All communities depend on their local utility to ensure reliable electricity service. As the solar energy market has expanded across the United States, utilities have developed and improved procedures for accommodating solar installations on the grid. However, many challenges remain when it comes to integrating rooftop, commercial, and utility-scale solar with traditional energy sources. It is important to understand how solar energy will impact consumer demand, utility business practices, and the functioning of the electricity grid to foster positive and collaborative engagement with utilities. Therefore, it is essential that municipalities and counties seeking to expand solar energy development engage utilities throughout the process in a meaningful and productive way.
An effective partnership between a local government and a utility helps the community adopt solar-friendly programs and practices, while supporting the reliable and cost-effective operation of the electricity grid. The municipality can achieve these win-win outcomes by building communication channels with its utility representatives, and by familiarizing itself with the local system for electricity production and delivery. A more detailed discussion of how local governments can partner with utilities is included in the stakeholder engagement section.
This section of Solar Energy: SolSmart’s Toolkit for Local Governments provides more detail on how electric utilities operate, along with the questions and concerns that are likely to arise as solar energy use expands. This, in turn, will help local governments engage with utilities as they work toward their solar energy development goals.
The first part of this section explains how electric utilities and electricity markets are structured in different parts of the country. Next, the section provides an overview of how utilities are regulated, and the regulatory incentives available for solar energy development. It concludes with a discussion of important ways that solar deployment can impact the electricity grid, and how these issues can be addressed.
There are three basic elements of the electricity grid: generation, transmission, and distribution, as shown in Figure 1. Historically, generation only occurred at a large facility such as a coal or nuclear plant. The electricity was transmitted long distances to population centers where it was distributed to homes and businesses. Today, there is a growing interest in distributed generation, which refers to a system where the electricity is produced in the same place it is consumed. A leading source of distributed generation is rooftop solar.
Figure 1: An Overview of The Electricity Grid
Despite the recent growth of residential solar energy, however, most electricity continues to be delivered through the traditional supply chain. The section below will describe how this supply chain works, and also examine the issues associated with integrating distributed solar into the grid.
The structure of the U.S. power sector is complex. Overall, however, utilities are set up in one of two basic ways. The first involves a single, “vertically integrated” utility that provides generation, transmission, and distribution services. The utilities also play the role of the “system operator” for the grid, ensuring that demand and supply are matched on a second-by-second basis. This structure predominates in large parts of the Western and Southeastern United States.
Under this structure, customers are usually (but not always) assigned to a utility based on the geographic boundaries of the utility franchise agreement, and do not have the option to choose among competing retailers. Accordingly, state regulatory commissions closely oversee these utilities, regulating the retail prices they can charge, the investments they make, and the overall revenues they earn.
The second type of structure — implemented in parts of the Northeast, Midwest, Texas, and California — features wholesale electricity markets run by independent organizations known as independent system operators (ISOs) and regional transmission organizations (RTOs). These organizations have footprints that can stretch across multiple states. They, rather than the utility, are responsible for operating the transmission system and ensuring grid stability. Figure 2 presents a map of the different wholesale electricity markets across the U.S.
Figure 2: Regional Transmission Organizations and Independent System Operators
In a wholesale electricity market, generation, transmission, and distribution are handled by different entities. ISOs and RTOs do not own any generation or transmission assets. Instead, various independently owned generators compete to sell electricity into the grid. Transmission is owned by utilities, independent transmission companies, or other entities such as the Bonneville Power Administration and the Tennessee Valley Authority.
Each ISO/RTO region also includes multiple distribution utilities. The core of a utility’s business under an ISO/RTO is usually the ownership and operation of distribution lines. However, a utility may also own generation assets such as power plants. In some markets, the utility competes with non-utility retail suppliers such as retail electric providers for customers. In other markets, this competition is not allowed. Regions that are served by ISOs/RTOs but have limited or no retail competition include California, Vermont, and much of the Midwest.
Another important aspect of a wholesale electricity market is the third-party aggregation of distributed energy resources (DERs). Aggregation refers to the assembly of a portfolio of DERs, such as rooftop solar, from multiple customers that can be managed collectively to provide energy, capacity, or ancillary services. For example, the potential of multiple industrial customers or thousands of residential air conditioners can be managed as an aggregated resource, providing significant peak demand reductions, frequency response services, etc. These services are offered to utilities or directly into competitive markets operated by ISOs or RTOs.
Utilities in ISO/RTO regions are overseen by state and federal regulators. However, the term “unregulated” is sometimes used loosely to refer to the ISO/RTO model because there are multiple competing retailers and generators. In these regions, market forces also play a larger role in determining the structure of retail prices and the nature of investment decisions.
ISOs/RTOs have successfully integrated diverse sets of resources — including renewable resources — over hundreds of miles and across state lines. However, as renewables have grown, there has been increasing debate over how to address that growth. Discussions are underway in many communities to determine how distributed resources (including solar) can effectively and efficiently participate in ISO/RTO wholesale markets.
Roughly 70 percent of the U.S. population is served by investor-owned utilities (IOUs). These companies are privately owned (often publicly traded) and are regulated by state commissions. The business models and regulatory regimes of particular IOUs can be quite different, however. For example:
The remaining 30 percent of the U.S. population is served by various types of publicly owned utilities. Municipal utilities (munis) and public utility districts (PUDs) are usually city-owned and regulated by a city council or board of elected officials rather than by the state. These utilities may be located in states that allow retail competition, but they often do not face competition within their municipality. For example, Austin, Texas is served by the muni Austin Energy. Though most of the state of Texas is a competitive market, residents in the Austin Energy franchise boundaries are served exclusively by the muni.
Cooperatives (co-ops), another type of publicly owned utility, are usually rural and are structured as nonprofit organizations. Like munis and PUDs, they are not regulated by the state, but are instead governed by a board elected by customers.
Community choice aggregation (CCA) is an increasingly popular tool utilized by local governments to procure power from alternative suppliers. Under this model, the electric utility continues to provide transmission and distribution services, but gives local governments the ability to choose where and how their electricity is produced, typically leading to greater procurement from solar energy and other renewables.
Prior to setting up a local CCA program, state authorities must pass legislation to enable the implementation of CCA in local jurisdictions. As of 2019, eight states (California, Illinois, Massachusetts, New Jersey, New York, Ohio, Rhode Island, and Virginia) had enacted CCA legislation. Local governments then enact their own legislation to set up the program. Cities and counties typically retain a third-party organization, such as a nonprofit, to manage the program.
For a more detailed discussion of the CCA model, please refer to the Solsmart Issue Brief: Community Choice Aggregation.
Utilities are subject to a variety of federal, state, and local regulations. Interstate transmission and wholesale power sales are federally regulated, while retail rates and distribution services are regulated by states. Issues such as facility siting and the environmental impacts of distributed generation projects are mainly regulated by local government agencies.
The Federal Energy Regulatory Commission (FERC) has the authority to regulate wholesale power sales. In addition, because 47 states (all except Texas, Hawaii, and Alaska) have interstate transmission networks, FERC sets the electricity rates and service standards for most bulk power transmission. FERC also has authority to approve bulk electric reliability standards
adopted by the North American Electric Reliability Council (NERC). ISOs/RTOs operate within NERC planning areas to meet FERC requirements, such as those specifying how generation can or cannot be interconnected on the bulk electric system. The bulk electric system is defined as the electrical generation resources, transmission lines, interconnections, and associated equipment operated at voltages of 100 kV or higher. Alongside the Nuclear Regulatory Commission, FERC also handles much of the licensing of nuclear and hydropower facilities. Licensing and siting of other types of power production facilities — about 75 percent of the total — are managed at the state and local levels.
Figure 3: NERC Regional Entities
State regulatory commissions generally oversee a utility’s financial responsibilities. They determine the revenue requirements for utilities and design price structures that are equitable across customer classes. Further, they evaluate and, in some cases, approve a utility’s new investment proposals. Additionally, they set service quality standards and consumer protection requirements, and also serve as the arbiter of disputes between the utility and consumers.
State commissions normally regulate all investor-owned utilities in a state. In most states, but not all, municipal utilities and public power districts are not subject to economic regulation by the state commission, but they are still subject to other forms of regulation. The regulatory commissions consist of three to seven appointed or elected commissioners and a professional staff to provide analysis, conduct hearings, and carry out enforcement. Commission decisions are subject to appeal to state courts, though in general courts will defer to the expertise of the regulators.
While investor-owned utilities are primarily under the jurisdiction of the state commission, publicly-owned utilities are generally subject to control by the city council or a special local board. These local entities use different processes than state-level regulatory commissions but perform the same basic functions.
Utilities can take advantage of federal, state, and local policies that encourage growth in solar energy. Some of the most common such policies are listed below.
RPSs are state policies that require utilities to obtain a certain percentage of their electricity from renewable sources. An RPS usually applies to investor-owned utilities. Munis, PUDs, and co-ops can also set their own renewable energy targets even in the absence of a statewide RPS.
NEM is designed to compensate utility customers with on-site renewable energy generation for the electricity they export to the grid. This provides an important incentive for consumers to install rooftop solar energy. Mandatory NEM rules are in place in 40 states, in addition to Washington, D.C, American Samoa, the U.S. Virgin Islands, Guam, and Puerto Rico.
Traditionally, electric utilities determine their revenue based on the volume of electricity sold. In this model, utilities have an incentive to expand, or at least not reduce, sales. They can be reluctant to support approaches that reduce overall sales volumes, including net metering programs for distributed solar customers.
Decoupling is designed to remove this disincentive by allowing utilities to recover revenue independent of their sales volumes. Specifically, decoupling allows a utility to assess a small rate surcharge if the utility’s sales fall short of expectations. In this way, utilities become indifferent to losing sales and more likely to support energy efficiency and distributed solar.
FITs provide guaranteed cash payments for electricity produced by renewable technologies, typically over 10 to 20 years. FITs were a popular policy measure, particularly in Europe, during the 1990s and 2000s. But this approach has since begun to fall out of favor due to a consensus that it is economically inefficient. It often results in higher than necessary compensation levels for solar electricity, when compared to a competitive bidding process in which a utility finds the lowest cost producers.
VoS tariffs are priced based on the costs and benefits of distributed solar. These programs determine a value for solar energy based on an algorithm that is calculated annually. Factors may include loss savings, energy savings, electricity grid capacity savings, full price hedge value, transmission and distribution capacity savings, and environmental benefits. States are showing increased interest in VoS tariffs, but they have yet to be adopted on a widespread scale, due in part to the fact that calculating the tariffs can become very complex.
Interconnection is defined as the technical and administrative linking of a generator – a distributed PV or other electric system – to the utility grid. It is very important to solar development because most all households and businesses that deploy solar want their systems connected to the grid. Consistent delays in the interconnection process will discourage investment in and the development of solar. Please refer to the Appendix for a more detailed discussion of federal and state interconnection policies and interconnection procedures.
A range of federal and state interconnection standards stipulate the rules and requirements for connecting to the grid. They have been developed to uphold grid reliability, safety, and economic objectives. Ultimately, these rules are intended to provide clear guidance on the timelines, fees, technical requirements, and steps in the DER application review and approval process.
Ideally, interconnection should be a quick, smooth process. In practice, the ease of interconnection depends on many factors such as system size; location; technology; utility and utility commission preferences; and local, state, and federal regulations. The regulatory landscape can be very complex with multiple organizations working on the state and national codes and standards that guide regulation. Furthermore, the codes and standards are regularly updated to keep pace with evolving technologies and changing grid characteristics.
At a minimum, interconnection involves the following steps:
Utilities typically interconnect to smaller systems faster than larger ones. A 5-kW residential rooftop system might require only a few days prior to and after construction for the utility approvals described above. A larger commercial or utility-scale system might, however, require months of reviews, supplemental studies, and negotiations before it is granted approval. See Appendix 1 for a more detailed discussion of interconnection.
Rooftop, commercial, and utility-scale solar adoption impacts utilities in many different ways. These opportunities and challenges can affect a utility’s core objective to safely, reliably, and equitably provide electricity to ratepayers. Understanding how solar energy will impact consumer demand, utility business practices, and the functioning of the electricity grid can help foster positive and collaborative engagement with utilities.
Utilities are required to match energy supply with consumer demand, hour by hour and minute by minute. Demand (known as “load”) shifts throughout the day as the need for electricity changes. Meanwhile, individual generators may go offline unexpectedly, making less electricity available to meet demand. In general, grid managers have been able to meet these challenges with minimal disruptions to consumers. In recent years, however, this daily management effort has required new thinking due to the growth of distributed solar energy.
The blue line in Figure 4 shows an example of the shifts in the load pattern that utilities traditionally experience over the course of a day. Demand is low in the early hours of the morning when most people are asleep, then rises gradually to reach a peak in the evening hours. The green line shows how this pattern could shift as more distributed solar is installed. Under this new pattern, the level of solar generation increases after sunrise, allowing consumers to meet a portion of their electricity needs using the solar panels installed on their rooftops. This causes electricity demand to fall during midday, only to rise again in the evening. As a result, the utility needs to ramp down its traditional coal and gas generators at midday and ramp them up again closer to sundown.
Figure 4: Illustration of Daily Load Pattern Faced by Utility
This new load pattern, known as the “duck curve,” presents challenges for utilities in how they manage the electricity grid and maintain grid stability. Fortunately, solutions have recently emerged, including:
While these technological solutions are important, another important tool for managing grid demand is to change the structure for electricity pricing.
In recent years, innovative pricing structures have offered promising ways for utilities to manage the growth of distributed solar energy. These new pricing schemes help persuade consumers to manage their electricity use more economically by shifting their demand to more favorable times of the day and night. Research indicates that customers respond favorably to this approach. For example, many customers are willing to shift the hours they run their laundry machines and other appliances if the right pricing incentives are in place.
One approach is to use what is what is known as time-of-use (TOU) pricing and distributed locational marginal pricing (DLMP), which have historically been implemented for commercial customers but are increasingly being implemented for residential customers. Under TOU pricing, the cost of electricity changes based on the time of day and season of the year, with prices set at the highest levels during peak demand periods. DLMP compensation is based on benefit calculations tied to location, real-time demand, and grid congestion conditions. These pricing schemes are expected to grow more popular as metering continues to become more sophisticated, enabling the utility to track the solar energy transmitted to the grid on a minute-by-minute basis.
TOU rates are becoming an increasingly popular rate structure for residential consumers. In fact, California has recently implemented TOU rates for over 20 million consumers. Adoption of TOU rates has been historically slow, in part due to the slow deployment of the advanced metering technology that these approaches require. However, utilities can roll out new meters on a gradual basis while adopting new pricing schemes. For example, they can install new meters for large customers first and then do so for smaller residential and commercial customers.
Table 1 illustrates a traditional rate design and a “smarter” TOU rate design for a commercial electricity customer. The TOU alternative encourages the customer to concentrate high-use energy requirements during the peak solar energy period from 10 a.m. to 4 p.m. Usage during the afternoon “ramping” period, when solar output declines and demand goes up, would be much more expensive. A business subject to this TOU structure might decide to cool its premises during the early morning hours and then again after 10 a.m. (The business might also consider ending the workday at 4 p.m.!)
Table 1: Traditional Rate Design and the Time-of-Use Alternative
A more sophisticated pricing alternative is known as real-time pricing (RTP). Under this scheme, the utility charges prices that fluctuate hour by hour, and the price is directly linked to the real-time changes in the utility’s wholesale cost of electricity. So far, this approach has mainly been used for large industrial or commercial customers. However, it may become more widely available with the adoption of “smart” appliances that monitor and react automatically to changes in price. For example, a smart refrigerator may be set to automatically defer energy use to periods of the day when prices are low.
Two types of additional charges — “fixed charges” and “demand charges” —can, depending up on how they are implemented, interfere with desired price signals sent by time-varying rates. Fixed charges are assessed regardless of when or how much electricity is consumed. A fixed charge, thus, does not provide a price signal or influence when electricity is consumed. If fixed charges are too high, other price signals are muted. Thus, collecting too much revenue from fixed charges can lead to inefficient consumption of electricity.
Demand charges are associated with the maximum customer use at a given point in time. For example, say a school’s electricity use averages 50 kW per hour over a month, but use spikes to 200 kW per hour for a couple of evenings when they host football games. Using the traditional rate design in Table 1, the normal electricity charge would be $3,600 (24 hours * 30 days * 50 kW/hr. * $.10/kWh). The demand charge would be $2,000 (200 kW * $10/kW), representing 36% of the total electricity bill of $5,610 ($3,600 + $2,000 + $10 fixed charge). While demand charges give consumers an incentive to reduce the “peakiness” of their energy consumption, they don’t encourage customers to manage the time of day when the peak occurs.
In developing a rate design, goals should include providing accurate price signals to customers, ensuring that the rate design is easy for customers to understand, and ensuring that the rate design gives the utility the opportunity to meet its revenue requirement. Choosing fixed charges, volumetric charges, time of use charges, and demand charges in a way that meets all three of these goals is complicated. Nonetheless, getting price signals right is critical to helping customers choose how much electricity they want to consume, when they want to consume it, and whether they will invest in solar, storage and energy efficiency. Local governments will find it beneficial to engage with utilities on the optimal ways to set electricity prices and benefit the community.
Another common concern among utilities is the financial impact of solar deployment. A utility is likely to be worried that rooftop solar adoption will cut into its electricity sales and impact revenue. The policy choices discussed earlier in this chapter are an important part of the context. For example, a state with a generous net metering program will provide significant compensation to rooftop solar users selling energy back to the grid, reducing potential revenue for the utility. On the other hand, decoupling policies can provide incentives for utilities to support distributed solar without an adverse impact on profitability.
There has been spirited debate in recent years about the value that distributed solar brings to the electricity grid and whether solar customers are paying their appropriate share to access the distribution network. Utilities often raise concerns that non-solar adopters are subsidizing the grid usage of solar customers, an issue referred to as “cross-subsidization.” Proponents of solar energy argue that, when all the costs and benefits are accounted for, net metering frequently benefits all ratepayers. Research conducted by PUCs, national labs, and academic institutions continues to find that the economic benefits of net metering outweigh the costs and impose no significant increase for non-solar customers. Such benefits, as outlined by a review of 11 studies on the impacts of net metering, include reduced capital investment costs, avoided energy costs, and reduced environmental compliance costs. The studies reviewed for this analysis present findings from a variety of sources of which were commissioned or written by utilities, public utility commissions, and non-utility organizations. A list of the studies reviewed is presented below.
Table 2: List of Studies Reviewed by Environment America Regarding Net Metering
Distributed solar technologies also can weaken the business relationship between a utility and its customers. The proliferation of emerging software and hardware platforms to manage and operate DER has the potential to lessen interaction between utilities and their customers. This may hamper utility strategic planning, grid planning, and program development/management efforts if utility companies continue traditional approaches. In response, some utilities are considering and pursuing third-party acquisitions or partnerships to preserve relationships with their customers and more actively participate in the DER marketplace.
The growing penetration of rooftop solar on the electricity grid also presents technical challenges. For example, the two-way power flow from distributed solar introduces challenges to traditional utility grid planning approaches. A utility’s existing models may be insufficient for bulk system and distribution operators to accurately forecast, plan, and manage grid services. Better coordination and understanding of ways to manage distributed resources is necessary to ensure a resilient and reliable utility system.
In multiple geographies, the challenges posed by grid-connected solar are being addressed through proposed retail rate reforms that include demand charges, grid access fees, and minimum bills. Value of solar tariffs that recognize the technical benefits of solar (line losses, fuel/O&M savings, externalities, etc.) are also being pursued to more equitably treat grid-connected solar.
Some other common utility concerns about distributed and large-scale solar deployment are summarized in the table below.
Table 3: Utility Impacts Related to Solar Photovoltaic (PV) Deployment
These concerns should not overshadow the fact that solar energy can be very beneficial for the electricity grid, and even provide economic advantages, as long as it is managed in appropriate ways as summarized in Table 3 below. For example, when large-scale solar installations are located near areas of high electricity demand, this can help reduce system losses that occur when electricity is transmitted over longer distances. Strategic siting of PV arrays can also help defer or eliminate investments in upgraded infrastructure.
Significant deployment of solar energy, both utility-scale and distributed generation, can also defer the need for new grid capacity, thus delaying or entirely forgoing investments in conventional power plants that burn fossil fuels. Solar energy can also decrease the amount of time power plants are needed to operate, reducing their wear and tear and associated operation and maintenance costs.
Of course, one of the primary values of solar is its environmental impacts, since solar panels emit no greenhouse gases or harmful air pollutants. These impacts have a financial value based on public health impacts, as well as other benefits to society such as local job creation. Solar deployment helps state and local governments meet goals related to sustainability and climate change mitigation, such as carbon dioxide reduction targets and renewable portfolio standards.
Table 4: Utility Benefits of Solar PV Deployment
Notes: * System losses are power losses that occur when electricity is transmitted over long distances.
** Cycling is the process of changing the output of a power plant by starting up, shutting down, ramping up or ramping down.
The rising number of distributed solar installations has created new opportunities for how electric utilities can interact with customers and solar developers. These opportunities are outlined in Figure 5. Some of the near-term opportunities that are relatively easy to implement include:
Over the mid-term, utilities can use creative financing mechanisms to help facilitate consumer access to solar energy. For example, utilities can adopt on-bill financing that provides customers with loans that can be used to purchase solar PV systems (as well as energy efficiency improvements). Regular monthly fees are then added to the customer’s utility bill until the loan is repaid. In addition, Renewable Energy Credit (REC) loan programs allow customers to pay down the balance of their loans using the value of the renewable energy credits produced by their purchased solar PV systems.
Utilities can also adopt community solar programs, which makes solar energy available to those who cannot install it on their own rooftops. Community solar also benefits the utility because it can help preserve its customer base, since some customers would otherwise purchase rooftop solar and reduce their utility services. Moreover, community solar provides the opportunity to strategically site solar arrays in locations that improve grid reliability.
Meanwhile, utilities can add solar energy to the grid by investing in large-scale solar farms. Two opportunities to promote PV installation in profitable ways include solar development funds and utility asset ownership. In a solar development fund, a power company provides capital to a third party to develop solar projects in exchange for a negotiated rate of return and a portion of the project profits. Meanwhile, third parties use the utility’s capital to fund business activities and growth.
Another opportunity is to develop online interconnection application portals that make it easy for a customer to interconnect to the grid, saving time for utilities and consumers. Utilities can also provide a range of consulting services on PV system engineering, equipment sourcing, and installer referral to benefit consumers.
Other long-term opportunities for utilities require greater investment in time and money to execute, and in some cases, a fundamental shift in strategic mindset. For example, a partnership between a utility and a third-party operator (TPO) such as a solar company offers the potential for win-win outcomes that take advantage of a utility’s technical expertise and branding, along with a TPO’s customer acquisition prowess. By leveraging their customer relationships to focus on targeted grid areas that can more ably support solar PV deployment, utilities can help TPOs reduce their acquisition costs.
There are many opportunities for local governments to engage utilities, solar companies, and consumers in ways that benefit all parties. The challenge is to develop these opportunities in ways that can satisfy the objectives of all stakeholders. This is best achieved when local governments develop productive, ongoing relationships with their utilities as they work to meet their solar energy development goals.
Figure 5: Solar Market Opportunities for Utilities
A range of federal, state, and local standards stipulate the rules and requirements for connecting to the grid. These standards have been developed to uphold grid reliability, safety, and economic objectives. Ultimately, these rules are intended to provide clear guidance on the timelines, fees, technical requirements, and steps in the application review and approval process for rooftop solar and other distributed energy generation.
Figure 6 provides an overview of the interconnection requirements in the United States. Some of these rules are mandatory, while others are voluntary. Collectively, their aim is to convey a uniform interconnection approach that coordinates among multiple standards, certifications, and codes. These standards are updated periodically to keep pace with technology advances and the evolving nature of the electricity grid.
Figure 6: Overview of Various U.S. Interconnection Requirements
At the national level, the Federal Energy Regulatory Commission (FERC) has authority over all interstate and wholesale electricity commerce, while states have jurisdiction over intrastate interconnections. State-level standards and their implementation differ by location. States often incorporate elements of voluntary directives put forth by independent entities like the Institute of Electrical and Electronics Engineers (IEEE), a professional organization.
Since its inception in 2003, IEEE Standard 1547 has served as the primary basis for interconnection agreements, rules, and technical requirements for rooftop solar and other distributed energy in North America. It focuses on the requirements relevant to the performance, operation, testing, safety, and maintenance of the interconnection. The standard has been updated repeatedly to address increasing penetration levels of distributed solar within the grid.
The figure below illustrates the process for a technical review of an interconnection application. Each successive review step, if required, provides an increasingly comprehensive assessment of the technical concerns raised by an application. These concerns can involve a system’s size and configuration or the location where a system intends to interconnect, among other issues.
Figure 7: Technical Review Process Overview
Many states have recently updated or are planning to update their interconnection standards to streamline their processes or automate them through online portals. These updates focus on clearly identifying fees associated with the process; specifying milestone timelines; standardizing and simplifying forms; and promoting information transparency and open communication.
Apart from any federal or state regulation, utilities also have many options for improving the interconnection process, as summarized in the table below. These options fall under two categories: administrative and technical. Administrative improvements include developing an online application and providing an online application checklist to ensure customers clearly understand the requirements to complete an application. Technical improvements may include offering fast-track interconnection for small systems that do not require technical review or updating review criteria to keep pace with screening methodology advances. These best practices could help utilities support the further adoption of rooftop solar (and other distributed energy resources) in responsible ways.
Table 5: Utility Practices and Opportunities for Improving the Interconnection Process
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