NewEnergyNews: TODAY’S STUDY: The Choices In The Next Big Fight For Solar


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    Tuesday, January 30, 2018

    TODAY’S STUDY: The Choices In The Next Big Fight For Solar

    Sustaining Solar Beyond Net Metering; How Customer Owned Solar Compensation Can Evolve in Support of Decarbonizing California

    Matthew Tisdale, January 2018 (Gridworks)


    California has committed to rapid decarbonization of its power sector. The state is pursuing that objective through a wide range of policy solutions, one of which is net metering, an incentive encouraging customer adoption of renewable distributed generation, especially solar.1 To date net metering has supported the adoption of solar by over 725,000 California customers, totaling nearly 6 GW of installed capacity.2 These adoptions have contributed to reductions in greenhouse gas emissions from the power sector and local job creation. Net metering has been a success by many of California’s key measures.

    Looking forward, California’s path to decarbonization assumes increased reliance on renewable energy, including estimates of up to 16 GW of behind the meter solar by 2030.3 Achieving these targets would require accelerated customer adoption of solar. But as analyses of California’s electric system have demonstrated, continued growth in generation during day-time solar peak periods creates two challenges: excess generation at the system-level and grid constraints at the distribution-level. Excess generation at the system-level has been demonstrated by increasing negative prices and resource curtailment, including of renewable generation.4 Distribution-level grid impacts have been demonstrated through analysis of distribution system hosting capacity showing limited capacity to absorb midday solar production in areas of high-solar penetration.5

    At their core, these challenges are the manifestations of misaligned power supply and demand. Going forward, rather than spread like seeds in the wind, solar energy needs to be planted at locations advantageous to the grid and needs to produce simultaneous with demand, or stored until there is demand. Solar alone will not suffice; it needs to be locationally targeted and co-located with storage. 6

    Meanwhile, California policy-makers have continued to push for differentiation of incentives for solar by location, ensuring grid costs are fairly recovered, and enabling customer choice. A clear need for balancing these objectives with the State’s decarbonization imperative exists.

    This paper reexamines net metering, asking how to build on its success to further California’s decarbonization, account for location value, fairly recover grid costs, and enable customer choice. Evaluating alternative policies and applying consistent criteria reflective of California’s principles this analysis identifies advantages and disadvantages to net metering and variations thereof. Based on this analysis we conclude California can sustain solar beyond net metering. We recommend California policy-makers move expeditiously to transition the state’s solar compensation framework toward a net billing structure with locationally differentiated prices paid for exports. As detailed further in this paper, the transition may be eased in several ways and informed by data and insight gained through evaluation of current net metering policies, helping to sustain growth in customer adoption and achieve forecasted levels of solar…


    In D.16-01-044 the CPUC asked staff and stakeholders to “explore compensation structures for customer-sited DG other than NEM, including analysis and design of potential optional or pilot tariffs, with a view to considering at least an export compensation rate that takes into account locational and time-differentiated values of customer-sited DG.”9 In the spirit of this call to action, the following potential compensation structures for California were identified through stakeholder engagement and research on how other states are compensating customer generation. These options do not represent an exhaustive list of possible compensation frameworks, rather a reasonable cross-section reflecting ongoing trends in California’s energy policy landscape. This section introduces those options; a later section evaluates them.

    Several new concepts are included within these options. They are introduced in the context of the following explanations of each option.

    OPTION 1 | NEM 2.0

    This option reflects the status quo. The only exception to current practice we contemplate is the possibility of further evolution of TOU rates to allow those rates to more specifically reflect grid conditions, including a) greater peak-to-off-peak rate differentials, b) greater locational rate specificity, and c) further shifts in TOU periods on daily or seasonal basis.


    This option reflects a net billing core structure with exports compensated at the resource’s Locational Value, an export price informed by the Locational Net Benefits Analysis (LNBA). 11 The LNBA is a methodology being developed under the supervision of the CPUC which differentiates the value of customer generation by location, as illlustrated in Figure 3. Depending on how the administratively set locational values are determined, this export price could differ between customers. To enable a predictable return for the investing customer, it is assumed that the export price paid to an enrolling customer would be fixed for a practical duration and variable following that duration, updated periodically, based on refreshed LNBAs. It is assumed the valuation is updated annually to allow newly enrolling customers to be compensated at refreshed pricing. Two additional features of this option may be considered to support customer adoption. First, would be the inclusion of a Market Transition Credit.


    Awarding additional temporary compensation to a customer generator during a defined period (e.g., 5 years, indexed to total customer adoption, up to percent of system peak) that ramps down over time but recognizes the importance of continued clean energy development. There are many ways such a credit could be structured. Here we envision a “step- down” Market Transition Credit, whereby an adder to the LNBA-based export price tapers down to zero out over time. The scale and pace of the stepdown could be benchmarked to installed capacity, like early California Solar Initiative rebate designs. Second, would be the allowance of Transferrable Credits.


    Allowing credit earned by a customer generator for exports to the grid to be transferred to any other customer at the discretion of the customer generator. 11 For additional background on the LNBA, see for example, Southern California Edison Compnay’s Demonstration Project B Final Report at Because the net billing framework suggested here compensates exports at a price reflecting their Locational Value, credits earned for these exports could be transferred to any other customer. The impact of transferrable credits would depend on whether the generator must be “sizedto-load,” as is the case under NEM 2.0. We envision that requirement being lifted. Finally, we contemplate the exports may also be eligible for participation in grid services on an opt-in basis.


    Market-based compensation for DER providing energy, capacity, voltage support, frequency regulation and resiliency pursuant to an identified grid need. Compensation may be at wholesale or distribution level.12 Compensation to customers opting into grid services would be an alternative to administratively determined export prices, such that the customer chooses one or the other, but is not eligible for both.


    This option reflects a net billing core structure with exports compensated at market prices based on their participation in grid services markets. Whereas in Option 2 the customer would be defaulted onto the administratively determined LNBA-informed export price with the option to opt-in to grid services markets, Option 3 would default the customer’s exports into grid services markets. It is assumed that aggregators will serve as the customer’s agent in participating in such markets, but individual customer participation is not precluded.


    Prices paid for grid services may be market-based resulting from competitive solicitations, participation in organized wholesale markets or other transaction platforms. Distinct from other contemplated pricing mechanisms which result from administrative value determinations (e.g., locational value, retail rate). An additional feature of this option would be a managed demand charge.


    A rate design feature in which a customer receives a charge based on their maximum electric capacity usage during a defined interval in which capacity to serve customers is relatively scarce. Customers can reduce or avoid the charge through reduction of maximum usage through generation, changes in consumption, or use of storage technology to shift load. This feature is highlighted because it may provide a meaningful opportunity for a utility to recover costs for grid services unless the need for those services is reduced by a customer’s change in consumption or adoption of a storage technology. Volumetric charges may be reduced for customers receiving a demand charge.


    This option reflects a buy all, sell all core structure with all production compensated at its Locational Value. An additional feature of this Option would be the inclusion of a Market Transition Credit. As summarized, customer consumption is metered separately from production, enabling customer participation in other programs such as demand response to be evaluated and rewarded distinctly.


    This option reflects a buy all, sell all core structure with all production compensated at market based export prices based on their participation in grid services markets. Whereas in Option 4 the customer would be defaulted onto the administratively determined Locational Value export price, Option 5 would default the customer’s production into grid services markets. It is assumed that aggregators will serve as the customer’s agent in participating in such markets, but individual customer participation is not precluded. In the next section, we turn to criteria which may be used to gauge the relative strengths of these options and an evaluation of their merits.


    Returning to the identified opportunity: net metering has proven potential to incentivize customer adoption of solar. But does net metering support the alignment of supply and demand and thereby help resolve key challenges facing California? Can those challenges be addressed while increasing affordability for all customers and preserving customer choice?


    To evaluate the identified compensation structure options, criteria consistent with California’s principles must be identified. This evaluation begins with the stated principles of the CPUC in its DER Action…


    This evaluation attempts to evenly balance criteria and concludes that Option 2, Net Billing with exports compensated at the LNBA-informed export price for solar would be a substantial improvement to current policy, allowing for locationally differentiated compensation, improved grid cost recovery, and deeper decarbonization though storage enabled alignment of solar supply and demand.

    This structure would lead to three potential outcomes:

    • where the LNBA-based price paid on exports provides an adequate return, customers will adopt solar (with or without storage) in areas advantageous to the grid, easing grid planning and operations while lowering grid costs;

    • where the LNBA-based price paid on exports does not provide an adequate return, customers are incentivized to maximize self-supply, most practically achieved through solar plus storage;

    • where neither the LNBA nor storage are advantageous to the customer, they will maintain the choice to adopt while making increased contributions to grid cost recovery.

    These advantages are more acute where and when mature grid services markets can replace the LNBA as a tool for pricing exports. As more experience with grid services is gained, these advantages may become increasingly practical.

    To ease the transition from NEM 2.0 to Net Billing, two measures are recommended. First, enable Transferable Credits, allowing credit earned by a customer for exports to be transferred to other customers at the discretion of the customer generator. This will introduce liquidity into the market, especially if “size-toload” requirements are lifted, allowing customers who are not in high-value locations to invest in those locations and receive corresponding reductions in their energy costs. Second, adopt temporary Market Transition Credits, smoothing the change from the current compensation levels to locationally differentiated levels. There are many ways this could be structured. One would be to “step- down” the Market Transition Credit in stages as the industry hits certain installed capacity benchmarks (similar to early California Solar Initiative designs). This step-down approach would have the added advantage of allowing for storage to scale up and reduce costs while signaling to industry that there will be a market for behind the meter storage.

    Timely adoption of a Net Billing structure may also pave the way for grid friendly transportation electrification. Net metering would allow non-simultaneous netting of vehicle electrification load, an accounting tool which would undermine a principal benefit of vehicle electrification from a societal perspective (i.e., increased throughput leads to decreased rates). To the extent net metering continues into the next decade when electric vehicle adoption is forecasted to surge, a huge class of customers may come to expect low or zero cost service from the grid. On the other hand, a Net Billing structure would encourage electric vehicle customers to charge while the sun shines, or store their solar-generated energy to charge their vehicles at other times.

    A final advantage of Net Billing deserves consideration: Net Metering’s reliance on the retail rate limits the flexibility of California policymakers – the price paid to solar is intertwined with retail ratemaking, a clunky policy making process with implications and complications extending far beyond customer generation. This approach has supported customer adoption to date because retail rates were going up and solar costs were coming down. It is not difficult to imagine these trends being reversed, with federal trade or tax policy turning against solar. Net Billing on the other hand compensates exports at a price determined by California policy-makers, allowing for the adoption of anchors and adders with relative ease compared to Net Metering. In this sense, Net Billing allows California alone to determine whether solar is sustained.

    Based on this evaluation we recommend California policy-makers move expeditiously to transition the state’s solar compensation framework toward a Net Billing structure. As provided, the transition may be eased in several ways and informed by data and insight gained through evaluation of NEM 2.0, helping to sustain growth in customer adoption and achieve the levels of forecasted solar adoption.

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