for the grid. That will strengthen the system and lower customer costs system-wide.

If LNBA-valued compensation does not provide that adequate return, “the value of self-supply with solar-plus-storage is maximized,” he said. Then it becomes financially advantageous for customers to consume their solar-generated and battery-stored generation during peak periods instead of taking electricity from the grid.”

That also “creates a positive tension between the utilities' retail rate and the cost-of-storage curve and is a clear market signal for further investment in storage,” he added.

The solar advocates and SCE’s Choi agreed the price of storage will be crucial to the successor tariff discussion. But Choi, Gutherz and SDG&E’s Britton stipulated it is also of primary importance that the successor tariff be technology neutral so as to avoid giving an advantaging to storage over other current or emerging technologies.

The outlook

Tisdale said the Gridworks discussions showed that utilities see net billing as “a step in the right direction because it breaks the link between exports and retail rates.” It creates marketing challenges for solar providers, he acknowledged. But there is “a growing alignment on the differences between them and the [investor-owned utilities].”

SCE’s Choi agreed. “We are now sharing customers with solar and other distributed technology providers,” she said. “We see transformations throughout our industry and we are getting on board because that's what our customers want.”

Vote Solar’s Constantine said that, in time, net billing could be a “manageable solution” for both sides. But no successor tariff should be implemented “until an agreed upon solar penetration threshold is met,” he added. Only that agreement would assure that all parties accept that there is a cost shift significant enough to need addressing.

TURN’s Freedman said the investor-owned utilities “are being pragmatic to support a successor tariff” because it will inevitably be better than NEM.

Tisdale said NEM “has been gospel for the solar industry because the retail rate kept going predictably up and costs were coming predictably down.” But the federally-imposed import tariff means costs may not continue going down. And the new time-of-use rates may prevent the retail rate from continuing to go up.

“Context matters,” he said. “The leveling or potential reversing of those trends has people more open-minded about delinking compensation and the retail rate.”