Compensating Solar Producers

Paying customers who send electricity to the grid is a relatively new approach for utilities. The most broadly used practice to compensate consumer-producers, which spread rapidly during the past two decades, is net-metering. This approach of crediting customers at retail rate for the energy they produce arose when solar was a very small player in the energy market. The rapid increase in rooftop solar adoption has driven discussion on net metering and rates in nearly all states. Much of the conversation revolves around whether net metering, or other compensation methods, are best for creating a level playing field without shifting costs from one customer to another.

Net Metering

The most common policy, active in 36 states, for compensating distributed solar owners is net energy metering, also known as net metering. Net metering policies allow distributed generation customers to sell excess electricity to the utility at retail rate and receive credit on their utility bill. The credit offsets the customer’s electricity consumption during other times of the day, reducing the amount of electricity the customer needs to purchase.

Net metering is seeing significant growth. In 2017, approximately 2.2 gigawatts of net-metered solar capacity were added to the grid.^{Ref. 24} Minnesota was the first state to adopt net metering compensation at the retail rate in 1983 and at the policy’s height, 44 states, Washington, D.C. and several territories had net metering policies.^{Ref. 25}

Net Metering Authorization

• States with net metering policies
• States with voluntary utility policies
• States with distributed generation compensation rules other than net metering.

Source: NCSL and Database of State Incentive for Renewables and Efficiency (DSIRE)

Thirty six states, Washington, D.C., and five territories provide net metering as of September 2018. Utilities in two additional states—Idaho and Texas—have voluntarily adopted net metering programs.^{Ref. 26} At least nine states—Arizona, Georgia, Hawaii, Indiana, Maine, Mississippi, Nevada, New Hampshire and Utah—have statewide distributed generation compensation rules other than net metering. As of September 2018, at least two additional states—Connecticut and Michigan—have passed legislation or issued public utility commission decisions to phase out retail rate net metering after a certain date. Connecticut and Michigan will continue to provide traditional net metering until the specified time, and existing net metering customers will be grandfathered under the previous rate for a specified period. For more information regarding compensation policies other than net metering, see the “Alternative Compensation Methods” section.

Georgia Power—Georgia’s largest electric power company—credits distributed generation customers at the avoided cost rate (the marginal cost for a producer to generate one more unit of power), which has attracted very few subscribers.^Ref.27 Mississippi’s policy credits customers at the utility’s avoided cost plus a premium for electricity exports.

Net Metering Policy Variations

While a majority of states and territories have authorized net metering, they have taken differing approaches by varying capacity limits, eligible technology, net metering credit retention and renewable energy credit (REC) ownership.

Capacity Limits
States can set system capacity limits to regulate the size of net metered installations. They can also establish aggregate capacity limits—also called aggregate caps—to regulate the amount of net metered systems that are allowed to participate in a state’s or utility’s net metering program.

Individual system capacity limits are determined in a variety of ways and differ across states. For example, Wisconsin has authorized net metering for systems up to 20 kilowatts (kW), while Arizona caps systems at 125 percent of a customer’s total connected load. Nearly half of states with net metering policies have system capacity limits of two MW or less, while at least one state—Ohio—has authorized net metering with no specific capacity limit. System capacity limits can also vary based on utility type or provider (Oregon and Colorado), customer type (West Virginia), technology (New York) and system type (Pennsylvania and Connecticut).

While some state net metering policies specify an aggregate capacity limit, other states have not, and a few states have discretionary caps. Most states with aggregate caps have percentage-based caps that are based on the peak demand, while a handful of states specify the number of megawatts covered by the cap. Aggregate caps can vary with regard to utility type or provider (Hawaii) and customer type (Massachusetts).

Eligible Technology
States include a variety of technologies in net metering policies. While all states with net metering include solar PV in their policies, they may also include: wind micro-turbines, combined heat and power or cogeneration, biomass, biogas, landfill gas, municipal solid waste, anaerobic digesters, geothermal electric, fuel cells, small hydroelectric, tidal energy, wave energy, ocean thermal and fuel cells powered by renewable sources.

Compensation
State policies address how long customers can maintain or “roll over” bill credits for net metered electricity. Virtually all states credit excess generation to the next monthly billing period or allow distributed generation customers to select this option. Not all states, however roll over credit at the full retail rate.^Ref.28 An important distinction among policies is whether credits for excess generation can expire or can be carried over indefinitely; states have taken a range of approaches to address this. For example, Alaska credits excess generation to a customer’s next bill and credits may be carried over indefinitely. In Hawaii, excess generation is credited to a customer’s next bill at retail rate, but excess credits are granted to the utility at the end of an annual billing cycle. These compensation policies may vary based on factors such as system size (Minnesota) or technology (New York).

Rec Ownership
Net metering policies may specify ownership of renewable energy credits created by the system, since these credits can be valuable. Renewable energy producers are eligible to earn RECs for electrical generation and states can determine who owns the REC. Many states with net metering have determined that distributed generation customers own RECs, however, in a handful of states—including Kansas, North Carolina and Vermont—utilities own RECs. REC ownership is also discussed in the “Ownership” section.

Types of Net Metering

In recent years, a number of states have differentiated how net metering policies apply to different customer types.

Conventional net metering, sometimes referred to as individual net metering, connects a generating source to a single meter, such as a house or building.

Aggregate net metering or meter aggregation allows a single customer to aggregate multiple electric meters on his or her property and offset the combined electrical load using a centralized renewable energy generating system.

Virtual or community net metering allows multiple customers to offset their individual loads using a centralized renewable energy system. This approach facilitates net metering for more customer types, including non-profits, multi-unit residences, renters, municipalities and others who are unwilling or unable to install individual distributed generation systems on their property.

Note: See Map "State Net Metering Policies" for conventional net metering authorization.

Aggregate Net Metering

Meter aggregation, also called aggregate net metering, allows an individual customer to offset electrical use from multiple meters on his or her property, using a single renewable energy generating system also located on the owner’s property. For example, farmers often have separate electric meters on different buildings or processes on their farm. With aggregate net metering, they can use net metering credits generated from one renewable energy system located on their property to offset the load from multiple meters on the same property or their adjacent properties.

States with Meter Aggregation/Aggregate Net Metering

Source: NCSL

Shared Renewable Energy

Virtual and community net metering, as well as initiating shared renewable programs or pilots, allow the creation of shared renewable energy programs, which offer customers who are unable or unwilling to install on-site distributed generation systems the opportunity to benefit from distributed renewable energy generation. Shared renewable programs can provide access to renewable energy to customers in multi-family residences, condominiums or those with roofs incompatible with solar arrays.

This emerging market segment of solar grew by roughly 25 percent in 2017, as more states enabled shared renewable energy and developed installations.^Ref.29 At least 20 states and Washington, D.C., have legislation authorizing shared renewables. States can adopt different policies to arrive at the same outcome of developing shared renewable systems:

State Shared Renewables Action

• State with shared renewables legislation
•  States with active shared renewables programs
• States with shared renewables legislation and active programs

Source: NCSL

While the majority of shared renewables projects are solar projects, there is also a small number of shared wind projects operating in several states. At least 12 of the states with shared renewables legislation, and Washington, D.C., include provisions to allow for other renewable energy technologies than just solar, such as wind, biomass or geothermal.
 
Similar to individual net metering, appropriate valuation of shared renewables presents a challenge for regulators and remains an ongoing discussion. Determining a value for compensating generation from shared renewables facilities can be difficult, and although many stakeholders agree that credit for generation should be included, there are varying opinions on including transmission and distribution costs in compensation systems. In general, compensation rates and the perceived value of the renewable energy produced are specific to the communities in which shared renewables projects are located.

Alternative Compensation Methods

While net metering policies have been responsible for expanding access to the benefits of distributed renewable energy, they have also generated questions of equity and cost-shifting. Originally designed to spur a nascent technology, net metering’s success has led to debates on the policy’s sustainability in virtually every state legislature or utility commission.

Critics argue that the compensation received by net metering customers allows them to avoid paying for the cost of maintaining electric grid infrastructure, shifting this cost to utility customers that don’t own solar. Additionally, some feel distributed generation users should not be credited at the retail rate for excess electricity generation, but rather at the avoided cost or wholesale rates.

Net metering supporters contend that net-metered resources, such as solar, provide utilities with economic benefits by supplying energy at peak times when producing and acquiring energy is most costly, reducing the need for transmission upgrades or the construction of new generation, while contributing to reliability and emissions goals.

Some utilities, especially investor-owned utilities, are concerned about net metering in part due to the way they are regulated in most states, where they earn a return on the capital they own and recover most of their costs through electricity sales. Net-metered solar reduces utility sales and utilities’ potential to earn income on new capital investments as well. Numerous discussions are taking place in states across the U.S. about how to regulate utilities in a way that better aligns customer and utility goals, particularly when it comes to distributed generation sources such as rooftop solar. In 2017, 31 states and Washington, D.C. took action—either proposing or adopting important policy changes—on distributed generation compensation, according to the North Carolina Clean Energy Technology Center.^Ref.30 Additionally, at least 21 states took action on solar valuation or net metering studies

State legislatures and public utility commissions (PUCs) are debating the best way to balance customer demand for distributed generation with the impacts new technologies have on the electric power grid. The increase in net metered solar has launched a comprehensive discussion about properly evaluating the effects and benefits of new technologies, such as energy storage, smart meters, distributed energy and energy management tools. Several of the alternative methodologies described below attempt to comprehensively value distributed energy resources (DER), not only solar energy.

It should also be noted that each of these methodologies can be addressed through one of two general approaches: net billing or “buy-all, sell-all.” A net billing approach allows customers to consume energy generated behind the meter with a retail rate credit, while exported energy is credited at a different rate. A buy-all, sell-all approach credits all exported energy at a non-retail rate and does not allow for behind-the-meter consumption.^Ref.31

Recent Policy Changes

As of September 2018, at least nine states—Arizona, Georgia, Hawaii, Indiana, Maine, Mississippi, Nevada, New Hampshire and Utah—have ended conventional, retail rate net metering and adopted alternative distributed generation compensation rules in its place. At least two additional states—Connecticut and Michigan—have passed legislation or issued public utility commission decisions to phase out retail rate net metering after a certain date.

Examples of recent policy action to adopt alternative distributed generation compensation rules include:

In addition to the examples listed above, a handful of states including, California, Hawaii and New York, have explored next generation compensation approaches, some of which attempt to comprehensively value distributed energy resources (DER), not only solar energy. Several of these approaches also incorporate principles of locational valuation and dynamic pricing.

California's Successor Tariff

In 2013, California passed Assembly Bill 327 requiring the California Public Utilities Commission (CPUC) to create a successor tariff for net metering, also termed NEM 2.0. The legislation assigned program limits for the state’s three major utilities based on generating capacity. Once programs reach their caps or after July 1, 2017, utilities must offer distributed generation customers a standard contract or tariff determined by the California Public Utility Commission. The CPUC decided in January 2016 to preserve the retail rate credit through 2019 and guarantee net metering credits for existing customers for 20 years after they are connected. The decision also requires all new net metering customers to be subject to provisions under a new successor tariff, which includes interconnection fees, non-bypassable charges for all electricity consumed from the grid and participation in time-of-use rates.

Hawaii's Grid-Supply and Self-Supply

In 2015, the Hawaii Public Utilities Commission issued a ruling that ended conventional net metering.^{Ref. 35} All new grid-connected customers with solar, are required to choose between a “Self -Supply,” a “Smart Export,” and a “Controllable Customer Grid Supply” option. Customers under the Self-Supply option are not allowed to export excess electricity to the grid and would need to use energy storage to decrease their electricity consumption from the grid and reduce their electricity bill. Self-supply customers are also eligible for an expedited review and approval of their systems. Under the self-supply option, residential customers are required to pay a minimum bill of $25 per month and small commercial customers are required to pay a minimum bill of $50 per month. Under the Smart Export program, customers with a renewable energy and energy storage system have the option to export energy to the grid between 4 p.m. and 9 a.m. Customers that choose the Controllable Customer Grid Supply option can export energy to the electric grid throughout the day but must use equipment that allows the utility to manage their solar installation’s output.  A “Customer Grid Supply” option was previously available; however, the program reached its total capacity limit in 2017. The Grid-Supply option functioned like conventional net metering, however customers were compensated at a location-based fixed rate for excess electricity sent to the grid.  All existing Customer Grid Supply customers are grandfathered for five years.^{Ref. 36}

Location-Based Valuation

As DG proliferation increases, states are exploring alternative valuation methods that incorporate the value of the benefits that distributed energy resources provide to the grid. One such method is location-based valuation, or locational valuation. Through this model, value is placed on the benefits that DER provide to the local distribution system. The value of DERs to the local distribution grid depends on their location on the distribution grid as well as the qualities of DER that contribute the necessary characteristics of availability, dependability and durability to the grid. Locational valuation provides incentives for DER that are sited in locations with optimal grid integration or those that are close to load centers. Distributed generation that is intentionally sited may also reduce grid congestion and the need to make costly upgrades.

Several states are exploring location-based valuation for distributed generation, particularly those with high solar and DG penetration, including California, Hawaii and New York. A small number of states are studying ways to value DERs based on their location and to deploy DERs at optimal locations and in ideal quantities to maximize their benefits to the grid and reduce utility customer costs.

California’s PUC is currently undertaking two proceedings, the Integration Capacity Analysis (ICA) and the Locational Net Benefit Analysis. Together, these proceedings are designed to provide a better understanding of where distributed resources can be added to the grid without infrastructure upgrades and their value at each location. In the ICA proceeding, the state’s three big investor-owned utilities—San Diego Gas &Electric (SDG&E), Pacific Gas & Electric (PG&E) and Southern California Edison (SCE)— are collaborating with DER providers to study the characteristics of local distribution systems to develop a better understanding of where customer-sited resources can be readily added to the grid. In its draft final report, the ICA working group identified the proceeding’s two primary objectives: to improve the DER interconnection process through identifying how much DER can be added at any interconnection point on the distribution system and to integrate DER into utilities’ distribution system annual planning through identifying optimal locations for future DER development.^{Ref. 37} Working with DER providers, the three utilities will meet these objectives by developing a methodology to identify optimal grid locations where DERs can connect and by creating publicly-accessible online system maps that include detailed, downloadable system data. Among the states currently studying location-based valuation of solar and other DER, California’s investor-owned utilities are further along than any other U.S. distribution system operators in mapping granular distribution grid data.

Similarly, New York is also addressing locational valuation as part of the state’s Reforming the Energy Vision (REV) initiative. This initiative is New York’s foundational proceeding that aims to transform the state’s energy economy into one that focuses on customers, embraces market and business model innovation, and is efficient, clean and reliable.^{Ref. 38} One of the primary purposes of the REV initiative is to “develop accurate pricing for DERs that reflect the actual value DERs create.”^{Ref. 39} To study the value of DER to the state’s grid, the state Public Service Commission (PSC) is employing the LMP+D model. In this model, “LMP” is the locational marginal price of energy on the wholesale side, and “D” represents the value of the distributed energy resources to the distribution grid. According to this model, the full value of DER to the system will only be complete when the value of the DERs on the distribution grid are added to the location-based marginal wholesale price of the energy.

In April 2017, the New York PSC issued the Value of Distributed Energy Resources order as part of the REV initiative. The Value of DER Order (or VDER) establishes a new pricing methodology, which is based on the avoided utility cost combined with additional metrics that place values on qualities such as location and environmental benefits.^{Ref. 40} The order required utilities to file schedules and work plans within 45 days to develop new pricing values, and in July 2018, the New York PSC filed two white papers suggesting improvements to the VDER Tariff.^{Ref. 41} Rooftop solar will continue to be eligible for full retail net metering until 2020, when compensation credits will gradually decrease.

Tariffs

Tariffs are regulatory commission-approved frameworks and rules that dictate how DG customers are compensated for their contribution to the grid. In addition to fairly compensating DG customers, these frameworks must also preserve the financial integrity of the utility and ensure equity for non-DG customers. While net metering is the most widely-implemented method for compensating distributed generation, feed-in tariffs and value of solar tariffs have also been adopted for DG compensation.

Feed-in Tariffs

Feed-in tariffs (FITs) were originally designed to support nascent renewable energy technology, provide incentives for investing in new technologies and reward early adopters. This tariff structure functions similar to a power purchase agreement (PPA). Under a FIT, customers enter into a long-term contract with a utility and sell all the output from their renewable energy system to the utility at a pre-determined rate for a fixed amount of time. Customers then purchase all their electricity from the utility at the retail rate. Instead of designing the compensation rate around the utility’s avoided costs or the value of the energy produced, FITs typically base the rate on the customer’s cost for the distributed generation investment.

While FITs have been adopted in several European countries, they have been less commonly used in the U.S. One reason for this low adoption is the conflict between this tariff structure and PURPA, which prevents state utility commissions from requiring utilities to pay more than their avoided costs for purchased energy. To sidestep PURPA, the compensation rate for many of the FITs adopted in the U.S. have been set through market forces, by state legislatures or by utilities on a voluntary basis.

Although there has been little activity on feed-in tariffs in the last couple years, more than half a dozen states and at least one U.S. territory have adopted feed-in tariffs at either the state, municipal or utility level. For example, in 2009, Vermont enacted House Bill 446 adopting a FIT and requiring all retail electricity providers to purchase electricity generated by solar, wind, biomass, landfill gas, farm methane and hydroelectric facilities. Contracts for solar under the FIT are between 10 and 25 years. In response to 2012 legislation, the Vermont Public Service Board (PSB) established a new market-based pricing mechanism that awards contracts through a Request for Proposals process.^{Ref. 42} In 2014, the Virgin Islands enacted Legislative Bill 4 requiring the Public Services Commission to create a FIT for solar PV systems. The resulting program offers solar PV customers a standard contract with terms between 10 and 30 years and compensates them at $0.26 per kilowatt hour (kWh). The compensation rate will be periodically reviewed based on the avoided cost rate of the utility. While California and Hawaii have established feed-in tariff programs, as of September 2018, both programs are closed to new applications or contracts.^{Ref. 43}

Value of Solar Methodology

A number of states have considered the value of solar (VOS, or VoST) tariff as a replacement for net metering. This compensation method is designed to capture the value that solar installations provide, along with costs they may create, for the electric system. Under existing VOS program designs, solar customers continue to purchase all their electricity from the grid at the utility’s retail rate while receiving credit for the electricity produced by their panels at the approved VOS rate. Unlike net metering, customers are charged for all electricity they consume and credited for all electricity they produce and are not credited for the net amount exported to the grid.

The VOS rate attempts to include the variety of costs and benefits that solar may create for the grid rather than simply crediting the fixed retail rate. The VOS rate is locked in for a specified period of time—more than 20 years in Minnesota for example—whereas net metering credits fluctuate with the retail price. By including both costs and benefits, the VOS rate addresses the concerns of cost-shifting to non-solar customers. VOS may allow utilities to better understand and manage electricity demand by allowing them to see how much solar electricity is being generated by the consumer along with how much they are consuming.

Only Minnesota and Austin, Texas, have adopted VOS policies to date. Austin’s VOS program is active for residential customers of the city’s municipal utility. However, as of January 2017, no eligible utility in Minnesota has chosen to implement a VOS rate. In 2013, Minnesota enacted House File 729 requiring the Minnesota Department of Commerce to develop a “value of solar” methodology for the Minnesota Public Utilities Commission (PUC).^{Ref. 44} The tariff will serve as a voluntary alternative to net metering. The Department of Commerce was required to submit a final methodology in January 2014 to the PUC and the PUC approved the tariff in April 2014. The legislation also authorized community solar gardens (see “Shared Renewables” above). If a utility elects to use the VOS, this tariff also applies to community solar garden customers.

Hawaii’s Community-Based Renewable Energy Tariff

Another example of a tariff structure is Hawaii’s community-based renewable energy program. In 2015, Hawaii enacted Senate Bill 1050 that required electric utilities to design a community-based renewable energy tariff to be filed with the Hawaii Public Utilities Commission (PUC) by October 2015. In response to utility filings, the Hawaii PUC filed an order in February 2017 creating a tariff framework for compensating community-based renewable energy projects that will be rolled out in two phases.^{Ref. 45} Compensation for participating projects will vary based on project location and the time of day the project provides power. The order established specific rates for midday, on-peak and off-peak hours. The framework also breaks down participating projects into three categories—standard projects, peaker projects and utility projects—based on operating entity, output during peak hours and percent of capacity provided to low- and moderate-income customers. Rates will range from $0.15 per kilowatt hour (kWh) to nearly $0.33 per kWh, depending on the island and the time of day.

Solar Incentives

Much of the content referenced in this section is from the North Carolina Clean Energy Technology Center’s Database of State Incentives for Renewables and Efficiency (DSIRE). Visit the DSIRE database for additional information.

While other sections of this publication have explored solar regulations, policies and programs, many states seek to encourage solar energy through financial incentives. Tax credits, direct cash incentives, RPS or RES policies and others, also can encourage solar deployment. Financing also serves as a market building policy, although it is discussed in a subsequent portion of the toolkit. These types of incentives reduce the cost of solar systems by either lowering the initial cost of a system or providing financial benefits after installation. The two most common types of state financial incentives are cash and tax incentives. While this section focuses on incentives for solar PV systems, other technologies such as solar thermal and passive solar may be included in these incentives.

Renewable Portfolio Standards/Renewable Energy Standards

The policy intent of Renewable Portfolio Standards is to drive the growth of renewable energy generation. These standards require utilities to sell a specified percentage or amount of renewable electricity. As of September 2018, 29 states, Washington, D.C., and three territories have adopted an RPS, while eight states and one territory have set non-binding renewable energy goals. Utilities can satisfy RPS requirements through building new generation or buying renewable energy certificates (RECs) and solar RECs (SRECs).

Renewable Portfolio Standards

• States are territories with Renewable Portfolio Standards
• States and Territories with a voluntary renewable energy standard or target
• States and territories with no standard or target

Source: NCSL

Some states have established solar or distributed generation set-asides or carve-outs, requiring that a certain percentage of a state’s RPS be met with solar energy or DG. States have also established credit multipliers for solar and distributed generation. At least 21 states and Washington, D.C. have an RPS with solar or distributed generation provisions. For example, Illinois requires that 6 percent of the annual requirement under the state RPS be met with solar PV, while Delaware requires that 3.5 percent of the annual requirement is met with solar PV by 2025-2026. Oregon and Washington have established solar and distributed generation credit multipliers under their RPS policies. Oregon has a credit multiplier for solar PV installed before 2016, while Washington has a credit multiplier for distributed generation. Depending on state regulatory structures, utilities may meet RPS or carve-out requirements by building new generation or by purchasing RECs from third parties or customer-owned generation.

Several states—including Delaware, Illinois, Massachusetts, Maryland, New Jersey, Ohio and Pennsylvania—and Washington, D.C. have specific SREC programs. The New Jersey Board of Public Utilities (BPU) requires investor-owned utilities in the state to enter into long-term contracts for SRECs as a means of increasing price certainty.^{Ref. 71} However, in accordance with legislation enacted in May 2018, the BPU approved a rule to adopt new regulations to shutter the current SREC program by June 2021 or once solar reaches 5.1 percent of the state’s electricity generation.^{Ref. 72,73}, The BPU will soon launch a study to evaluate replacements for the SREC program. Massachusetts made significant changes to the state’s SREC program in early 2017, by replacing it with the Solar Massachusetts Renewable Target (SMART).^{Ref. 74} Under the new program, 1,600 MW of solar would be developed in 200 MW blocks, with declining incentives for each subsequent block. Incentives would be based on customer classes, with additional incentives for projects on preferred locations or serving low-income customers.

Tax Incentives

Tax incentives are one of the most common types of financial incentives for solar and other renewable energy sources. Relative to other forms of financial incentives, tax credits are fairly simple to administer and are generally more politically viable than direct cash incentives because they do not require states to appropriate funds. However, certain entities that do not have a tax liability, such as schools and government facilities or low-income customers may be unable to take advantage of these incentives. Several types of tax incentives exist, including personal and corporate investment tax incentives, property tax incentives and sales tax incentives.

Personal and corporate investment tax incentives provide a direct reduction in a taxpayer’s tax liability for a portion of the cost of purchasing and installing a solar energy system. While these tax incentives are typically implemented at the state-level, municipal governments can also offer credits or exemptions for income, franchise or other similar taxes to encourage solar development. More than a dozen states offer personal and/or corporate investment tax credits.

As installing a solar energy system typically increases an entity’s property tax burden, states have established property tax incentives. These incentives mitigate or eliminate the increase in assessed value of a property attributable to a solar energy system installation. Property tax incentives are particularly viable in states with high property tax rates.

More than half of states have established statewide property tax incentives. Several other states have established local option property tax exemptions, which authorize, but do not require, municipalities to pass ordinances to exempt residential renewable energy systems from taxation. In response to the recent growth in large-scale solar facilities, a handful of states have developed separate tax incentive policies for utility-scale solar generating facilities. For example, Nevada allows new and expanded businesses to apply for a property tax abatement of up to 55 percent for up to 20 years for real and personal property used to generate electricity from renewable energy resources including solar.^{Ref. 75} Eligible generation facilities must have a capacity of at least 10 megawatts and must plan to be in operation for at least 10 years. Furthermore, Colorado enacted House Bill 1101 in 2014 exempting a portion of community solar gardens from property tax. The percentage of electricity capacity of a community solar garden that is attributed to residential subscribers, governmental subscribers or certain organizations is exempted from property tax.

Finally, states have established sales tax incentives to reduce the costs of installing a solar energy system. These policies provide an exemption from or refund of sales tax for the purchase and installation of solar energy components and systems. Nearly half of states offer some form of sales tax incentive for solar installation, while a handful of states authorize, but do not require, local governments to provide sales tax incentives for solar installations.

Public Benefits Funds

Another policy tool that states can use to provide long-term funding for renewable energy programs, including solar, is a public benefit fund (PBF). Public benefits funds are typically formed through adding a small surcharge on electricity consumption by customers (typically served by investor-owned utilities), however some states have established PBFs as a result of utility merger settlements and other activities. States establish PBFs to provide direct incentives and financing for renewable energy projects, energy efficiency, low-income programs, business development and industry recruitment activities, as well as research and development. States can establish state level PBFs or grant municipalities authority over their local electric utility to establish PBFs. Additionally, states can allow municipal utilities or electric cooperatives to “opt-in” to state-level PBF programs. Nearly half of states have established public benefits programs that support solar projects.

Direct Cash Incentives

Direct cash incentives—rebates, grants and performance-based incentives—reduce the initial equipment costs for solar energy systems. The policy intent of direct cash incentives is to stimulate markets, such as early stage solar deployment, or for low-income customers. Although unlike tax incentives, direct cash incentives apply to a broad range of participants (including non-taxpaying entities), they require explicit funding mechanisms. Direct cash incentives are typically implemented at the state level and by individual utilities, however local governments may offer these incentives also. The majority of states offer some type of direct incentives for solar that are either implemented at the state level or by individual utilities.

Rebates, which are incentive payments issued to a purchaser after a solar energy system has been installed, are one type of direct cash incentive. Rebate programs can be implemented at the state or local government level or by individual utilities. Nearly half of states have rebate programs that for various solar technologies, including solar PV. A majority of these PV-eligible rebates are for residential customers and include several common approaches, such as percentage-based, production-based or flat-rate rebates, or a combination of these. While there are common structures for rebates, states offer a range of compensation. For example, Wisconsin offers a rebate for 12 percent of residential and commercial solar PV installation costs, while California offers a rebate of up to 75 percent of system costs for solar PV on affordable housing. New Jersey’s new residential construction rebate for solar PV is a flat-rate incentive based on housing type (single-family, multi-family, etc.) with individual maximums established. Delaware offers a rebate to Delmarva Power customers based on production, customer class and ownership model (for residential customers only). For example, residential customers with solar leases or power purchase agreements receive a flat incentive of $1,000 while resident-owned systems receive $0.55 per Watt for the first 5 kW and then up to $0.20 per watt for up to 50kW.^{Ref. 76}

Grants provide funding for larger projects and typically involve more detailed, competitive applications. For example, Maryland has at least two state-implemented clean energy grant programs that incorporate solar: the Residential Clean Energy Grant Program and the Commercial Clean Energy Grant Program. The residential program provides financial incentives to homeowners that install solar water-heating, solar PV (up to 20 kW) and geothermal heating and cooling systems.^{Ref. 77} Grants are available on a first-come, first-serve basis, and when funds are exhausted, additional funds may be appropriated in the annual budget. Through the commercial program, Maryland offers grants for solar water-heating, solar PV (up to 200 kW) and geothermal heating and cooling systems installed by businesses, nonprofits and local governments.^{Ref. 78} Grants are available on a first-come, first-serve basis, and the program expires when funding is exhausted.

Performance-based standards, also known as production-based incentives, help secure financing and offset financing costs through providing a revenue stream. This type of incentive is based on the actual energy output of a renewable energy or solar energy system and are disbursed over a specified time period. Feed-in tariffs and RPS REC purchase programs are two types of performance-based standards. Performance-based standards exist for various utilities in nearly half of states.

Feed-in tariffs require energy suppliers to buy electricity produced from renewable resources at a fixed price, usually at a premium price over a long-term period. While this policy has not been widely adopted in the U.S., several states, localities or utilities have established feed-in tariffs.

Community Choice Aggregation

Another policy that states have implemented to encourage the adoption of renewable energy, is community choice aggregation. These policies enable local entities to aggregate electricity contracts within a specific jurisdiction to procure electricity as a group, rather than as individuals. Those with aggregation still retain their existing electricity provider for transmission and distribution services.

States may consider allowing aggregation as a way to give local governments the means to reduce electricity costs, provide power from local sources or purchase energy from renewable sources. A handful of states allow for community choice aggregation. According to the most recent data, in 2016, approximately 3.3 million customers received 8.7 million megawatt-hours of renewable energy through CCAs, up from 7.4 million megawatts delivered to 1.9 million customers from CCAs in 2015.^{Ref. 79} For the most recent year compiled, Illinois continues to lead in CCA participation with more than 2 million participants, while Massachusetts showed the largest market growth.^{Ref. 80}

States with Community Choice Aggregation Policies

Source: NCSL

Industry Recruitment and Support

States and local governments have implemented various financial incentives to encourage growth in solar and renewable energy businesses, create jobs and provide customers with increased access to renewable energy. Industry recruitment and support incentives are typically loans, grants and tax incentives—including property tax abatements and corporate tax exemptions and credits. These incentives are designed to promote the establishment or expansion of renewable energy manufacturing operations and support research, development and commercialization efforts, as well as encourage private partnerships to invest in solar and renewable energy companies.

More than a dozen states currently have solar industry recruitment and support incentives. States have taken a variety of approaches with these incentives. For example, states may create programs that have minimum thresholds for job creation, production output and investment. Incentives may also be based on product sales from a manufacturing facility. Additionally, states can grant local governments the authority to establish industry development programs.

Bonds

A handful of states have established renewable energy bonds that include solar technologies. For example, New Mexico established a bond program that authorizes up to $20 million in bonds to finance energy efficiency and renewable energy improvements in state government and school district buildings.^{Ref. 81} Idaho passed Senate Bill 1192 in 2005 allowing non-utility developers of renewable energy projects—including solar PV and solar thermal—in the state to request financing from the Idaho Energy Resources Authority, a state bonding authority. Finally, Utah created a local option industrial facilities and development bonds program that allows counties, municipalities and state universities to issue Industrial Revenue Bonds or Industrial Development Bonds to promote industrial development and manufacturing facilities. The program was expanded in 2013 to include energy efficiency upgrades and renewable energy systems as eligible projects.^{Ref. 82}

Ownership Models

In addition to traditional ownership models, a variety of other arrangements have arisen in recent years. Ownership models vary based on size, customer access, financing and additional factors.

Utility Ownership

Depending on state law, utilities may be able to own a combination of community or shared solar, and smaller rooftop solar generation. Utilities see several financial and logistical benefits to owning distributed and shared solar energy generation. Utilities realize revenues and benefits through owning and maintaining distributed generation, as opposed to experiencing reduced cost recovery caused by lower electricity consumption and lost capital investment when the asset is owned by a consumer or third party. Since utilities have an existing billing relationship with their customers, they have access to a large base of potential solar customers, including low- and moderate-income households. Utilities also have an idea of where solar installations may benefit the grid and best satisfy congestion or peak demand needs. They may also have a streamlined process for permitting, financing and planning new energy installations that can reduce costs and time.

Utilities are capital-intensive entities with a large customer base that are often able to recoup investments through rates. Thus, they have access to favorable financing and may receive significantly more competitive interest rates than other entities. Utilities may have difficulty passing on the benefits of federal tax incentives to their rate base however, under the Internal Revenue Service’s normalization rules. Finally, utilities can meet state Renewable Portfolio Standards by owning these assets. Increasingly, large corporations are seeking to meet aggressive renewable energy goals or carbon emissions reductions with commercial-scale renewable energy purchases. If utilities can satisfy this demand through distributed solar, they are at lower risk of losing electricity sales.

However, utilities are monopolistic enterprises and other solar stakeholder may be wary of the effects that a lack of competition may have on customer costs. Utilities’ ability to include costs in rates places them at an advantage over independent power producers and third party companies, since they don’t have to compete to keep costs as low as possible. Also, since they are virtually guaranteed an opportunity to recoup their capital costs, utilities may have a competitive advantage over non-utility entities that must remain profitable to survive.

Utilities in traditionally regulated states can own large-scale solar energy generation, while investor-owned utilities in restructured states may be restricted from owning generation, except in certain circumstances. Additionally, in the 20 states and Washington, D.C., that have authorized shared renewables, utilities can own those installations in just 10 of those jurisdictions. Given this limited number of states, only about 33 percent of all shared renewables programs nationally are utility-administered, according to the Smart Electric Power Alliance.^{Ref. 83}

Although states may prohibit utilities from owning distributed solar generation, there have recently been more efforts to explore utility DG ownership. In July 2015, Georgia Power launched a solar sales and installation service through an unregulated arm of the utility. The entity, Georgia Power Energy Services, will determine if homeowners are eligible for a distributed solar system, and then either provide installation services or connect the customer with an installer. Georgia Power does not offer financing or leasing to customers. While the program received high customer interest in its first year, a small number of contracts have been signed.

In 2014 the Arizona utility Tucson Electric Power (TEP) received permission from the Arizona Corporation Commission to launch a utility-owned residential solar program. The program is limited, with a $10 million spending cap, and adds customers in 3.5 MW blocks. Program participants have a $250 processing fee and receive a set, 25-year compensation rate based on historical consumption. TEP contracts with third party entities to install and maintain the solar energy systems. Another Arizona utility, Arizona Public Service, has also launched a utility-owned residential rooftop solar program. The state Renewable Energy Standard requires investor-owned utilities to meet 30 percent of their annual requirement for renewable electricity sales through distributed generation.

A recent utility partnership involves the utility National Grid and the nation’s largest rooftop solar provider, Sunrun. The entities announced a collaborative effort experimenting with different rooftop solar approaches: rooftop sales to residential customers, using rooftop solar to help balance the grid by aggregating distributed generation and customer behavior research. The effort initially targets 100,000 single family homes in New York.

Third Party Ownership

Although not authorized in every state, third party solar developers and companies can help expand customer and utility access to solar energy, meet a Renewable Portfolio Standard or achieve corporate sustainability goals. These entities can either contract with utilities to provide power or certain services, or—as is more common in states where it is allowed—contract directly with retail customers to provide renewable power.

Third party entities can serve different functions, from installing or performing maintenance on solar equipment to owning, financing and building solar energy systems. As mentioned above, utilities can also contract with third parties for installations and maintenance, such as in Arizona and Georgia. These entities can expand or drive markets for solar energy and help meet customer demand for renewable energy. Third party companies may develop specialization in this area, leading to streamlined processes, increased efficiency and reduced costs. As businesses, they can transfer successful practices to new state or regional markets more easily than a utility. Third party solar companies can benefit from federal, state and local tax incentives and may have substantial experience in accessing these benefits. These entities also assume a larger share of risks and remain responsible for the operation and maintenance of systems. Third party financing may be structured so customers either pay no up-front costs or only a partial cost; customers may also be able to purchase the system before the end of a lease term.

However, third party entities are not allowed to sell electricity to end-use customers in a number of states and may not have access to financing rates as low as utilities. Also, consumer protection concerns surrounding third party entities and fair business practices for residential solar have increased in recent years (see more in “Consumer Protection” section).

Under the federal Public Utility Regulatory Policies Act (PURPA) of 1978, third party entities can build, own and maintain “qualifying facilities” of smaller grid-scale or commercial solar energy installations, selling the electricity at a utility’s avoided cost rate to utilities, corporations, individuals or power markets through long-term power purchase agreements or leases.Power purchase agreements (PPAs), or energy service agreements, are contracts between a provider—typically an independent electricity generator or system owner—and a buyer that are used to finance and implement renewable energy installations.^{Ref. 84} PPAs may be attractive because they facilitate the delivery of predictable, lower cost energy, as well as renewable energy certificates and tax credits, without large upfront costs. PPAs also require the owner or developer to assume much of the risk, providing security and assurance to the customer.

Corporations and private-sector entities represent a growing segment for purchasing new PPAs, and accounted for more than 7 GW of domestic renewable energy capacity as of March 2017.^{Ref. 85} Within the first nine months of 2018, corporations had already purchased 7.2 GW of renewable energy globally—more than the previous record of 5.4 GW purchased in the whole of 2017.^{Ref. 86} The United States and Nordic countries made up just under 80 percent of the corporate procurement activity in 2018.^{Ref. 87}

Although a majority of states have statutes mentioning or defining PPAs, at least 15 have enacted substantive legislation to authorize and regulate these agreements.

States with Detailed Power Purchase Agreement (PPA) Legislation

Source: NCSL

PPAs can help meet a state’s Renewable Portfolio Standard or allow third party rooftop solar providers to operate. To promote PPAs, most state legislation gives the public utility commission the power to direct or allow local utility companies to enter PPAs with qualifying independent generators, such as in Connecticut, Hawaii, Oregon and Rhode Island. Michigan and Washington have passed legislation requiring commission approval for utilities entering PPAs longer than a designated length of time. Additionally, state legislation—such as in Iowa—addresses interconnection by directing utilities to facilitate the transmission of electricity from third party generators directly to individual customers. Finally, a third party entity leasing to a tax-exempt entity cannot claim the federal Business Energy Investment Tax Credit unless a PPA is used.^{Ref. 88}

On the residential scale, third parties have developed a significant role offering customers financing through the same two avenues: PPAs and leases. As with commercial PPAs, a third party owns the solar system and acts as an intermediary between a utility and a customer. The third party entity installs a system at a customer’s home, typically at no cost. The third party sells the electricity generated to the customer at a fixed rate—typically lower than the utility rate in some markets—and the electricity reduces the customer’s bill. At the end of a PPA term, the customer can either extend the contract, purchase the system from the third party or have the system removed.^{Ref. 89}

According to the Database of State Incentives for Renewables and Efficiency, at least 26 states, Washington, D.C. and Puerto Rico permit third party solar photovoltaic PPAs, while nine states explicitly disallow solar PV PPAs (their legal status remains unclear in the remaining states).^{Ref. 90} In recent years,South Carolina enacted Senate Bill 1189 in 2014 authorizing solar leasing andGeorgia enacted House Bill 57 in 2015 authorizing third party financing.

Legal Status of Third-party Power Purchase Agreements (PPA)

• Disallowed by state or otherwise restricted by legal barriers
• Authorized by state or otherwise currently in use, at least in certain jurisdictions
• Status unclear or unknow

Source: NCSL and Database of Stae Incentive for Renewables and Efficiency (DSIRE)

Under the lease model, a customer signs a contract with an installer or developer to pay for the solar system over a period of time, rather than for the power produced (although a minimum production guarantee is typically included). In states where solar residential PPAs are less  common or face regulatory challenges, leases may still be permitted.

Although third party entities historically held a significant share of the residential solar market, their portion has recently declined. According to GTM Research, third party ownership peaked in 2016, accounting for 53 percent of residential solar installed.^{Ref. 91} The 2017 year marked the first year since 2011 when more residential solar systems were purchased with cash and loans than with leases or PPAs.^{Ref. 92} The third party ownership is expected to continue to decrease, and GTM Research predicts its market share will drop to 33 percent by 2023.^{Ref. 93}

Third party entities can also be key in shared renewable installations. Washington, D.C. and 16 of the 20 states that authorized shared renewable programs or pilots have stated that third party entities can own and operate installations. Third party entities lead 67 percent of community solar programs, for example, according to the Smart Electric Power Association.^{Ref. 94}

Customer-Owned
Customer-owned distributed solar—made possible through cash and loan purchases—is dramatically on the rise. In 2017, customer-owned solar—purchased with either cash or loans—overtook third party-owned solar as the dominant residential solar model,  accounting for approximately 59 percent of the residential market share.^{Ref. 95} Customer-owned distributed solar is increasingly cost-competitive and the demand for owning one’s own system is increasing. Certain third party entities, such as Tesla, now offer customer-owned options for distributed solar.

The customer-owned model exists on the residential, small commercial and community scales. In this model, a property owner purchases the solar energy system through a cash or loan payment. After a third party entity installs the system, the owner may be responsible for system operations and maintenance (O&M) directly, or signs a O&M contract or warranty. The owner may be eligible to receive tax benefits, however municipal entities and public entities with no taxable income are ineligible for the federal Investment Tax Credit. Entities may address how the tax benefit is allocated in the purchase cost differently. Owners may also be responsible for additional taxes depending on state tax law. Any increases in property tax value following a reassessment, for example, if a system is not tax exempt. While individuals do purchase solar energy equipment in many markets, states without net metering or financing policies tend to have markets of minimal size.^{Ref. 96} Low-income customers however, may have difficulty accessing this method of ownership.

While property owners receive the benefits of solar energy ownership, they also bear the risk and responsibility. For community-sized shared renewable facilities, this can place a significant burden on individual participants that must come together to plan and develop these systems. Consequently, only a handful of states—such as Delaware, Kansas, New Hampshire, Rhode Island, Vermont and Washington—allow individual customers or groups of customers to own shared renewable energy facilities.

Many entities offer direct purchase loan options for distributed solar, including third party companies (that may or may not also offer leasing) and banks. Utilities are increasingly exploring this option as well. For example, the PSE&G Solar Loan Program offers 10-year loans with an 11.18 percent interest rate and a minimum Solar Renewable Energy Credit value guarantee to mitigate volatility.^{Ref. 97} The New Jersey Board of Public Utilities approved a rate of return for PSE&G’s program to prevent cross-subsidization with non-participating customers. Utility offerings can be solar specific or use existing loan programs, including on-bill financing (see “Financing” section).

REC Ownership
An additional consideration regarding ownership models is not the specific solar hardware itself, but who owns the renewable energy certificates (RECs) from the systems. Solar generation results in two products: the underlying generation and a solar REC, which represents the renewable energy attributes of the generation. Only the entity who owns the REC can claim their electricity as renewable. RECs have monetary value (e.g. $200/MWh), with the highest values in markets where utilities have a distributed solar mandate.^{Ref. 98}

All ownership or financing agreements stipulate which entity owns the resulting RECs, and consequently the claim that they have purchased renewable energy. While this is subject to variation, there are several trends in REC ownership. In PPAs between utilities and third parties, third party generators typically own the RECs and sell them to utilities, allowing utilities to meet RPS requirements. State net metering and shared renewable energy legislation typically stipulates the entity that owns RECs. In shared renewable energy programs, RECs are usually conveyed to the utility, though in some cases the subscriber keeps the RECs, most notably in California.^{Ref. 99}

Clearly communicating and stating in writing REC ownership, especially with distributed solar, is a consumer protection consideration. Customers should clearly understand how claims to renewable energy are tied to RECs, who owns RECs, whether they can be sold and the implications of a sale, as well as the risks associated with REC ownership and market value.^{Ref. 100}

Financing

Despite increasingly favorable economics, the cost of distributed solar remains a barrier for many. To increase customer access to solar, many states are exploring how innovative financing mechanisms and improved terms for traditional financing mechanisms can overcome market barriers. Financing can remove or reduce the up-front capital required for investment in solar technology. Certain programs can address the split incentive between renters and owners or incorporate private sector capital and expertise. Coordinated state financing efforts can collect and consolidate data, increase quality assurance, and improve consumer outreach and protection. Several traditional and innovative financing mechanisms are listed below.

Loan Programs

To help customers overcome the barrier of high upfront costs of installing a solar energy system, states have implemented loan programs. While loans do not reduce the system cost, they allow customers to spread the cost of the system over time. More than half of states offer loans that may be applicable to solar projects.

Loan programs may vary in design, implementation and funding source. Programs can be funded by annual appropriations, public benefits funds, RPS or RES alternative compliance payments or other methods. Several programs are designed to be revolving loan programs, meaning that loan repayments replenish the fund so that additional loans can be disbursed each year. Montana’s Alternative Energy Revolving Loan Program is funded by air quality penalties collected by the Department of Environmental Quality.^{Ref. 101} The program provides loans to individuals, small businesses, local government agencies, the university system, and nonprofit organizations to install renewable energy systems. North Carolina enacted House Bill 1389 in 2009 creating a local option revolving loan program that authorizes, but does not require, cities and counties to establish revolving loan programs to finance residential and commercial renewable energy and energy efficiency projects.

Property Assessed Clean Energy

Property Assessed Clean Energy (PACE) enables property owners to implement energy improvements on their property and repay the costs over an assigned term (typically between 15 and 20 years) through an assessment on their property tax bill.^{Ref. 102} For many states, PACE offers an effective and voluntary solution to attract private capital to renewable energy, energy efficiency, water efficiency and resiliency projects, including rooftop and community solar systems. For instance, a 2015 project secured through the Washington D.C. PACE program provided financing for solar and energy efficiency upgrades to renovate a local YWCA, a non-profit property, that had fallen into disrepair. In addition to bringing the building above local code requirements, this project also deployed a 30 kW solar PV array, reduced the building’s operating costs by an estimated $6,000 per year and helped preserve 84 units of affordable housing.^{Ref. 103}

PACE programs are differentiated between the commercial and residential sectors.

With programs active in 19 states and Washington, D.C., and authorizing legislation enacted in at least 34 states and Washington, D.C., the Commercial PACE (C-PACE) market is steadily growing.^{Ref. 104} C-PACE has proven to be a flexible and effective tool for financing upgrades in multiple types of buildings, including office, retail, industrial, multifamily, mixed use and agricultural facilities—accounting for over $588 million in projects to date.^{Ref. 105} For example, in July 2016, a specialty hog processing facility in Missouri became the largest agricultural project in the United States to utilize PACE financing. The $4 million project successfully retrofitted a 75,000 square foot facility to include a solar PV system, HVAC upgrades, and improved water and lighting efficiency.^{Ref. 106} In 2017, C-PACE lenders broke records for the largest project to date: a $40 million seismic retrofit to the Seton Medical Center Campus in California.^{Ref. 107} The upgrades will allow the hospital to meet the state’s mandatory Hospital Facilities Seismic Safety Act. ^{Ref. 108} The project is expected to be completed by the end of 2019. Furthermore, a PACE assessment is an ad-valorem taxation, and therefore can be utilized by property owners that are typically exempt from property taxes, such as non-profit organizations.

The growth and success of C-PACE programs has primarily been led by local governments, with more than 500 municipalities creating C-PACE programs across the country.^{Ref. 109} However, C-PACE market growth has faced challenges in some jurisdictions due to its novelty and complexity, a lack of program standardization across jurisdictions, and the administrative and legal lifts required to move from program initiation to project completion. In 2014, the Connecticut legislature took an innovative step in the state’s approach to clean energy financing by creating the Connecticut Green Bank. This entity replaced the state’s previous PACE program, the Clean Energy Finance and Investment Authority, and was designed to remove barriers and streamline efforts for participation by standardizing program criteria and developing guidelines for municipalities. All municipalities in the state are eligible to join the program and all properties located within the boundaries of a participating municipality are eligible for financing.

Legislatures and state energy officials can play multiple roles in supporting and advancing C-PACE in their states. NASEO’s 2016 report, Accelerating the Commercial PACE Market: Statewide Programs and State Energy Office Participation in PACE Financing, highlights strategies and examples from diverse C-PACE markets, including Texas, Michigan, Connecticut, Colorado and California.^{Ref. 110}

Residential PACE (R-PACE) programs have also helped thousands of homeowners, primarily in the state of California, finance solar improvements. Unlike conventional loans, which are based on the borrower’s credit score, R-PACE financing takes the form of a special assessment and is typically available to any homeowner who is current on property tax and mortgage payments. The R-PACE obligation is attached to the property and can be transferred upon sale to the new homeowner. R-PACE is compatible with many common mortgage products, including those insured or underwritten by the Federal Housing Administration and the Department of Veterans’ Affairs. Additionally, the U.S. Department of Energy released a guidance for residential PACE programs in fall 2016.^{Ref. 111} However, fewer states have R-PACE programs or enabling legislation due to the senior-lien status of R-PACE assessments over mortgage liens. Additionally, the Federal Housing and Finance Authority has encouraged mortgage lenders not to purchase liens with PACE mortgages. Consequently, of the 22 states with R-PACE enabling legislation, only California, Florida and Missouri have operating programs.^{Ref. 112}

In 2010, the Florida legislature passed PACE-enabling legislation, House Bill 7179, which has resulted in five active financing programs in the state, three of which (Florida PACE Funding Agency; Ygrene Energy Fund; and RenewPACE) provide financing for residential renewable energy and energy efficiency projects. Increased interest in residential efficiency and clean energy improvements has led to steady growth in R-PACE markets, as demonstrated by the total financing amount for R-PACE more than tripling between December 2015 and December 2017.^{Ref. 113}

States with Property Assessed Clean Energy (PACE) Programs

Source: NCSL, PACENation

State Energy Loan Funds

State Revolving Loan Funds (RLFs) enable state and territory energy offices and their partners to offer long-term, low-interest financing for a variety of uses, including energy efficiency and renewable energy. RLFs are unique financing instruments in which principal and interest repayments for existing loans are recycled to fund additional projects, essentially creating a sustainable source of capital that can be used to fund projects indefinitely. States have used RLFs to introduce the market to a variety of innovative financing tools, such as energy performance contracts, on-bill financing, PACE and public-private partnerships. ^{Ref. 114}

To meet states’ specific market needs and maximize the impact of the funds, RLFs can and have been designed and implemented in a variety of ways. The Rhode Island Economic Development Cooperation RLF was initially funded by the federal American Reinvestment and Recovery Act of 2009 (ARRA) and offers low interest loans for in-state businesses to make investments in energy savings. Texas offers the LoanSTAR Revolving Loan Program, which makes energy-related financing available for state, public school district, public college, public university and tax-district-supported public hospital facilities. NASEO maintains the State Energy Loan Fund database, which tracks energy loan programs and includes key statistics such as funding source, fund size and program purpose and can provide energy officials with more in-depth knowledge regarding the various types of RLF models in use.^{Ref. 115}

On-Bill Financing

On-bill financing and on-bill repayment programs are two innovative solutions for property owners to pay for clean energy investments through their utility. Utilities can offer this type of financing for residential, commercial or industrial facilities by taking advantage of existing sources of capital, including revolving loan funds, public benefits funds, utility shareholder funds, grants or private investors.^{Ref. 116}

On-bill financing allows the utility to incur the cost of the energy upgrade, which is then repaid by the customer on their utility bill. Similarly, on-bill repayment requires the customer to repay the investment through a charge on their monthly utility bill. The difference is that the upfront capital for the loan is provided by a third party instead of the utility. On-bill financing gives utilities the freedom to manage these programs without the need to negotiate terms or identify third party partners, this method of financing is more commonly used than on-bill repayment.^{Ref. 117} On-bill repayment however, still allows for a streamlined revenue-collection process, as utilities already have a billing relationship with their customers and access to information about their energy usage patterns and payment history.^{Ref. 118}

As customer demand for energy efficiency and clean energy upgrades increase, utilities are looking to on-bill financing as a potential solution to meeting this burgeoning need. To encourage greater residential solar penetration, Pedernales Electric Cooperative in Austin, Texas, created an on-bill financing program for customer-owned solar installations and battery storage. Likewise, the City of Tallahassee, Florida allows customers to borrow up to $20,000 for solar PV systems, following a city energy audit, to be repaid on the customer’s utility bill.

At least 14 states have enacted legislation to authorize public benefit funds for capital, to create pilot programs or to require utilities to offer on-bill financing or on-bill repayment. While a number of states initially authorized on-bill financing for energy efficiency, recently states like Connecticut and Minnesota have begun including renewable technologies as eligible for financing. Additionally, in 2018, Alaska enacted House Bill 374 that authorized on-bill financing for the purchase and installation of renewable energy systems and energy efficiency devices, as well as energy storage systems.^{Ref. 119} Legislation intent on creating on-bill financing programs can explore a variety of topics and consider numerous factors. For example, states may select which technologies and upgrades are available for financing or direct the state’s public utility commission to do so, rather than utilities. If a state implements on-bill repayment, stakeholders must determine whether utilities or third-party financers assume the risk of non-payment. Utilities in an additional 21 states, and Washington, D.C., administer on-bill financing programs, although there has been no enabling legislation enacted to create these programs.^{Ref. 120}

On-Bill Financing and Repayment Legislation

Source: NCSL

State Green Banks

States are exploring “green” energy banks as a way to promote renewable energy, energy efficiency and resiliency. Green banks are public-private partnerships that combine public funding with private capital and expertise to promote renewable and efficient energy technologies and lower the cost of investments.^{Ref. 121}

These banks are public or quasi-public entities that provide an array of financing tools including direct loans, co-investing, PACE financing, on-bill financing or on-bill repayment, credit enhancements and bonds. An energy bank can also utilize innovative or new financing arrangements that may be deemed too risky for the traditional banking industry to assume without public support. State energy banks also serve to consolidate and coordinate existing renewable energy and energy efficiency programs—allowing a state to deploy a cohesive financing strategy. Energy banks require initial public funds, however state energy banks will ideally become financially self-sustaining.^{Ref. 122}

Connecticut established the nation's first green energy bank. In 2000, the legislature created the Renewable Energy Fund (later renamed the Connecticut Clean Energy Fund) to fund more than $150 million in renewable energy projects, education programs and technology investments. In 2011, the state legislature consolidated the Connecticut Clean Energy Fund and other state programs to establish a quasi-public green bank through Senate Bill 1243. Substitute Senate Bill 357 in 2014 renamed the bank to the Connecticut Green Bank. The bank coordinates state energy finance programs and has a mandate to enable efficiency improvements in at least 15 percent of single-family homes by 2020. Additionally, the bank is authorized to enter into contracts to perform loan organization services. The goals of the bank include energy security and reliability, as well as job creation and local economic development.

State green banks can allow for an increased focus on energy security, critical infrastructure and resiliency efforts. Following Superstorm Sandy, New Jersey experienced extensive damage to electrical transmission, distribution infrastructure and critical infrastructure systems. This led to the state forming an Energy Resilience Bank in October 2014.^{Ref. 123}

The New Jersey Economic Development Authority and the New Jersey Board of Public Utilities have joint oversight of the Resilience Bank. The bank was initially funded with $200 million in public capital from the state’s Community Development Block Grant Disaster Recovery allocation. The first series of projects will support the “islanding” of distributed energy resources at critical facilities, with a preliminary focus on water and wastewater treatment plants, including combined heat and power, fuel cells, retrofits, microgrids and off-grid solar inverters with battery storage.

Reducing Soft Costs

While scale and technological innovation have rapidly decreased the costs of solar technology and manufacturing, non-hardware “soft costs” have not declined as quickly. Solar soft costs are the expenses associated with customer acquisition, permitting, inspection, interconnection, installation labor, taxation and system financing. For solar photovoltaic (PV) systems, these expenses represent up to 64 percent of the total cost.^{Ref. 156} Soft costs are paid by customers, so reducing these expenses increases competitiveness.

Although permitting, inspection and interconnection costs comprise a small portion of solar PV system costs, this process is one segment of soft costs that state policies can affect. Deploying solar PV systems typically encompasses two separate, but parallel, approval processes: one for the local jurisdiction, which oversees permitting and inspection and one for the electric utility, which oversees interconnection. The fragmented energy marketplace in the U.S. drives higher soft costs since permitting, inspection and interconnection processes vary significantly across 18,000 local jurisdictions and more than 3,000 utilities.^{Ref. 157}

PV Building Permitting and Utility Interconnection

Source: National Renewable Energy Laboratory (NREL)

Source: U.S. Department of Energy, 2016

For small solar PV systems, the full utility interconnection approval process—including permitting and inspection—took an average of 67 days in 2015.^{Ref. 158} Delays in these processes can result in increased soft costs and higher overall system costs. The Lawrence Berkeley National Laboratory (LBNL) found that variations in local permitting procedures can lead to a difference in average residential PV system prices of approximately $0.18/Watt (W) between the jurisdictions with the most-onerous and most-favorable permitting procedures.^{Ref. 159} This equates to a $900 difference in system costs for a typical 5 kilowatt (kW) residential PV installation between jurisdictions. When considering variations in permitting practices as well as in other local regulatory procedures, the price difference increases to $0.64-0.93/W between the most-onerous and the most-favorable jurisdictions: a price difference of between $3,200 and $4,700 for a typical 5 kW residential PV installation. In addition to increased system costs, delays in the permitting, inspection and interconnection processes may result in foregone energy production and customer dissatisfaction.

One avenue for state policies to assist in reducing soft costs is by streamlining and expediting the permitting, inspection and interconnection processes. Streamlining these processes may also lower other soft costs, such as customer acquisition costs, through reducing the costs incurred by solar installers due to customers abandoning delayed projects.

Several states have taken action to address permitting, inspection and interconnection soft costs. For example, California passed the Solar Permitting Efficiency Act (Assembly Bill 2188) in 2014 that required all city and county governments to adopt an ordinance that creates an expedited, streamlined permitting process for small residential rooftop solar energy systems with a capacity of less than 10 kW. Cities and counties are required to conform their permitting processes to the recommendations in theCalifornia Solar Permitting Guidebook.^{Ref. 160} The bill also requires that cities and counties provide all eligible systems with a simple checklist for the permit process.

Similarly, Rhode Island enacted companion bills in 2017 that required the Rhode Island Office of Energy Resources to create a statewide solar photovoltaic permit application that municipalities must use.^{Ref. 161} The permit encompasses both the building and electrical permit aspects required for a solar PV system.

Legislation enacted in Massachusetts in 2012 required the Department of Public Utilities (DPU) to develop recommendations for improved interconnection policies and processes.^{Ref. 162} In accordance with this legislation, the DPUestablished three basic tracks for interconnection.^{Ref. 163} The Simplified track, for systems with a capacity of 15 kW or less, has a maximum timeline for approval of 15 days. The Expedited track, for systems 15 kW or greater, has a maximum time frame of 40 days. All facilities that are not eligible for the Simplified or Expedited tracks are put on the Standard track, which has a maximum time frame for approval of 125 days.

States can also decrease soft costs through reducing or eliminating the cost of obtaining permits. For example, in 2012 California enacted legislation that placed a statewide cap on permit fees for solar energy systems.^{Ref. 164} For residential, roof-mounted solar PV systems, municipalities cannot charge fees greater than a flat amount of up to $500, plus $15 for every kilowatt over 15 kW. In 2017, California enacted Assembly Bill 1414 that extended this fee cap until 2025. Connecticut passed Senate Bill 1243 in 2011 that established a local option for building permit fee waivers for renewable energy projects. Municipalities are authorized to waive the building permit fee for projects including solar energy systems.

Additionally, states can decrease building or interconnection permitting requirements or eliminate them entirely. For example, in Vermont, solar net-metered systems must receive a “certificate of public good” from the Vermont Public Service Board to interconnect. House Bill 56 enacted in 2011 established that for systems 5 kW or less, applicants are only required to “self-certify” that they comply with the interconnection requirements and certain siting requirements. Utilities, municipalities, and adjacent landowners have a 10-day period to raise any issues and request a hearing. If none are raised during this period, a certificate of public good is issued. In 2014, Vermont passed House Bill 702 increasing the capacity of systems eligible for the 10-day permitting process to 15 kW.

Arizona enacted House Bill 2615 in 2008 establishing standards for how construction permits are awarded for solar PV and water heating installations. Legislation allowed municipalities and counties to remove the requirement of obtaining a professional engineer’s stamp to approve a solar system installation.

Finally, allowing customers to access and submit permit applications online can reduce soft costs through decreasing labor and reducing delays caused by lost or misplaced applications. For example, in a 2015 order that established the state’s interconnection standards, the Mississippi Public Service Commission (PSC) included provisions that required electric utilities to make PSC-approved interconnection application forms available online and to establish processes for accepting applications electronically.^{Ref. 165} An increasing number of states also require utilities to post information about the status of interconnection requests online.

Training and Certification

This segment contains numerous excerpts from the Clean Energy States Alliance (CESA) publication, “Standards and Requirements for Solar Equipment, Installation, and Licensing and Certification.” Visit CESA’s website for the full publication.

State and local jurisdictions typically establish standards for electrical work and the qualifications required of contractors and individuals that perform that work. Most states have adopted the National Electrical Code (discussed in “Building Policies and Codes”), often with state or local modifications, as the standard for electrical installations. Because PV systems contain numerous electrical components and usually connect to the electric grid, many states or localities require qualified electric professionals to perform many aspects of PV installation.^{Ref. 180}

Licensing and certification are the credentialing tools that states and local jurisdictions use to ensure that a solar installer is a “qualified person,” possessing the qualifications, competence, and expertise to provide solar installation services. A license is a grant of legal authority to those individuals who demonstrate the necessary degree of knowledge, experience and skill to safely and competently engage in the profession. Licensing is typically a mandatory requirement administered at the state level, and in some states at the municipal level. Certification is typically a voluntary credential that is administered by third party, non-governmental organizations. There are three variations of licensing and certification regimes employed by states and localities to illustrate different licensing models for rooftop solar installers: general electric licensing, limited electric licensing and third party certification. Most rules governing who is qualified to perform electrical work and the standards for the work are adopted at the state level; however, local jurisdictions in some states establish electrician licensing standards and requirements. As discussed further below, state or local government administered solar programs will often incorporate third party certification requirements into program rules.

Licensing and Certification

• Statewide Solar Contractor Policies
• Local Solar Contractor Policies
• Include Solar PV

Source: NCSL

Several states have taken legislative action relating to solar certification. For example, Rhode Island passed House Bill 8200 in 2014 creating the Renewable Energy Professional Certificate. Certificates are issued by the Department of Labor and Training to registered contractors who have either an associate or higher degree in renewable or solar energy, or who have completed an approved certification course. Certificate holders can perform certain installation work and all ancillary, non-electrical work. While holders can bid for renewable energy jobs that entail electrical work, a licensed electrician must complete all electrical work for the project. Louisiana enacted Senate Bill 447 in 2014 requiring licensed contractors to be in compliance with the State Board of Licensing to install solar panels, through a solar PV installer certification. The bill specified that contractors with Building Construction, Electrical Work or Mechanical Work licenses as of August 1, 2014 will meet requirements for compliance. Contractors without certification from the North American Board of Certified Energy Practitioners must take a written exam. Contractors applying for Solar Energy Equipment classification, must have a Building Construction, Electrical Work, Mechanical Work or Residential Building Contractor certification and must complete a board approved training course in solar energy systems design. Additionally, Utah enacted Senate Bill 208 in 2013 exempting contractors with a specialty license for electrical work for photovoltaic installation, repair or maintenance earned in 2009 through 2011 to be exempt from an electrical license.

A handful of states have enacted or introduced legislation establishing solar training programs. For example, Illinois passed Senate Bill 2814 in 2016 that, among other provisions, created the Illinois Solar for All Program, which will prioritize new solar development in and job training for low-income communities. The bill requires all projects under the Illinois Solar for All Program, when possible, to include job training opportunities and to coordinate with existing job training programs. It also includes provisions to create a utility-funded solar installer training program specifically designed to reach certain individuals, including ex-offenders and former foster children. Pending legislation in New York introduced in 2017 would authorize vocational training for inmates on the installation of solar hot water systems in correctional facilities.^{Ref. 182}

Solar Access and Rights

Although state- and local-level support for solar energy development has grown, solar energy customers may still face challenges such as local ordinances or homeowner association rules that restrict, prohibit or significantly increase the cost of installing solar energy systems. Investments in solar can also be compromised by trees or new construction on adjacent properties that obstruct sunlight.

Solar access laws can be implemented at the state or local levels and protect solar energy customers from private prohibitions of solar energy installations and secure customers’ access to sunlight. There are two types of solar access law: solar easements and solar rights law. Solar easements are the most common type of solar access law at the state level. These policies allow existing solar customers to secure rights to continued access to sunlight and protect against neighboring properties being developed in such a way that the solar customer’s access to sunlight is limited or restricted, either through building construction, growing trees or other foliage.

Solar rights laws address local ordinances’ or homeowner association’s efforts to prohibit, restrict or significantly increase the cost of installing solar energy systems. These laws can define what type of equipment is included in the law, prevent covenant restrictions from prohibiting solar energy installations, define what constitutes an unreasonable restriction, provide exemptions, clarify which structures are included in the law, and award costs and legal fees for civil action expenses arising from disputes.

At least 42 states have authorized some type of solar access laws: at least 16 states have solar easements, at least nine states have solar rights laws and at least 17 states have both solar easements and solar rights laws.^{Ref. 183}

State Solar Access Policies

• States with solar easements
• States with solar rights law
• States with Solar easements and rights law

Source: Database of State Incentive for Renewables and Efficiency (DSIRE)