The US solar industry is expanding rapidly, with revenue that grew 174% from 2011 to 2015 making it a significant driver of the larger $200 billion US advanced energy market that now employs 3.3 million workers. The growth in solar has been fueled by falling technology costs (as seen in the graph below), financial incentives, business model innovations, renewable energy targets, and customers wanting more access to clean energy. This burgeoning industry has affected how utilities traditionally operate, sparking debates from California to Maine. Advanced Energy Economy (AEE) is keeping tabs on all of these developments through our online policy platform - PowerSuite. There are a myriad of developments that have the potential to affect the solar industry; today we outline four key questions that are dominating the conversation and market developments.
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1. How should rooftop solar (and other distributed generation) customers be compensated for the electricity they feed back to the grid?
As the penetration of distributed generation (DG), particularly rooftop solar, increases, pressure is building to find alternatives, or successors, to net metering in order to fairly compensate both the utility and the customer for the value each provides. Many stakeholders have argued that new net metering tariffs should evolve to reflect both the costs and the benefits to the system of all distributed energy resources (DER) - which we define to include distributed generation, such as combined heat and power, solar PV, small wind, fuel cells, as well as energy storage, electric vehicles, demand response, energy efficiency and microgrids - and to achieve desired customer changes and system outcomes to make the electric power system work better for all.
New York has been at the forefront of these discussions with their Value of DER proceeding. That proceeding opened in late 2015 to identify a short term successor to net metering (with a final decision expected in 2017) as well as a long term approach that establishes a full value of DER based on the locational marginal price plus distribution (LMP+D) approach.
Other states have taken a narrower approach. In November, the Louisiana Public Service Commission removed its net metering cap (which had been reached by Entergy Louisiana and Southwestern Electric Power Co.) in the first phase of their net metering investigation and ordered that utilities continue crediting customers at the retail rate with any excess credits carried over every month at the avoided cost rate. This is a win for the solar industry and its customers in the near term, although the Commission was clear to point out that permanent changes will only be made after a study period, which could last up to two years.
In January, the Maine Public Utilities Commission approved revisions to its net energy billing rules based on a transitional approach that slowly reduces the compensation level for rooftop solar customers over the next 10 years. Other states to watch include Arkansas and New Hampshire, which both have open proceedings considering changes to their renewable DG policies and net metering rules, and Michigan, which is expected to open a proceeding to establish a new DG tariff as directed by Senate Bill 437.
2. What is the right rate design to ensure that DG and non-DG customers are both paying their fair share to maintain the grid on which we all depend?
Retail net metering continues to raise issues with respect to utility cost recovery and potential distribution cost allocation in states with higher levels of net metered customers. As a result, states - and especially utilities - are pushing back and calling for tariffs that incorporate higher fixed charges, demand charges, and/or interconnection fees. Increasing the fixed charge or adding a demand charge component ultimately gives the utility a more stable and predictable revenue stream and ensures that DG customers pay for their use of the distribution system. However, this structure is also coupled with a proportional decrease in the variable component of a customer’s bill which reduces customers’ incentive for generating their own power, as well as increasing their energy efficiency. Furthermore it fails to recognize all of the benefits that DG provides to the grid. Most of all, it hurts the value proposition of DG for customers.
In November, PacifiCorp in Utah released a cost-of-service study stating that the typical rooftop solar customer underpays for supporting the grid by $400 a year. As a result, the utility proposed a new tariff for net metering customers that includes a $15 monthly fixed charge and a $9/kW peak-period demand charge. Solar advocates countered that PacifiCorp did not fully consider the benefits that solar can provide - and that the proposal would cripple the solar industry.
In Arizona, three utilities have proposed rate design changes that would limit the value proposition of solar for customers. Arizona Public Service (APS) has proposed a default demand charge for residential and small commercial customers, an increase in the basic customer charge, and a reduction in the net metering credit from retail to wholesale rates. Tucson Electric Power (TEP) has proposed a demand charge for solar customers and a reduction in the net metering credit from retail to the utility’s avoided cost. Finally, Sulphur Springs Valley Electric Cooperative (SSVEC) has requested in increase in the monthly minimum charge from $10 to $50 a month for DG customers and a significant reduction in the net metering credit.
While an ideal rate design that can accommodate DER has yet to be determined, there are a few principles that should be adhered to. New rates should give customers price signals that drive desired outcomes related to electricity use, accommodate all technologies, and encourage customer-sited DER where and when it is most beneficial to the grid. To date, none of the utility proposals for additional charges on net-metered customers meet those standards.
3. How can all customers get access to the renewable energy they want?
As solar has become less competitive on price, more consumers want access to it. However, for a variety of reasons, owning a solar system is not a feasible option for all customers. Those shut out of onsite solar ownership includes many large corporations, renters, apartment dwellers, households with shaded rooftops, consumers with sub-optimal credit, people living in historic districts, and those hampered by unfavorable building codes or zoning ordinances. To offer the option of renewable energy to these customers, policymakers are turning toward green tariffs, direct access power purchase agreements (PPAs), and community solar programs.
In July, Public Service Co. of New Mexico (PNM) received approval for a five-year PPA to provide 60 MW to 100 MW of renewable power for a new Facebook data center. Facebook had been weighing options for where to build a $250 million data center, but settled on New Mexico when the application was approved. In November, Public Service Co. of Colorado received approval for a voluntary retail customer solar program - Solar*Connect (SC). Under SC, PSCo would purchase energy through a PPA, resulting from a competitive solicitation, from a large solar PV plant (up to 50 MW). In February, Sierra Pacific Power Co. (an operating utility of NV Energy) filed an application for a 200 MW renewable energy agreement with Apple to help Apple reach their company renewable energy objectives.
In October, Idaho Power received approval for a 25-year community solar pilot program, financed solely through voluntary customer contributions. In November, Kentucky Utilities (KU) and Louisville Gas and Electric Co. (LG&E) got the go-ahead to offer 4 MW of community solar through their subscription-based Solar Share Program. In December, South Carolina Electric & Gas received approval for a low-income community solar offering as part of their DER program. And in Mississippi, Entergy filed a report in July (the Commission has not yet responded) recommending the adoption of a community solar program to broaden solar choice to a wider group of customers.
4. How can utilities optimize their resource planning to include the integration of DER assets on their distribution systems?
A trend we are seeing across the country is the movement towards distribution system planning that takes DER - such as rooftop solar, demand response, energy efficiency, energy storage, or electric vehicles - into consideration in resource planning. Getting utilities to consider DER as an alternative to traditional infrastructure investments (e.g. a combined solar and storage project rather than a substation upgrade) can lead to a more nimble, reliable, resilient, and clean grid.
Leading the way has been the California Public Utilities Commission (CPUC) with their Distribution Resource Plan (DRP) and Integrated Distributed Energy Resources (IDER) proceedings. These interrelated proceedings are intended to overhaul how California’s utilities make investments in their distribution system by incentivizing the adoption of DER and integrating DER in the highest value areas of their grid.
Several other states have begun having conversations to explore distribution system planning. New York, in its Reforming the Energy Vision (REV) proceeding, has been the most ambitious with its plan to turn utilities into Distributed System Platform Providers. New Hampshire, Minnesota, and Maryland have established working groups and held stakeholder meetings to investigate distribution system planning as part of their larger grid modernization proceedings.
There is no question that the solar industry is and will continue to be a major player driving change in our electricity system, and the rules under which it is governed. We are a long way from done. Stay up-to-date on all solar and other advanced energy policy development, plus see predictions on outcome of pending bills with AEE’s PowerSuite.
Written by Coley Girouard, an Associate, Public Utility Commission Program, at national business group, Advanced Energy Economy.