NewEnergyNews: TODAY’S STUDY: On The Path To SunShot – Utilities And Distributed Solar


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    Tuesday, May 24, 2016

    TODAY’S STUDY: On The Path To SunShot – Utilities And Distributed Solar

    On The Path To SunShot – Utility Regulatory and Business Model Reforms for Addressing the Financial Impacts of Distributed Solar on Utilities

    Galen Barbose, et. al., May 2016 (National Renewable Energy Laboratory)

    Executive Summary

    Net-energy metering (NEM) with volumetric retail electricity pricing has enabled rapid proliferation of distributed photovoltaics (DPV) in the United States. However, this transformation is raising concerns about the potential for higher electricity rates and cost-shifting to non-solar customers, reduced utility shareholder profitability, reduced utility earnings opportunities, and inefficient resource allocation. Although DPV deployment in most utility territories remains too low to produce significant impacts, these concerns have motivated real and proposed reforms to utility regulatory and business models, with profound implications for future DPV deployment.

    This report explores the challenges and opportunities associated with such reforms in the context of the U.S. Department of Energy’s SunShot Initiative. As such, the report focuses on a subset of a broader range of reforms underway in the electric utility sector. Drawing on original analysis and existing literature, we analyze the significance of DPV’s financial impacts on utilities and non-solar ratepayers under current NEM rules and rate designs, the projected effects of proposed NEM and rate reforms on DPV deployment, and alternative reforms that could address utility and ratepayer concerns while supporting continued DPV growth. We categorize reforms into one or more of four conceptual strategies (Table ES-1). Understanding how specific reforms map onto these general strategies can help decision makers identify and prioritize options for addressing specific DPV concerns that balance stakeholder interests.

    Reducing compensation to DPV customers.

    Recent efforts to address stakeholder concerns about the impacts of DPV have revolved largely around reforms to NEM rules and retail rate structures. These include, for example: new or increased charges for DPV customers, minimum bills, demand charge rates for DPV customers, reduced compensation for electricity exported to the grid, reduced compensation for all DPV generation under two-way rates, and transfer of renewable energy certificate ownership to the utility. Although such reforms can address the concerns of both utility shareholders and non-solar customers and are often relatively straightforward to implement compared to more fundamental reforms to utility business models or markets, they accomplish their objectives only by constricting DPV customer-economics and deployment. They are thus largely a zero-sum game. Community solar is one possible exception because its economies of scale may allow for compensation at prices below retail rates, while maintaining customer-economics comparable to rooftop DPV with full NEM.

    To demonstrate the deterioration in DPV customer-economics that could occur if, in particular, NEM were eliminated, we compare the payback period of DPV systems with and without NEM, based on original analysis described further within the main body of the report. In the latter case, we assume that DPV generation exported to the grid in each hour is compensated at wholesale electricity prices, rather than at retail rates. As shown in Figure ES-1, elimination of NEM would increase the payback period for residential DPV systems by 1.4–8.9 years across the six illustrative states shown, depending on the state and the size of the system. Elimination of NEM would erode the customer-economics of commercial DPV as well, though only in cases where significant grid exports occur and where volumetric rates under the prevailing retail electricity tariff are substantially above wholesale electricity prices. As other studies have shown, customersited storage and demand flexibility can help DPV customers insulate themselves from such changes, though in doing so would also thwart the effort to stem utility revenue erosion.

    Given the implications for DPV customer-economics, reforms to NEM rules could also significantly impact long-term DPV deployment levels. Under an extreme bookend scenario in which NEM is immediately eliminated across all states and replaced with the alternative compensation scheme described above, cumulative U.S. DPV deployment in 2050 would be roughly 20% lower than under a continuation of current NEM policies (Figure ES-2, left), based on original analysis described further within the main body of the report. Conversely, indefinitely extending and expanding NEM to all customers and states would lead to DPV deployment levels in 2050 that are 30% higher than under current policies (Figure ES-2, right). In both cases, the impacts are notably more pronounced for residential than for non-residential markets. Many other recent studies have also shown potentially significant impacts on DPV customer-economics and deployment from other kinds of retail rate reforms, such as timevarying pricing, demand charges, two-way rates, fixed customer charges, and minimum bills.

    Within the context of the SunShot Initiative, NEM and retail rate reforms represent significant risks to achievement of near-term cost and deployment goals as well as the longer-term legacy and impact of the initiative. Within the immediate timeframe of the SunShot 2020 cost-reduction targets, constraints on market growth could dampen the pace of soft-cost reductions driven by increasing industry scale and learning. Uncertainty in the outcome of NEM and retail rate reforms also exacerbates business risks for the solar industry and potential solar customers, inflating soft costs associated with customer acquisition and financing. Longer term, NEM and retail rate reforms could produce an outcome in which achievement of the aggressive SunShot 2020 cost targets could still fail to spur the initiative’s vision of dramatic, sustained DPV growth.

    Fortunately, several other strategies—as discussed below—offer the potential to address utility and non-solar customer concerns about DPV, without unduly constraining DPV customereconomics and market growth.

    Facilitating higher-value DPV deployment.

    Many reforms seek to address stakeholder concerns about DPV by facilitating higher-value DPV deployment. Certain retail rate reforms—such as time-varying, locational, and unbundled attribute pricing—could incentivize optimally sited and grid-friendly DPV, though these innovations generally increase costs to DPV customers and could require significant efforts from utilities to establish the value of DPV production and handle customer differentiation. Enhanced utility system planning can provide an analytical foundation for these pricing designs and for other mechanisms to preferentially direct DPV deployment toward locations or design characteristics that increase its value to the utility system. In addition, utility ownership of DPV assets may enable higher-value forms of deployment through optimized siting and operation. Community solar might also facilitate optimized siting and design and more readily enable deferral of distribution system upgrades. Over the longer term, major reforms to utility business models and retail markets (e.g., transforming electric utilities into energy services utilities and forming distribution network operators or transactive retail electricity markets) could facilitate higher-value DPV deployment through enhanced price signals or procurement processes.

    Broadening customer access to solar.

    Bringing solar to traditionally underserved customer classes can diffuse concerns about cost-shifting and potentially regressive effects of NEM; indeed, one reason why energy efficiency programs are less susceptible to such concerns is that opportunities for participation are broad and often include programs targeted to low-income or other hard-to-reach customer segments. Among the reforms highlighted in this report, community shared solar offers perhaps the most explicit path toward expanding customer access, if opportunities for participation are broadly available. Utility DPV ownership that is restricted to underserved customer segments may provide another pathway to expanding access to those customers, and it may minimize some objections over utility entry into a competitive market.

    Aligning utility earnings and profits with DPV.

    Under traditional cost-of-service regulation, DPV tends to erode utility financial performance via reductions in sales growth and deferral of traditional utility capital investments. Reforms can seek to realign utility financial incentives so they are neutral toward, or even produce utility shareholder benefits from, DPV growth. Such reforms are thus targeted at addressing utility shareholder concerns, in particular, but can exacerbate ratepayer concerns surrounding possible cost-shifting to non-solar customers. Some suggested reforms entail relatively “incremental” changes to utility regulatory and business models. These include decoupling and other ratemaking reforms to reduce regulatory lag, which already have widespread adoption and hold utility profits immune to DPV growth. Performance based incentives and utility ownership or financing of DPV assets could create positive utility earnings opportunities associated with DPV growth, and they have precedents, but they represent a greater departure from the traditional cost-of-service model. Finally, many novel conceptual utility business model and market reforms are intended to realign utility financial incentives vis-à-vis DPV, such as by reorienting utility profits around the provision of services rather than commodity sales of electricity.

    In summary, efforts to address concerns by utilities and non-solar customers about the financial impacts of DPV growth are unfolding across the country in a variety of forms. To date, much of this activity has centered on reforms to NEM rules and retail rate designs. This pathway has certain practical advantages because these kinds of reforms address concerns of both utility ratepayers and shareholders and can often be implemented in a relatively immediate fashion. However, these reforms are generally premised on reducing compensation to DPV customers and, as such, achieve their objectives only insofar as they constrict DPV customer-economics. Other reforms discussed in this report instead provide opportunities to address utility and/or ratepayer concerns about DPV without necessarily constraining growth of those resources—by focusing on facilitating higher-value DPV deployment, expanding customer access, and aligning utility earnings and profits with DPV growth. Some of these alternatives have already been adopted in some locations and are options for wider implementation by 2020, while others will unfold over a longer horizon. In either case, opportunities exist to preserve the long-term legacy of the SunShot Initiative by promoting a stable regulatory environment and utility business models that align DPV adoption with the continued provision of safe, reliable, and affordable electricity service.

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