Power Purchase Agreements and Renewable Energy Certificates: Distributed Generation Projects

I. Introduction. The term “distributed generation” is applied to a wide range of facilities using different technologies and varying in size. Due to the sheer variety of solar energy facilities, it can sometimes be difficult to define what is “distributed” and what is not. Perhaps the most common element of distributed generation projects is that they are located on-site. They will typically connect “behind the meter” to the site owner’s building systems, aka the “site host.” Connection to the grid “at the meter” is still important for the site host, though, because of the need to access electricity supply when the distributed generation facility is not generating or is not capable of meeting the full needs of the site host. Complicating the issue further is the recent expansion of virtual net metering and community solar programs, both of which share some features with on-site projects and utility-scale projects. For our purposes here, we will focus principally on on-site facilities.

For distributed generation solar photovoltaic (“PV”) installations, the on-site nature of the project is typically a far larger complicating factor than the intermittent nature of its output. Unlike larger utility-scale projects, distributed generation solar PV may be located in either urban or rural areas, on rooftops or on the ground, on larger structures or on smaller structures, with clear solar access or in congested areas. In addition, the site host may or may not be the power purchaser. Consequently, there is a significant potential for strongly conflicting interests between the passive host with a limited interest in the project and the power purchaser that wants the project output, in regard to what each is willing to accept as reasonable risk allocations with the project developer.

Every distributed generation solar project requires at least two fundamental commitments from the site host and/or the offtaker. Every project needs site rights sufficient to allow the developer to build, operate, and maintain the solar installation on the site and an agreement for the purchase and sale of the power generated from the solar installation. If the power purchaser and the site host are the same, it makes little difference whether the relevant provisions are put in the site lease or the power purchase agreement (“PPA”). However, the site host can lease or sell the premises, thereby changing the identity of the host and party to the site rights agreement. Accordingly, there is no single solution for all situations. In addition, there may be situations where a license, or right to use the project site, may be preferable to an actual lease of the site. The potential for this issue is particularly present when the site host is a municipality or other type of governmental entity.

To distinguish the particular nature of distributed generation facilities and from larger utility-scale projects, we have split our discussion of PPAs into two parts. The first part discusses distributed generation solar PV PPAs and is presented in this chapter. The second part discusses solar PPAs in the context of larger utility-scale projects.

A. The Parties.

1. The Project Owner/Seller. The ownership of a distributed generation solar PV installation is a tax-advantaged investment. As a result, protecting and enhancing the available tax benefits is as important as maximizing revenues. Both are essential to a successful project, and equal consideration should be given to tax benefits and revenue protection. This may change in the future if or when federal investment tax credit for solar phases out. But for now the solar PV market largely relies on the federal investment tax credit, and our discussion below is therefore premised on the application of federal investment tax credit provisions.

   To facilitate the pass-through of tax benefits and available subsidies, the project owner/seller in a distributed generation solar PV project will almost always be a limited liability company. The entity will expect to be able to pass through to its members the tax benefits, revenues from power sales, and revenues from the sale of Renewable Energy Credits (“RECs”) that represent the environmental benefits and attributes of the non-carbon-based electricity generation. Depending on the particular forms of subsidy (such as state tax credits, state cash subsidy payments, or solar carve-outs in state renewable portfolio standards designating the amount of generation local utilities must derive from renewable sources by certain benchmarks), the project owner may have more or less interest in actually owning the facility after the tax credit recapture and direct subsidy period has ended (though there are other tax considerations relating to the “profit motive” test that may require the project owner/seller to maintain longer term ownership of the installation). In other words, the project owner/seller typically has little interest in actually operating or structuring itself as a utility. Solar PV lends itself well to this lack of interest in being a “real” power generator since solar PV is generally considered to have an extremely low level of required maintenance and an extremely high level of reliability. Consequently, the project owner/seller wants to minimize risks to its expected stream of tax benefits, power sales revenues, and REC sales, particularly those that the project owner/seller considers to be within the control of the site host or power purchaser to prevent or avoid.

   The project owner/seller’s ability to pass through the tax benefits to third parties is fundamental to a tax equity investor being willing to provide financing to a transaction. The tax equity investor typically has an even larger desire to exit the transaction after the tax and subsidy benefits have been exhausted than a developer/owner. For this reason, many distributed generation solar PV transactions have been structured using a “flip structure” where the tax equity investor starts with typically 99 percent of the ownership interests in the pass-through project-owning entity, which “flips” to a 5 percent interest after the tax equity investor has received the return on investment that has been negotiated between the parties.

   Additionally, and regardless of the specific structure utilized, the party that expects to receive the federal investment tax credit must be the “owner” of the installation on the date the installation is “placed in service” for federal income tax purposes. Consequently, all structures for distributed generation solar PV projects are premised upon the need to have the tax equity investor in ownership prior to the placed in service date. Many potential investors want to avoid any construction period risk by delaying their contributions until after the installation is completed and has proven to be functioning in accordance with its intended design specifications. Project developers should be aware of the problems that can arise if the investors are not willing to put any funds at risk prior to completion of the project.

2. The Buyer. The power purchaser typically is interested in reducing its energy costs at a specific location. This can be a single manufacturing facility, an office building, an automobile dealership, a warehouse, a school, a hospital, or a public facilities maintenance building. As the market has realized, there is an enormous opportunity to place safe and passive solar PV installations in a wide range of locations. The main physical constraining factor is available useful space. In addition, various state regulatory hurdles often make it difficult to install the full capacity a site host could physically accommodate. See Chapter 5, Regulatory and Transmission-Related Issues. For these and other reasons, the power purchaser from a distributed generation solar PV facility will usually be a party with a long-term commitment for a large facility, who is looking for a long-term plan to fix and reduce energy costs. In essence, this power purchaser just wants to receive the power with the minimum amount of additional risk and financial obligation. In previous years, solar PV buyers were principally motivated by a desire to “go green,” but with the sharply reduced cost of solar energy, today the motivation is usually financial.
3. The Site Host. If the site host and the power purchaser are not the same (or closely affiliated), the site host may become a silent partner (or at least an ever-present consideration) in the negotiation of the PPA. Although not as true for a ground-mount installation, a rooftop installation is generally in place for a long time on a structure that was probably not specifically designed to accommodate a solar PV installation. This can raise a number of issues regarding (1) the timing and need for routine rooftop repair, maintenance, and replacement (including both the costs of having to move the installation to allow repair or replacement and the lost revenues from power sales while the repair or replacement is going on); (2) the possible need for structural improvements to support the solar PV array; (3) the susceptibility of the solar PV array to high wind conditions and other climate factors where it is located; and (4) the problems of changing ownership or occupancy of the structure during the term of the PPA. The project owner must recognize that these situations pose objective risks that may disrupt the production of electricity from the installation temporarily or permanently.

These risks need to be allocated among the parties in the best position to protect against their occurrence, but always in a fashion that provides sufficient protection for the project to remain financeable. This can be particularly challenging when the site host is not also the power purchaser. Such a site host will tend to not want to bear any of these costs that may be outside its normal costs and risks of doing business, such as providing for roof repair, maintenance, and replacement. At the same time, a power purchaser that does not own the building or structure it is occupying is likely to view these as risks that it is not normally asked to assume as a “mere tenant.” The fact remains that the project owner is making a significant financial investment that will depend on all of the various economic returns from the project, tax benefits, power sales revenues, and REC sales or other subsidies to make a reasonable return on its investment. No solar PV project is so economically “rich” that allocating these risks can be overlooked. To make sense of how the power sales aspect of a PPA interacts with these “other” concerns, it is first necessary to discuss how a typical PPA deals with the actual sale of output from the solar PV installation.

B. The Power Sales Aspect of the PPA.

1. Standard Terms. Most current distributed generation solar PV PPAs simply provide that the buyer will buy all of the electricity generated by the installation at the price specified in the PPA and the electricity will be delivered at the point of interconnection with the buyer’s (or site host’s) electric system (“behind the meter” delivery). In other words, the obligation to pay is based on the actual receipt of output at the specified point of delivery, and payment is determined by reference to the amount of output delivered. By contrast, a “take or pay” contract specifies a certain amount of money the purchaser is obligated to pay each year (expressed as a minimum volume of energy at an agreed unit price) regardless of whether the installation actually produces output. Given the host/offtakers’ expectations of substituting solar energy for utility-provided energy, and the developers’ interest in guaranteeing system performance, “take or pay” contracts have not found a place in the distributed generation marketplace.
2. Pricing the PPA. The electricity to be delivered under a solar PV PPA is typically priced at a set cents-per-kWh, usually with an annual escalator. The initial price is sometimes calculated so as to provide a specified discount to the current utility retail rate, but there is now significant downward pressure on PPA prices for distributed projects as module prices have dropped. Competition among providers is now the principal driver for PPA pricing. Occasionally a PPA is priced on a variable basis as a discount from utility retail rates during the PPA term. These utility-discount variable-rate PPAs are generally disfavored by financing providers, and are much less common than in previous years.

   It is unlikely these considerations will change significantly going forward. Even if regulatory actions, such as passage of a cap and trade bill by Congress, cause changes in the market rate of electricity, electricity from distributed generation solar PV installations will probably continue to be priced in reference to utility retail rates.

3. Performance Guarantees. Performance guarantees are fairly unusual for distributed generation projects, but they do occur from time to time. In the case of an output guarantee there will typically be a provision stating that power output will decrease annually by a fixed percentage, usually about 0.5% per year. Regardless of calculation methodology, the project owner/developer should attempt to make certain that the threshold is set low enough that it is never triggered.
4. Net Metering Expectations. Many power purchasers enter into solar PV PPAs with the expectation that any unused output can be sold to the local utility. Net metering is one way in which the power purchaser expects that it can gain a financial benefit from any excess electricity delivered by the solar PV installation in excess of the power purchaser’s immediate need. Another is the potential to sell power to the local utility. In the limited circumstances the latter option is available, the price is typically at or below wholesale levels.

The PPA itself will usually not have any provisions dealing with these situations because the typical solar PV installation is delivering behind the meter for the immediate use of the power purchaser without the requirement of any use of the local utility’s grid for transmission. The project owner/developer should consider including language in the PPA specifically disclaiming any responsibility for the ability of the power purchaser to net meter or sell excess energy.

Net metering and the limited circumstances in which a power purchaser may be able to sell its excess output to the serving utility are discussed further in Chapter 5, Regulatory and Transmission-Related Issues.

II. Standard Provisions of a PPA.

A. Term of the PPA. The current standard appears to be that the PPA will have a length (“term”) of 20 years, though 15 years is also common. To some extent, the term is dictated by the project owner’s desire to receive, or need to receive, a certain rate of return from its investment. It is increasingly common to see PPAs with terms significantly shorter than 15 or 20 years, although shorter PPAs can be more difficult to finance. It is standard in solar PV PPAs that the project owner is responsible for paying the costs of removing the installation from the site upon the natural termination of the PPA. However, if termination occurs early due to an event of default caused by the power purchaser or a termination declared by the site host, this cost typically shifts to the purchaser.

B. Installation, Testing, and Start-Up. Most PPAs contain an obligation on the part of the project owner to cause the project to be installed, set out the conditions relating to pre-operation testing, and define when the project will be considered “placed in service” (important for tax considerations and not requiring full actual operation) or in “commercial operation” (which relates to commencement of project eligibility for power sales and usually requires that the project produce and deliver electricity at the standards set forth in the PPA). The project owner will usually satisfy its obligation to construct and install the project by entering into an installation agreement with an experienced solar installer. The installer will then undertake the obligations of testing the project, obtaining certification that the project has reached commercial operation, and completing the final punch-list items necessary to perform the installation contract. Pre-operation testing for a solar PV installation is usually quite simple: hook the system up for a set period of time (usually four hours for small projects, and longer for larger projects) and meter the output to see if it is producing within design parameters. If it does, it has passed its required pre-commercial operation testing and will be considered placed in service. For more on installation agreements, see Chapter 4, Solar Energy System Design, Engineering, Construction, and Installation Agreements.

C. Project Operation and Maintenance (“O&M”). The solar PV PPA typically will provide that it is the project owner’s responsibility to maintain the installation. Several standards are usually specified, such as conformance to prudent utility practice, prudent solar industry practice, or best practices, but they all mean essentially the same thing: the installation must be maintained so that it does not pose a danger to individuals, to the structure on which it is located, or to the grid, and so that it will produce electricity in accordance with contractual expectations. The project owner will often fulfill this obligation via a third-party O&M contract. Many installation contractors also desire to handle O&M, and may extend the term of their equipment and installation warranty (two or three years, increasing to five or 10 years) if they are awarded the O&M contract.

D. Project Purchase Options. An option for the power purchaser or site host to purchase the solar PV installation at some defined point during the term of the PPA is a common feature of solar PV PPAs. As with the pricing structure, the times at which this purchase option may be exercised vary widely.

1. Purchase Option Points During the PPA Term. It is common to have a purchase option exercisable after some or all of the sixth, tenth, or fifteenth year, or on the natural expiration of the PPA. Occasionally the purchase option is exercisable at any time after the sixth year, or any time at all. Granting a continuous purchase option presents significant issues for the project owner/seller including potential recapture issues.
2. Pricing the Purchase Option. A project owner considering granting a purchase option is faced with a combination of tax considerations and economic business considerations. The principal consideration is the requirement that the purchase price be no less than fair market value. If the purchase price is below fair market value, there is a risk that the IRS will reallocate the investment tax credit to the power purchaser instead of the project owner. There are two common methods of setting the purchase price. The most common method is to have an appraisal at the time of the option exercise, and the purchase price is set as the fair market value as determined by the appraiser. Recently, it has become increasingly common to agree to a set price in advance. This set price is determined using appraisal and accounting tools to be at least fair market value at the time of the option exercise. An additional limitation is the five-year recapture period for the federal investment tax credit, during which any exercise of a purchase option will trigger recapture of a percentage of the federal investment tax credit received by the project owner. An exercise of a purchase option during this period is therefore typically not allowed. If a purchase option is allowed during this time, the purchase price will be increased to compensate for lost or recaptured tax benefits.

E. Off-Ramps Before Construction, Events of Default, and Other Common Provisions. See Chapter 3, Power Purchase Agreements: Utility-Scale Projects for a discussion of standard event of default provisions that are generally applicable to both distributed generation solar PV PPAs and utility-scale PPAs, other than those dealing with the creditworthiness of offtakers, guaranties, and other financial accommodations, which typically are not found in distributed generation solar PV project documentation.

III. On-Site Issues in a Distributed Generation Solar PV PPA. Several issues arise from the on-site location of distributed generation installations that are relatively unique to these types of electric generation projects. They will be encountered in any distributed generation facility regardless of technology, but the large increase in the installation of distributed generation solar PV facilities makes them an excellent template for discussing these issues.

A. Structural Integrity. Installing a solar PV system on the rooftop of an existing structure will put a significant weight load onto a structure that may not be rated for that weight. Placing a solar PV installation on a structure that cannot easily bear the weight is a clear danger to health and safety, and poses a potential threat of damage to the structure itself. A careful survey of the weight-bearing load capacity of any building on which a solar PV installation will be placed should be done before going very far into the negotiation process. Structural reinforcement may be required, and the costs of those improvements may prevent the installation from being economically viable. The only option other than making structural improvements may be downsizing the proposed installation to reduce weight. The site host, power purchaser, and project owner each have a direct and clear interest in being certain the structure on which the installation will be placed can bear the load for at least the full term of the PPA. Nonetheless, the responsibility (and risk) of structural integrity must be allocated to a party, and this can be a hotly negotiated topic.

B. Repairs and Replacement. Many roofs will require maintenance and repairs at some point or points during the term of the PPA. In addition, most roof coatings are designed with a known useful life. Exceeding the useful life of the existing roof may require the solar installation to be moved or removed from the rooftop to allow repair or replacement of the existing roof. There is a direct economic cost from both disconnecting the installation and moving it out of the way on the rooftop and disconnecting it and moving it off the rooftop while repair or replacement is conducted. That cost is the loss of power sales during the period the installation is out of service, as well as the loss of any REC sales or other subsidies that depend on the installation being in production. Project owners will often grant the power purchaser or site host some agreed period of time in which there will be no penalties incurred to accommodate ordinary repairs and maintenance. If the installation downtime will exceed this agreed-on period, many PPAs will require that the power purchaser start reimbursing the project owner for lost power sales, lost REC sales, and other lost economic benefits. If the power purchaser is not the site host, this presents a clear need to coordinate the PPA and the site lease, license, or easement to handle this risk.

C. Sale of the Structure or a Change of Tenant. Distributed generation installations also present the unique problem that ownership of the structure on which the installation is located may change during the term of the PPA, or the tenant that was previously the power purchaser may move out and a new tenant that is not interested in assuming the PPA may move in. There is no single, clear, simple solution to this problem. The site lease, license, or easement will usually require that any purchaser of the structure assume the site lease, license, or easement (i.e., it is an encumbrance that “runs with the land”). The site host may want to require a new tenant to assume the PPA as well, but if the new tenant is unwilling and has sufficient leverage with the site host that may not happen. Consequently, even if the project owner believes it is adequately protected from these situations under the project documents, the project owner is faced with a difficult decision. There is a substantial cost attached to the project owner’s enforcing its legal rights, as well as immediate lost revenues of various types if the new owner or tenant simply will not accept the delivery of electricity from the solar PV installation. This is a central issue to project success, and should be addressed carefully in the agreements.

D. Ground-Mount On-Site Issues. A ground-mount installation presents a different range of issues than a rooftop installation. Gone are the concerns about structural integrity, roof leakage, tenants, and multi-use properties. Instead, ground-mounted systems face a greater range of environmental compliance risk and regulation. These risks and obligations should be carefully allocated between the site host and the project owner. Typically, the site host will be responsible for all nonproject hazardous substances and other environmental risks, while the project owner is responsible for project-related environmental matters.

IV. Distributed Utility PPAs. Certain utilities, including the Southern California Edison Company (“SCE”), Pacific Gas and Electric Company, and San Diego Gas & Electric Company in California, have received authority to enter into PPAs with distributed generation solar installations owned by independent power producers. For example, the standard form of PPA used for the SCE program combines provisions typical to distributed general solar PPAs with some provisions typically used only in utility-scale solar PPAs, although in a more limited form than usual for a utility-scale PPA. For example, a security deposit calculated at a fixed dollar amount per kilowatt that will be held by the utility is required. If the developer fails to install any of the equipment or devices required to provide output at the designated gross power rating for the installation under the PPA by the defined starting date for power sales, the entire deposit is forfeited to the utility. If only a portion of the designated gross power rating of electricity is delivered by the defined starting date for power sales, a portion of the security deposit is forfeited. This type of security deposit is common in utility-scale PPAs but is relatively uncommon in distributed generation PPAs. Due to the character of the power purchaser as a regulated public utility, regulatory approval of the PPA is required, and the power seller is required to operate the installation in compliance with certain regulatory tariffs. Such provisions are common to utility-scale PPAs but uncommon for typical distributed generation PPAs. In addition, these hybrid PPAs are silent on the issues that typically must be dealt with between the developer/project owner and the site host discussed above. The developer/project owner must solve these on its own, and the purchaser utility has no role or interest in those issues.

V. PV System Leases. It can be seen that in the distributed generation context, a PPA is more a financing device than a commercial agreement for the sale of electricity. It allows the host/offtaker to gain the benefits of PV generated power with little or no upfront capital expense. The PPA does this by moving ownership to a third party that has the available capital for investment and is able to take advantage of the tax benefits of PV system ownership. The host/offtaker essentially pays for the system over time. Under the PPA, the payments are based on units of electricity. In an ordinary loan, the payments of principal and interest would offer similar benefit to the host/offtaker and similar payment structure. A third financing device, offering benefits to the parties similar to those afforded by a PPA, is the system lease. As in an automobile lease, the lessee/host/offtaker contributes a relatively small upfront payment, then leases the equipment and pays the system owner rent for an agreed term. As in PPAs, there are typically early termination charges and options to purchase. IRS regulations require there to be at least 20 percent residual market value in the equipment at the conclusion of the lease term. For this reason, lease terms tend to be shorter than PPA terms.

VI. Renewable Energy Certificates. Renewable energy generation creates at least two distinct commodities that may be sold together or separately. These two commodities are electricity and environmental attributes. The environmental attributes include the emissions benefits associated with the use of renewable energy (e.g., avoidance of greenhouse gas or other emissions) and the source of renewable energy (e.g., solar or wind resources). Because there are two commodities, it is possible to sell the electricity with the environmental attributes or to sell the two commodities separately from each other. A renewable energy certificate or “REC” is a marketable unit representing the rights to the environmental attributes of renewable power generation. A REC typically represents the environmental attributes from 1 megawatt hour (“MWh”) of electricity from a renewable energy source (and includes the reporting rights to the greenness of that MWh of electricity. In the case of electricity from solar generation, the corresponding certificate may be referred to as a solar renewable energy certificate or “SREC.”

A. Types of Markets for RECs. REC prices are largely determined by market forces. In general, there are two markets for RECs: compliance markets and voluntary markets.

1. Compliance (or Mandatory) Markets. During the first decade of the 21st century, a majority of states passed laws requiring certain utilities to include a minimum amount of renewable energy in the portfolio of generating resources serving the utility’s load. These laws are generally referred to as renewable portfolio standards (“RPS”) or renewable energy standards. They require utilities to add renewable generation to their system incrementally until reaching a standard of anywhere from 10 to 100 percent of retail sales from renewable energy. Many of these initial benchmarks have been reached and will likely continue to be satisfied for the foreseeable future by utilities retiring RECs from existing renewable generation. In response, many states have recently moved to significantly raise their state standard, which has the effect of expanding the compliance market for RECs.

   In compliance markets, buyers tend to care only about whether the source of renewable generation meets the state RPS requirements. As such, it is critical to understand how these policies work to either limit or add value to your particular RECs or SRECs. In addition, utilities making long-term purchases of RECs may impose credit requirements on sellers in the form of a letter of credit, a corporate guaranty, or other arrangement, as utilities tend to buy RECs only from sources that will satisfy their RPS needs for the long term.

   a. REC Eligibility. Each state RPS program determines whether RECs are tradable and defines what constitutes a REC that will satisfy its own particular standards. Some states specify that the generation source must be located within the state or a particular region or that the electricity generated be delivered to the state or a nearby region to meet the state standard. Some states require their utilities to purchase the electricity and REC together, or limit the amount of the RPS that can be met by purchasing RECs alone (e.g., California). States often also designate an allowable life span or shelf life for RECs to meet state standards. These often range from three to five years (but can be longer) and at the end of the designated period expire for the purposes of meeting the state RPS. Additionally, solar facilities may be required under state law to be certified in order to sell qualifying solar RECs and such certification may include meeting additional requirements for solar like a capacity cap. Markets for RECs are changing all the time, and while tracking your RECs through a regional tracking system should gather and verify the data necessary to demonstrate compliance for various state policies, the risk of noncompliance is ultimately in the hands of the REC holder (the tracking systems do not verify eligibility). Thus it is critical to track the current RPS policies and eligibility of resources in various states where the parties intend the RECs to be used for compliance.

   b. Solar Carve-Outs or Set-Asides. In an attempt to pull more solar energy into their markets than would otherwise happen under a traditional RPS where lower cost renewable energy (e.g., wind energy) will likely be utilized first to meet the requirements, many states have legislated unique standards, carve-outs, or additional incentives for solar energy. A solar carve-out or set-aside is a requirement that a certain percentage of the electricity acquired by utilities subject to a state RPS be generated by a solar energy resource. Sometimes this is laid out in a graduated class or tier system whereby utilities are required to get a certain percentage of their electricity from each class or tier over time and where solar may occupy one class by itself or be classified with other similarly situated technologies. In other cases, there is simply a stated percentage of electricity (most common) or percentage of the total RPS that is required from eligible solar technologies, and the percentage too may increase over time. In certain cases the state legislature may have added a separate solar standard years later on top of the traditional RPS. Other states have chosen to set a capacity (MW) or production (MWh) target for solar energy that may or may not be directly carved out of the state RPS.

   c. Multipliers or Factors. Many states also allow solar energy RECs or generation to be multiplied by some factor (e.g., two or three) such that a utility could use less solar energy to comply with the state RPS. These measures, if put to use, effectively lower the total state renewable energy requirement and may also include a cap or sunset date to curb this effect. Multipliers may be used in lieu of or in addition to a carve-out.

   Other states create priorities within solar generation by assigning different solar REC factors for different types of installations (e.g., 1 for community shared solar projects vs. 0.8 for generation on brownfields). And the multipliers or factors themselves may be for any number of things potentially affecting a solar energy facility and may be mutually exclusive or additive. For example, states may include a multiplier for the type of technology (e.g., solar), scale of technology (e.g., under x number of MW or distributed generation), type of system (e.g., ground or building mounted), time of generation (e.g., peak hours), location (e.g., in state or in-service territory), type of entity (e.g., community based), or development characteristics (e.g., use of in-state manufactured content or labor).

   d. Regulating Value. States have employed a variety of legislative and regulatory efforts to stabilize the long-term market prices for solar RECs. Please refer to Chapter 12 for more detail on securities regulation in general. Some states, for example, set solar alternative compliance payments (“ACPs”) that aim to create a ceiling on solar REC prices on the theory that a utility would simply opt for the lower priced ACP in order to meet its requirements if solar REC prices became too high. Thus when there is a shortage of solar REC supply, the ACP could virtually set the market price for the solar RECs. In the case of New Jersey, the legislature set forth a 15-year schedule of ACPs to encourage more certainty in the market.

   Efforts to stabilize solar REC prices under the opposite conditions—where there is an oversupply—include various methods of encouraging long-term contracts and establishing an effective price floor. Massachusetts, for example, addresses oversupply through its Massachusetts Solar Credit Clearinghouse Auction program, which aims to auction off any available solar RECs that are not being sold on the open market through a series of fixed-price auctions. If the available credits are not cleared by the bids at the fixed price during the first auction, another auction is held at the same fixed price but where the shelf life of the REC is extended, thereby adding value to the REC. If the shelf-life extension remains insufficient to clear the volume, the state increases the utilities’ obligations for the next year in proportion to the volume of available SRECs. These actions all aim to create a market floor price and create a more stable financeable product.

   The factors mentioned above also work to control the effective value of the environmental attributes associated with solar generation. In Massachusetts, for example, once a 1,600 MW program cap has been reached, the solar REC factor values will switch from a range of 0.7-1 to 0.5-0.7, resulting in the need to generate more MWh to achieve the same revenue from REC sales.

2. Voluntary Markets. Although the compliance market is a critical driver of REC sales today, the concept of RECs or green tags was originally developed for voluntary actions where individuals or companies aspired to meet certain renewable or sustainability goals. Voluntary buyers may be motivated by a desire to “do the right thing,” or to enhance or affirm their corporate identity, corporate climate or sustainability goals, or general environmental awareness. Buyers include marketers, brokers, businesses, nonprofit organizations, and individuals. The following sections provide an overview of the different ways electricity customers participate in the voluntary markets for “green” electricity.

   a. Green Pricing. Early examples of voluntary REC markets include utility “green pricing programs,” which started with a small number of utility programs in the early 1990s and now number in the several hundred. In these cases utility customers generally sign up to pay a premium on their utility bill for renewable energy and the utility then procures and retires RECs in proportion to the amount of green power purchased by the customers involved in the program. Some of the top programs (e.g., Portland General Electric) have well over 100,000 participants in their green pricing programs and the top 10 sell well over 5 million MWh of green electricity each year. While these programs have historically purchased primarily wind energy generation, solar procurement under the programs is on the rise and some utilities are offering the customers an option to procure from solar specifically. The RECs associated with these programs may be sold bundled with the electricity or separately as unbundled RECs.

   b. Green Tariffs. In recent years, to accommodate the increasing desire for green power, the need for competitive and stable electricity prices, and customer goals to procure the associated RECs, utilities in some states have launched “green tariff” programs. Specifically, a “green tariff” is a price structure or rate offered by the utility and approved by the state’s public utility commission that may provide for up to 100 percent of eligible customer electricity needs to be sourced from renewable resources. These green tariff programs vary widely depending on level of customer participation or price structure. Some are aimed at smaller customers and are known as “subscriber” utility programs. In such instances, the utility maintains full control over the procurement and pricing terms of a renewable energy project and the customer “subscribes” to the utility program for a portion of the project. Other “green tariff” programs primarily involving larger customers give the customer direct control in the negotiation of the renewable PPA. In such instances, the customer, utility, and solar developer enter into a “sleeved” agreement. The associated green tariff then replaces the customer’s standard electricity rate with the cost of the renewable energy under the PPA and a rider added to the standard electricity rates (accounting for the total of the cost of renewable energy plus credit for the avoided cost (i.e., fossil-fuel power replaced through the renewable energy project)). Lastly, in a market-based green tariff, the customer signs a PPA for the energy and RECs from a dedicated renewable energy facility and the utility sells the resulting output into its wholesale market (e.g., Southwest Power Pool or Midcontinent Independent System Operator) and credits the wholesale market price to the customer. In all of the above green tariff variations, the utility and customer have unbundled the cost of service rate and substituted for the cost of service for the renewable resource. The various iterations of green tariffs are still relatively new and the ability of such arrangements to facilitate renewable transactions, at least in part, depends on the value proposition to the customer and whether it will yield savings.

   c. Corporate Purchases. Alternatively, certain corporate purchasers enter into “synthetic” or virtual PPA transactions, which provide the ability to contract directly with the renewable energy generator for the sale of electricity and/or RECs without the actual delivery of the physical power. These arrangements are often used by customers with intensive energy use, who are interested in a long-term hedge given the volatility of the energy market or who are subject to corporate sustainability goals. Essentially, in these transactions, the buyer and the seller engage in a hedge or a swap, whereby the parties sell into the wholesale marketplace but agree on a “strike” price at a known hub or trading point. The buyer will pay the seller if the market price is below the strike price, and the seller will pay the buyer if the market price is above the strike price. The RECs may be built into the deal or treated separately. Synthetic PPAs can provide the buyer with long-term price security for both power and RECs, and if the strike price is financially attractive for the seller, it allows the seller to finance the project for the term of the agreement with the certainty that it will be paid no less than the strike price for the power produced. Determining whether and how to best structure such a deal is highly dependent on the particulars of a state’s energy regulatory system.

   d. Community Choice Aggregation. Some states allow communities to aggregate their loads and procure green power in larger quantities through an alternative electricity supplier. For example, in California, community choice aggregation (“CCA”) programs have been established by individual jurisdictions (such as a city) or by two or more jurisdictions pursuant to a joint powers authority agreement. CCAs typically provide different product offerings that allow customers to choose how much of their energy will be derived from renewable energy resources. To serve these customers, CCAs enter PPAs with energy suppliers. Most commonly, these agreements call for the delivery of both the electricity and RECs generated by the applicable project. However, during the first few years of a CCA, the program may purchase unbundled RECs to meet its renewable energy supply requirements until contracted renewable energy projects come online. While CCAs provide for procurement of electricity and RECs, the existing utility will typically continue to provide energy delivery over its distribution system, as well as performing other services (e.g., monthly billing).

   e. Community or Shared Solar. Increasingly, electricity customers also have the option to subscribe to a shared solar project, which is currently a small but growing market. Please refer to Chapter 9 for more detail on community solar in general. For the purposes of this chapter, we note that the treatment of the environmental attributes associated with shared solar programs can vary widely and can have dramatic effects on the project’s financing. Minnesota, for example, uses a value of solar rate structure that, by definition, does not separately account for the environmental attributes but instead folds them into the value of solar calculation and assumes the RECs transfer to the utility alongside the electricity.

B. Tracking RECs. Many states that have RPS legislation allowing RECs to count toward the requirements also require the RECs to be retired through a specific tracking system, such as M-RETS, Western Renewable Energy Generation Information System, New England Power Pool Generation Information System, or PJM Interconnection’s Generation Attribute Tracking System. There are at least 10 regional REC tracking systems in the United States and many more now around the world. These electronic systems track each REC from “birth” to retirement. Each unit of generation is assigned a unique ID that includes its attributes, such as the date the energy was generated, the facility location, the date the facility went online, the type of renewable facility, the emissions profile, and all transactions associated with that unique ID. Operating procedures for these tracking systems generally require that the RECs remain whole and that all generation from a particular unit be reported in one tracking system to avoid double counting. A utility, or other entity, can then elect to retire that unique certificate to show compliance with a state requirement.

Trading in or out of certain systems comes down to compliance with particular state policies. Some states are relatively open with respect to where the RECs can be sourced and others limit the RECs that can be retired for compliance purposes to a single state, neighboring states, or a regional tracking system. The geographic limitations imposed in state policy have deterred market liquidity for RECs and have also been subject to various legal challenges asserting that favoring in-state products above out-of-state products runs counter to constitutional provisions aimed at limiting state protectionism. Some states have changed their policies in favor of a more open approach, but legislators also like to make sure the benefits of legislation accrue locally. Thus, it is important for a developer to carefully track the eligibility of its RECs to be sold into prospective compliance markets.

VII. Conclusion. The project owner must carefully consider how to integrate the on-site issues presented by a distributed generation solar PV system with the basic purpose of the PPA, which is to cover the project owner’s agreements with the power purchaser regarding the installation, start-up, maintenance, and sale of output from the system. Any situation in which the PPA will be with a party other than the site host will raise the question of whether these on-site-specific provisions should be in the site lease, the PPA, or a combination of the two, depending on what the project owner is able to negotiate with the site host and the power purchaser.

RECs, and solar RECs in particular, can be a valuable revenue stream for a solar developer. Selling an intangible attribute into a growing and evolving market for cash is a great way to enhance the viability of a project. A project’s success can be highly dependent on a detailed understanding of the ability of a solar generation resource to meet certain state standard requirements or corporate sustainability goals, the value eligibility brings to the project, the mechanics of tracking and trading the RECs, and the appropriate contract terms to facilitate the transfer of rights to the attributes in exchange for an important project revenue stream over time.

Simply ignoring these issues is an option for the project owner, but one that needs to be taken knowingly. While a developer/owner may elect to take these risks, most tax investors and banks will not. Failing to adequately address these issues will make third-party financing very difficult.

As to the basic core terms of the PPA, the discussion above indicates that there are many different approaches to each provision being used in the market. At this point, there is no single set of deal points that is generally accepted as the industry standard, although most experienced investors and attorneys will recognize a “bankable” PPA when they see one.