Module 4: Text Versions

Below are the video text versions for Module 4 of the City and County Solar Photovoltaics Training Program.

Introduction

The policies and incentives that may affect your potential PV project vary by location and can make the difference between your decision to own or finance a system. We'll help you understand the different financing types available to local governments.

Training

Hello, this is Tien Tien from the National Renewable Energy Laboratory. Welcome to Module 4 of the city and county’s solar PV training program, policy and financing. So far, we have covered setting a goal, identifying and screening the sites, steps to a detailed site evaluation and additional webinars on resiliency and the system advisory model. If you want to review these webinars, they are available on Litmus. In this module, we’ll cover some of the important elements that plug into the economic analysis covered in previous sessions, including incentive policies and financing structures. First, we will go over the key incentive policies that influence a potential PV project. First, we will cover a renewable portfolio standard or RPS.

An RPS requires load serving entities to generate or procure a given amount of renewable energy within the state. Low serving entities typically demonstrate RPS compliance through the generation or procurement of renewable energy certificates or RECs. Each REC represents the clean energy or environmental attributes of one megawatt hour of electricity generated from qualifying renewable resources. By generating demand for RECs, RPS creates a market for solar generation as a saleable or tradable asset. The sale and purchase of RECs for RPS compliance is commonly referred to as the compliance market. A separate market exists for voluntary RECs, which are typically priced much lower than compliance RECs. Many states in Washington, DC, provide extra incentives for electricity generated from solar or distributed energy used to meet RPS requirements.

Those can be done through a solar credit multiplier to increase the value of RECs generated from solar. If a state has a multiplier of two for a distributed solar, for example, the PV system is credited two megawatt hours or two RECs for each megawatt hour generated with respect to the RPS compliance. The presence or absence of a compliance market and whether you choose to sell solar energy into compliance markets has significant impact on project economics. REC sales can provide a major revenue stream, particularly in markets with high alternative compliance payments.

However, the decision to sell or retain RECs has implications beyond the financial viability of the project. REC ownership determines who can make legal claim to the clean energy attributes of solar generation. So if you want to sell your RECs, then you lose the right to claim ownership of the clean energy output of the system’s generation.

Here we have a checklist for RPS and RECs. First, an S-REC market may not be available in some states, even if the state has the RPS for solar carve out. States without an RPS may still be able to participate in REC or as REC markets of other states. Participation in S-REC markets may provide strong economic incentives for developers and for customers. However, volatility of the S-REC market is a consideration when calculating project economics.

Second is the decision to sell RECs. The revenue from RECs may be necessary to provide the internal rate of return for solar project. The customer can consider the costs and benefits of retention of his RECs in relation to financial viability of the project. However, they also have to take into consideration the institutional goals. Third is the eligibility of a project for the state’s solar carve out multiplier or factor. Some states may place qualifications such as system size and sector for a project to qualify for the extra RECs. The metering is an unbilled mechanism that allows or requires utilities to compensate solar system owners for next excess generation delivered to the grid. The credit can be applied to offset consumption of electricity within the current billing cycle, and often in future billing cycles.

The PV system owner is then billed for net energy consumption during a billing cycle. Net metering standards vary significantly across states in terms of the rate at which customers are compensated for excess generation, eligible size, user rate, and total program capacity. Even for the few states that do not have a net metering policy, utilities tend to have net metering while other bill credit mechanisms for solar PV. One of these mechanisms is net billing. On their net billing of PV system owners can consume electricity generated by the PV system in real time and export any excess generation of onsite consumption to the utility grid.

But instead of banking kilowatt hours within the billing cycle to offset future consumption, all net energy exports are metered and credited at a predetermined sell rate the moment they are injected into the grid. Net metering standards can significantly improve the internal rate of return of solar investments by adding an additional long-term revenue stream to the project. However, customers should consider these elements. The first one is system size limits. Many states limit the size of the system that qualifies for net metering. A number are limited to residential size systems. You should ensure the size of the system under consideration is eligible for the program.

Next is to ensure rates are favorable to a project economics. The rate at which net metering customers are compensated for excess generation varies by state and by utility. Most states will credit the customer at the retail rate, but an increasing number of states credit the net excess generation at an avoided cost rate, which is much lower than the retail rate. Some utilities have increased or are proposing to increase additional charges and higher user fees than solar customers. User fees refer to any additional electricity cost that a customer accrues as a result of installing a solar system.

They generally take three forms. The first is customer fixed charges. They are flat monthly fees levied on customers regardless of electricity use. Demand charges are fees based on peak customer demand. Utilities typically only place demand charges on non-residential customers. However, some utilities have proposed expanding demand charges to residential solar PV customers. Standby rates are placed on customers with their own generation that require a backup source from the utility. The next point to take note of is the aggregate capacity element.

Most states specify a limit on the total amount of net metering allowed within a state or within a utility. Assessment of availability of net metering in the sector is important to determine when to build a project and how much capacity to build. You can find the latest information from state public utility commissions. Also don’t forget about REC ownership. While RECs provide a revenue stream, ownership of RECs may be important for a municipality’s environmental goals. Lastly, meter aggregation compensates electricity customers for the output of a solar system not cited on their property. It allows customers to invest in off-site solar system and receive financial benefits in proportion to their investment.

This is an important consideration for customers with multiple users and meters such as commercial developments, multi-unit housing, apartments, and municipalities and school districts with multiple buildings. State level interconnection standards influence the upfront transaction cost of solar projects. These additional costs may take the form of legal and procedure cost to secure unit connection agreements, and the relevant permits or direct posts in the form of inter-connection fees. Therefore, understanding accounting for the costs embedded in interconnection policy procedures can be an important component in the financial planning of a project. Directly related to interconnection is the permitting process.

Solar system installations can require a variety of permits depending on the jurisdiction, including electrical permits, interconnection permits, building permits, and zoning permits. We’ve discussed permitting issues in the module on site evaluation, and you can refer back to the module for more information. Almost all states have implemented interconnection standards or guidelines. Most of these procedures differ amongst states in terms of standard form agreements, capacity limits, timelines, insurance requirements, and technical requirements. A number of these states’ interconnection guidelines apply to net meter systems only.

The interconnection process often poses a sizeable cost burden for distributed solar projects due to potential complex impact studies on processing times and lack of certainty regarding approval. Project delays due to interconnection are more common for the midscale projects than for smaller distributed PV projects under 250 kilowatts. Detailed impact studies are commonly required for any projects greater than one megawatt. Here is a checklist for issues related to interconnection standards for municipalities to consider. First is the availability of standardized interconnection for small generators.

You can review state policy for standard interconnection to assess if the sector and type of solar system is eligible for standard interconnection. Keep in mind although the state sets interconnection processes and standards, the local utility implements the final interconnection rules. Second is system size limits. States with standardized interconnection standards may have capacity limits and possibly voltage specifications. Often, states exclude smaller systems from the more rigorous interconnection requirements applicable for larger systems.

And an online application process typically shortens the interconnection process compared to manual application. Next, we’ll talk about some financial incentives. There are several types of financial incentives available for solar projects. The first is rebates and grants. Rebate and grant programs provide a direct upfront payment for solar investors. Rebate and grant programs may be administered at both the state and utility level. In a typical policy structure, a state develops a broad rebate grant policy and delegates authority to the utilities for administration.

Performance based incentives operate similarly to rebates and grants, except that the payment amount depends on the output of the solar program. Loan programs facilitate the financing of solar projects without making a direct payment. They may be administered at both the state and utility level.

Property assessed clean energy, or PACE financing is a special form of loan program that allows local governments to provide upfront funds for energy improvements on residential and commercial properties, including solar projects. Project owners pay PACE financed investments through property assessments over 10 to 20 years. The last one is tax incentives. The major tax incentive is the investment tax credit. It’s an important federal financial incentive supporting solar PV. The ITC allows 30 percent of the development cost of a solar project to be deducted from the federal income tax for utility skill, commercial, and third party owned and residential solar properties. For both commercial and residential solar, the 30 percent deduction is effective until the end of 2019, after which the credit level is scheduled to decrease.

The modified accelerated cost recovery system, or MACRS, is another federal tax benefit for commercial projects. MACRS qualifying solar equipment is eligible for a cost recovery period of five years. The commercial sector ITC is scheduled to decrease to 26 percent by the end of 2020, 22 percent by the end of 2021, and ten percent by the end of 2022. In addition to the federal incentives, many states exempt solar project investments from property sales and income taxes.

Some states also provide tax credits for solar project investments. Financial incentives can determine the most lucrative capital structure for finance and project ownership. Here are some considerations when looking at financial incentives. First is system eligibility. State financial incentives are often specific to a particular segment of the market with different amounts of incentives, different system size caps, and different total funds or aggregate capacity. The customer can identify if solar PV system fits within these parameters, or if any of these parameters can influence the design of the solar project.

You can determine which taxes will apply and cost allocation. For net income tax, revenue generated by a project will be subject to state and federal income taxes. Some states offer income tax credits in addition to the federal ITC. Other financial incentives such as rebates and grants can reduce the taxpayer’s basis for calculating with ITC unless the incentives are considered taxable income to the taxpayer. For sales and use tax, most states’ sales taxes apply to solar equipment rather than the sale and use of electricity.

Some states offer sales tax exemptions for solar facilities. You may check to see if participants can benefit from the tax exemptions on their community or shared solar program. Many states offer property tax reductions or exemptions for solar facilities. Note that the assessment values for property tax come from either a local assessor or a state authority. Participation in certain state incentive programs will transfer the ownership of RECs from one customer to another entity, so before participating in these incentives, be sure to consider how able to affect your REC ownership and environmental goals if that’s important to you.

Shared or community solar models allocate the electricity of a jointly owned or lease system to offset individual entities’ electricity bills, allowing multiple energy consumers to share the benefits of a single solar array. Community solar expands access to solar energy for residential and non-residential customers who rent, have unsuitable roofs or cannot meet financial or other requirements for individual systems.

There are several models of community or shared solar, each with different options to allocate the benefits of the solar system. These benefits include electricity generation, net excess generation, RECs, tax benefits, and state incentives. There are three common models. First is the utility sponsored model. Utilities own and operate a project and offer multiple retail customers the option to purchase solar electricity from a shared facility.

For an unbilled crediting special purpose entity model, commercial and residential entities jointly invest in a portion of a shared solar array through a special purpose entity and receive a credit on their electricity bill proportional to their contribution based on how much electricity is generated by the facility. In a nonprofit model, donors contribute to a shared solar installation owned by a nonprofit organization. They do not directly share the benefits of the solar installation, but support the nonprofit in lowering electricity bills and creating environmental benefits.

The nonprofit can partner with a for profit entity to capture the tax benefits. A number of state level community solar programs and policies have emerged in recent years to encourage adoption of solar. The enabling policies for community solar include aggregate net metering, virtual net metering, special community solar tariffs, and guidelines for community solar development. Community solar projects can often make good use of marginal lands where unused rooftops don’t offer the benefits of solar to community members who would otherwise miss out.

Municipalities that host solar – shared solar systems on its bill, buildings and lands can provide electricity and other benefits to the community. Here are some things to keep in mind for community solar projects. First is the availability of billing credit mechanisms. Billing credit mechanisms, such as accurate metering and virtual net metering are not available in every jurisdiction. In this case, a special purpose entity model might not be feasible. States may have limits on the PV systems’ capacity for the solar system, number of customers that can participate, and types of customers for community projects.

Individual projects or utilities may also have additional requirements for their community projects. You should also ensure that the renewable shares are transferrable to another party in case of planned or unplanned change in participation. There are many options for allocating the benefits of participation in a community’s solar program. You should consider the following elements’ impact on cash flow and economic feasibility when determining suitability of a particular model or structuring for the project.

These include electricity protection from the solar system, ownership of RECs, federal tax credit and deductions, accelerated depreciation, and state and local utility rebates and incentives. In the past decade, the most common alternative business model for solar PV procurement has been third party ownership. In this model, a solar customer pays for the power output of a system owned and operated by the third party system owner.

Many state policies characterize and regulate third party owners as utilities. When third party owned systems are subject to utility level regulations, the model does not provide the same level of efficiencies to drive deployment. Some states have recharacterized third party ownership agreements to protect third party owned systems owners from utility regulation. Where third party ownership is explicitly or implicitly prohibited, some states have developed alternative direct access and green tariff policies. Green tariffs allow customers to purchase the power output of a renewable energy project from the utility as a vehicle for the purchase.

Now at least 26 states and Washington, DC, and Puerto Rico authorize or allow third party power purchase agreements for solar PV. Third party PPAs can help entities unable to monetize federal tax credits such as nonprofits, municipalities, and schools. Third party financing options help avoid upfront capital, which can discourage larger solar projects due to the relatively larger capital investment. But customer, which usually does not have experience in solar energy, will not need to operate and maintain the system under a PPA, and they will not bear the risk of a solar system performance.

PPAs are considered off balance sheet financing, which does not list the projects’ assets and liabilities on the host’s balance sheet, but are deducted as an operating expense. Before determining the structure of your solar project, you should consider the following. First, existing policy on third party ownership. Availability of enabling policies that allow PPA contracts to be signed between a developer and facility host differs from state-to-state. In certain cases, the law is not clear. Customers may pursue a lease model with a third party financier or developer to avoid upfront costs. PPA models compatibility with state incentives. Third party owned systems may be ineligible or incompatible with certain state incentives, such as net metering, production based incentives, and rebates. In some cases, this is not explicitly stated in state policy and would need verification from state and local authorities and third party developers.

And lastly is the ownership of RECs. The ownership of RECs is subject to negotiation under a third party ownership model. You should evaluate your desire to keep the environmental attributes as well as the outlook of the REC market in the contract process. Now let’s take a closer look at some financing structures available for public entities. Historically, state and local government agencies have employed one of two models that deploy solar photovoltaic projects.

One is the Solve ownership model, which is financed through a variety of means, and the second one is a third party ownership through a power purchase agreement. If a state allows third party ownership, you can consider the PPA model. It requires a separate taxable entity to procure, install, and operate the solar PV system on a consumer’s premises. The Gerima Agency enters into a long-term contract which is typically referred to as the PPA to purchase 100 percent of the electricity generated by the system from the system owner. The system owner here is often a third party investor or tax investor who provides investment capital to the project in return for tax benefits. The tax investor is usually a limited liable – a liability corporation backed by one or more financial institutions. In addition to receiving revenue from electricity sales, they can also benefit from federal tax incentives. These tax incentives can account for approximately 50 percent of the project’s financial return.

Without the PPA structure, the government agency could not benefit from these federal incentives due to its tax exempt status. If PPAs are not allowed or are limited, there are other options that can be considered. First is the solar lease. Under a solar lease, the customer does not purchase power from a third party, but simply leases the equipment and receives the power generated to buy that equipment. Although it avoids the retail sale of electricity, the solar lease model creates challenges for the use of federal tax credit and accelerate depreciation.

A utility may also act as a contractual intermediary. Under this arrangement, the third party owner sells power from the solar PV system to the utility, which in turn sells power back to the site host or the end user. Also, standardized third party PPA contract language can in some cases be put in to protect customers and reduce the likelihood that the Public Utilities Commission will disallow the third party PPA model or require future regulation.

Another option is the utility ownership model. Utilities that own solar PV systems cited on customers’ properties could take the federal investment tax credit to reduce the capital cost of owning solar PV. Taxpaying utilities may choose to build and own large scale solar plans. They can also finance customer cited distributed generation and sell the power back to the host customers. In this instance, the utility effectively takes the place of the third party in the third party ownership model.

If the model is properly structured, the customer can enjoy the same benefits of fixed price power at or below utility retail rates, and the utility can take advantage of the tax credits. For states and municipalities that want to install solar PV on government property, clean renewable energy bonds or CREBs previously offered an alternative financing mechanism to the third party ownership model. However, this was eliminated under the tax cuts and jobs act in December of 2017. The bond PPA hybrid is a financing option by which a public entity issues a government bond at a low interest rate and transfers that low cost capital to a developer in exchange for a lower PPA price. This model can be used to finance solar PV projects on schools, colleges, county administrative buildings and other public buildings.

Under this model, a public entity issues a request for proposal seeking a solar developer to build, operate, and own a solar project or portfolio project on public buildings. The administrator then sells the bonds to finance the development cost of the PV installation. The public entity that enters into both a lease purchase agreement with the winning bidder and a PPA on behalf of the local hosts to buy the electricity from the PV program. So which one of these financing models is right for you? It would depend on many factors and your circumstances. For the third party PPA model, you don’t have to put up any upfront capital.

It allows you or your project to take advantage of the federal tax incentives and other tax exemptions. It gives you a predetermined electricity price from 10 to 25 years. It also doesn’t require any operating and maintenance responsibilities, and you can eventually own the system after the tax benefits run out. For the self ownership model, you can use this to gain full control over a project, including the design, operations, and take the risk on. It’ll give you the ability to choose what to do with the renewable energy attributes, the RECs generated by the project, and it’ll allow you to use cheaper financing options, such as public debt and other financing strategies available to public entities.

On the other hand, under a third party ownership, the process of negotiating a PPA can be very lengthy and costly. The public entity also has limited control over the project design and operations, and you may hit a sub-optimal PPA pricing and allow the third party to take advantage of most of the financial benefits. And for self ownership, this does not allow the public entity to monetize the value provided by the ITC. And you need to be an expert on dealing with maintenance and operations of the project.

You may also run into debt issues and limitations as well as project management issues. Now that we’ve covered incentive policies and some financing mechanisms, we hope you have more tools to help you build the economic analysis and design of solar projects for your jurisdiction. We have some more resources available in the additional references section of this module including resources for finding incentives and policies for each state and general guides for policies, community solar, and financing.