NewEnergyNews: The Officially-Determined Costs Imposed By Solar

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    Monday, August 23, 2021

    The Officially-Determined Costs Imposed By Solar

    Cost-effectiveness of NEM Successor Rate Proposals under Rulemaking 20-08-020; A Comparative Analysis

    June 15, 2021 (Energy and Environmental Economics)

    Executive Summary

    This study compares NEM successor proposals as submitted by the parties in CPUC Rulemaking 20-08-020 to replace the existing NEM tariff (“NEM 2.0”). Only the proposals that contained sufficient detail were modeled. Eleven residential proposals and six small commercial proposals were modeled in addition to NEM 2.0, the existing tariff, which was modeled for comparison. This comparative analysis is intended to serve as a guide for the CPUC and parties to understand how the various party proposals approach reducing the cost misalignment under NEM 2.0. The analysis was done with two key principles in mind:

    • Consistency. While the party proposals differ significantly from each other, E3 used a single evaluation method, five standardized output metrics, and the same set of model inputs and assumptions to provide a consistent evaluation across proposals. E3 developed an Excel-based model to calculate annual customer bills for representative customers assuming standalone solar and solar paired with storage. For each party proposal, bill savings were calculated relative to a counterfactual customer with no solar or solar+storage system.

    • Transparency. In cases where the exact specification of a proposal could not be modeled or an assumption had to be made, it is noted in this document. In addition to this report, the Excel-based analysis tool itself will be made publicly available to provide transparency in this process.

    Dimensions of the Analysis

    The dimensions of the analysis are designed to illustrate differences between the party proposals for a range of customer types, technology, and installation years. They are the following:

    • 3 investor-owned utilities: PG&E, SCE, and SDG&E;

    • 3 customer categories: non-CARE residential1 , CARE residential, and small commercial;

    • 2 system types: solar only and solar+battery systems;

    • 2 installation years: 2023 installation year and 2030 installation year.

    Output Metrics

    For each of these customers, 5 metrics were evaluated:

    1. Simple payback period

    2. First-year cost-shift

    3. Participant Cost Test (PCT) benefit-cost ratio

    4. Ratepayer Impact Measure (RIM) benefit-cost ratio

    5. Total Resource Cost (TRC) benefit-cost ratio

    Results Summary

    To illustrate the results, this executive summary compares party proposals for a residential customer in PG&E’s service territory who adopts customer solar in 2023. This customer has an annual consumption of 7,500 kWh/year and their solar system generates an equivalent 7,500 kWh/year. In the report, different dimensions are varied one by one to illustrate differences. For example, a customer with solar+storage, a customer on CARE rates, and installation in 2030 are all considered. Complete results are provided in Appendix D and the Excel model.

    Simple Payback Period and First-year Cost Shift

    These two metrics are used to illustrate each proposal’s impact on participants and nonparticipants in customer-sited renewable generation.

    The simple payback period is an estimate of how many years of bill savings would be required to recover the upfront costs of a new solar or solar+storage system.2 A shorter payback period reflects a proposal that is more favorable for participants.

    The first-year cost shift reflects the dollar value of utility costs shifted from participants to nonparticipants in the first year after interconnection. A smaller cost shift reflects a proposal that is more favorable for nonparticipants.

    Figure 1 shows the simple payback period and first-year cost shift for a 2023 residential non-CARE solar adopter in PG&E’s service territory. There is a wide range in these metrics across the party proposals. Compared to NEM 2.0, all proposals would result in a longer payback period and a smaller first-year cost shift. However, while some proposals would retain a similar payback period to NEM 2.0 in the near-term, other proposals would result in a somewhat or substantially longer payback period and a lower cost shift.

    Across the board, the proposals that have a shorter payback period also have a larger cost shift. This reflects the fundamental tension that exists between the solar adopter and the nonparticipant. Absent non-rate funds, utility cost recovery is essentially a “zero sum game” and a tariff that provides a shorter payback period for a solar adopter will result in a larger cost shift to the nonparticipant.

    Standard Practice Manual Cost Tests

    The California Standard Practice Manual3 defines cost tests that are used to explore cost-effectiveness from different stakeholder perspectives. These cost tests reflect the net present value ratio of benefits to costs over the lifetime of the solar system.4 The exact definition of the cost tests is provided later in this document and results are provided here as an overview for this PG&E customer.

    Participant Cost Test

    Figure 2 shows the Participant Cost Test (PCT), which reflects the benefit-cost ratio from the participant perspective over the assumed life of the system. A benefit-cost ratio above 1.0 meansthat customers would find lifecycle benefits exceed lifecycle costs, which we find in 7 of the 12 cases. Compared to NEM 2.0, all proposals would reduce the PCT benefit-cost ratio.

    Ratepayer Impact Measure

    Figure 3 shows the Ratepayer Impact Measure (RIM), which reflects the benefit-cost-ratio from the nonparticipant perspective. The results show that for PG&E’s service territory, only one proposal (CARE) is not unfavorable to nonparticipant customers, as it provides a ratio of 1 (equal lifecycle benefits and costs). Compared to NEM 2.0, all proposals increase the RIM benefit-cost ratio.

    Total Resource Cost

    Figure 4 shows the Total Resource Cost (TRC), which reflects the benefit-cost ratio from the combined participant and nonparticipant perspective. When looking at the TRC for solar customers, only one factor leads to a distinction in TRC score. Community solar projects have a lower upfront cost than residential projects, leading to a higher TRC score. The CCSA proposal is based on community solar projects, whereas the other proposals are evaluated assuming customer-sited solar. All of the TRC results are less than a benefit-cost ratio of 1.0. This indicates that the costs of rooftop and community solar exceed the benefits to the grid based on the draft 2021 Avoided Cost Calculator (ACC)…

    Model Results

    This section includes example results in PG&E’s service territory. Appendix D: All Model Results includes model results for all customers, all IOUs, and all proposals. Residential 2023 Non-CARE Solar Figure 6 shows the simple payback period and first-year cost shift for a 2023 residential non-CARE solar adopter. This is the same as Figure 1 in the Executive Summary and is provided again here for comparison to other customers.

    Residential 2023 Non-CARE Solar

    Figure 6 shows the simple payback period and first-year cost shift for a 2023 residential non-CARE solar adopter. This is the same as Figure 1 in the Executive Summary and is provided again here for comparison to other customers.

    Figure 9 shows the TRC for a 2023 solar+storage customer in PG&E’s service territory. For the solar customer, the only distinction in TRC was for community systems. However, for solar+storage, there is an additional distinction among the proposals that factors into the TRC. Two different storage dispatch profiles are used depending whether a proposal’s export rate varies hourly or by TOU period. Export rates that vary hourly would encourage storage dispatch that is more aligned with underlying system costs, leading to a higher TRC value for these proposals.

    Residential 2023 Non-CARE Solar+Storage

    Figure 8 shows the simple payback period and first-year cost shift for a 2023 non-CARE solar+storage customer in PG&E’s service territory. Overall, payback periods are not considerably longer than for solaronly customers. This is largely due to the SGIP incentive, which reduces the upfront cost of storage. As a ratepayer-funded rebate, the SGIP incentive increases the cost shift for solar+storage adopters. Two proposals achieve a shorter payback period than NEM 2.0. This is because they suggest modeling the existing EV rates for solar+storage customers, while NEM 2.0 assumes the default TOU rates. Some proposals have export rates that vary hourly or with substantial variation by TOU period. Under these proposed tariffs, storage can enable the customer to capture greater value with their on-site generation, increasing bill savings and potentially reducing the payback period relative to a solar-only system.

    Figure 9 shows the TRC for a 2023 solar+storage customer in PG&E’s service territory. For the solar customer, the only distinction in TRC was for community systems. However, for solar+storage, there is an additional distinction among the proposals that factors into the TRC. Two different storage dispatch profiles are used depending whether a proposal’s export rate varies hourly or by TOU period. Export rates that vary hourly would encourage storage dispatch that is more aligned with underlying system costs, leading to a higher TRC value for these proposals.

    Residential 2023 CARE Solar

    Figure 10 shows the simple payback period and first-year cost shift for a CARE customer. In general, customer bill savings are lower for the CARE customer vs. the Non-CARE customer. For many proposals, this results in a longer payback period and a smaller first-year cost shift relative to the Non-CARE customer.

    Under NEM 2.0, there are two reasons why a CARE customer would see smaller bill savings from solar vs. a non-CARE customer. First, exports are credited at a discounted rate; and second, self-consumption of solar generation offsets imports at a discounted rate. Some proposals maintain NEM 2.0 but address the first point by crediting exports at the full non-CARE export rate; however, this does not affect the second point. These proposals achieve a simple payback period that is only slightly shorter than NEM 2.0.

    Residential 2030 Non-CARE Solar

    Figure 11 shows the simple payback period and first-year cost shift for a Non-CARE customer adopting solar in 2030. Several key changes occur between 2023 and 2030. First, the upfront cost of solar falls substantially. Second, import rates increase, which increases bill savings in proposals that allow offsetting imports with on-site generation. Third, some proposals transition from a NEM 2.0-like structure to export rates that are based on avoided costs. And fourth, avoided costs during solar hours fall considerably.

    Overall, the spread between simple payback period among the proposals increases from 2023 through 2030. NEM 2.0 becomes extremely lucrative for the participant, resulting in a 2.6-year payback period. Some other proposals have similarly short payback periods. On the other hand, proposals with compensation tied to avoided costs may see a similar payback periods for customers in 2023 and 2030.

    Residential 2030 Non-CARE Solar+Storage

    Figure 12 shows the simple payback period and first-year cost shift for a Non-CARE customer adopting solar+storage in 2030. The trends described above apply to solar+storage as well, with two key differences. First: although upfront costs for battery storage fall from 2023 through 2030, no SGIP incentive is assumed in 2030, which offsets some of the cost decline. Second: although solar avoided costs fall over this period, the solar+storage system can capture higher avoided costs in evening hours. Proposals that vary compensation dramatically based on the timing of imports and exports may see a shorter payback period for solar+storage than for solar alone…

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