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    Monday, November 17, 2014


    The True Value of Solar

    Steven Fine, Ankit Saraf, Kiran Kumaraswamy, Alex Anich, October 21, 2014 (ICF International)

    [Editor’s note: See also:]

    Executive Summary

    As solar becomes an increasingly significant factor in the generation mix, ICF believes that utilities, investors, and markets are missing out on optimal strategies to price assets, lower costs, and mitigate risks, because they lack a consistent and accurate approach for determining the true value of solar.

    Current methodologies are all over the map, yielding different outputs based on different inputs, and different assumptions to those inputs. That is why we suggest here an updated, comprehensive methodology that could help all stakeholders expose the benefits and costs and make more informed— and ultimately more beneficial—investments.

    This kind of approach will likely become even more important in the years to come. The amount of distributed photovoltaic (DPV) installed behind the meter specifically for residential customers grew 60 percent from 2012 to 2013. ICF forecasts DPV installations to continue to increase to over 27 GW on commercial and residential premises by 2018, representing over 1.8 million locations where DPV will be interconnected to the distribution grid. Utilities, regulators, and the broader solar industry will need to understand how to value this growing factor in the market.

    In this paper, we look at the current state of value of solar (VOS) analysis and propose a more holistic methodology that can be consistently applied across various utility service areas. We recommend factors for inclusion and exclusion in the calculation and consider the most appropriate way to construct each variable, keeping in mind our base view that distributed resources need to be evaluated in the same light as other generating resources on the grid, not just a decrement to load.

    We recommend the following methodological approaches on potential VOS components:

     Energy: avoided generated energy represents the most straight-forward calculation, and while the best way to quantify energy value would be at the margin, a more simplified interim approach may be considered.

     Avoided/Deferred Generation Capacity: there needs to be a realistic analysis of the correlation between customer and system peak as well as an analysis of the DPV’s generation profile to accurately assign a DPV system capacity credit. The same process should be applied to DPV projects as with central station renewables, with the added complication that penetration rates on distribution system feeders also need to be included.

     Avoided Transmission and Distribution (T&D) Losses and Capacity: For the T&D portion of the grid, DPV potentially represents both a benefit and a cost, and both of these impacts need to be included and separately assessed as part of a VOS analysis. This includes careful consideration of where DPV will be deployed versus the loads being served, as well as understanding the different feeder characteristics.

     Grid Support Services: based on the high amount of uncertainty on this variable, we believe that Grid Support Services should not be included in a VOS calculation for potential payment but should be reviewed for the potential to determine the mechanisms that may need to be in place to monetize any potential value when the appropriate technology exists.

     Environmental: as a generation resource on the grid, DPV should be evaluated in the same way as any other new resource, including central station renewables, in terms of environmental costs and benefits that it confers upon the system. The emissions (in this case CO2) values assigned on a $/ton basis should be similar to those used to evaluate other power generation resources.

     Financial: “financial” benefits such as a fuel price hedge, reservation of natural gas pipeline capacity, and/or a market price response are not typically accounted for in utility integrated resource planning (IRP) evaluations of new resources, including central station renewables, or in cost-benefit evaluations of EE measures, and should not be included in VOS analyses.

     Social: “social” values are not included in the construction of utility scale conventional or renewable projects and should not be part of VOS analyses.

     Security: when DPV is able to isolate from the grid or “island,” it can provide reliability to the owner of the facility. This value, however, does not accrue to society or even the local grid. Security benefits should therefore be explored to value resiliency at specific critical locations, however, they should not yet be included in the VOS calculation until a set and agreed-upon methodology for resiliency is developed.

     Frequency to Update VOS: the utility should update the VOST on a locational basis for new installations yearly to address the changing amount of solar or energy use in different areas.

    The result of our approach is a general roadmap for achieving a better consensus VOS, though calculations for individual entities would require an analysis tailored to the individual circumstances of their geography, energy market, and physical grid infrastructure.

    This new VOS calculation could be an input in calculating the retail credit net energy metering (NEM) subsidy under a Value of Solar Tariff (VOST), and can also help to guide larger investment and market decisions for utilities, regulators, and the broader solar industry, better aligning costs and benefits and mitigating the risks that the rise of solar will bring to the market…


    In order to get the Value of Solar “right,” a consistent and comprehensive methodology is needed for calculating avoided generated energy, avoided generation capacity, T&D losses and capacity deferrals, grid support services, and environmental values. VOSTs should be updated periodically to reflect existing and new systems. Furthermore, DPV must be treated not simply as a decrement to the system, but as a system resource. Customers who have installed DPV should be viewed as contributing generation to the grid at time of export and also as retail customers when they are not exporting during the majority of the year.

    Traditional evaluation parameters such as those applied to central station resources, including renewables, should be applied. Avoided generation, capacity, and T&D should be correctly accounted for within the system at the location of the asset, and not just from aggregated and isolated distribution perspectives. This is increasingly important as distributed generation of all types continues to deliver costs and value to the grid based on the locational nature of the distribution feeder and its segments. Environmental benefits also need to be included in VOS calculation using the marginal resource avoided, which may be a gas fired simple cycle or combined cycle combustion turbine, but could also be any type of generating unit . Therefore, an analysis of the utility’s energy supply should be prepared and reviewed.

    Values that should not be part of a VOS calculation are those that would not be considered part of the valuation of a generation asset or those that are not yet available in the market – specifically financial hedging and societal benefits. Security benefits should be explored to value resiliency at specific critical societal locations. However, they should not yet be included in the VOS calculation until a set and agreed-upon methodology for resiliency is developed. Grid support services should be included once technologies and a means to actively coordinate with distributed generators like DPV has been established consistently.

    A VOS approach moves beyond NEM and makes much more sense, but studies to date have often been less rigorous and thorough, ignoring the infrastructure that needs to be in place to manage the DPV and capture the value. A strong VOS approach, in which the real costs and benefits to the system are accurately portrayed and valued, is not only a useful tool for integrating increasing amounts of DPV onto the grid, but will be critical for utilities, regulators, and other stakeholders to make rational planning and risk management decisions.


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