What every real property owner should know.
Nicholas A Giannasca is a partner with the law firm of Blank Rome LLP and a co-chair of the firm’s energy and natural resources industry group. He acknowledges the assistance of Carlos E. Gutierrez and Elizabeth A. Stern, both associates at the firm.
For reasons ranging from good corporate citizenship to the desire to enhance the market value of their properties, owners of real property, particularly commercial property, are exploring ways to reduce energy costs and become more efficient consumers of energy. Among the options available to achieve these goals are building retrofits, the installation of energy efficiency measures, and in certain cases, the installation of onsite power, also known as distributed generation (DG) facilities,1 such as photovoltaic (PV) and combined heat and power (CHP) units.
One key impediment to the installation of DG often has been the lack of viable financing alternatives for property owners who have determined that an outright purchase (i.e., self-financing) of the facility, and the associated operation and maintenance, isn’t an attractive business investment. While many owners might be interested in DG, they might not have the budget flexibility for a significant capital outlay or the expertise to operate sophisticated generation facilities. Additionally, many owners might not be aware of—or aren’t well positioned to benefit directly from—the myriad federal, state, and local incentives (e.g., investment tax credits and accelerated depreciation) available to developers and owners of distributed generation.
The solar industry responded to the market signals for a non-ownership financing alternative with the proliferation of zero capital-outlay products featuring a power purchase agreement (PPA).2 Under this structure, a developer of the generation facility assumes all financing, construction, ownership, operation, and maintenance risk, and enters into a PPA with the host property owner for the sale of electricity over a sufficiently long duration to accommodate financing, and to permit a return on the investment. Without expending any capital funds, the property owner or host benefits from lower-cost electricity—often discounted from the otherwise applicable utility rate—while shifting to the developer much of the ownership and operational risk related to the DG facility.3 The resulting expansion of distributed solar generation, particularly in the residential arena, is largely attributable to the PPA model, and the CHP industry has taken note. Market participants increasingly are developing PPA-based products for the installation of CHP facilities.4
Whether an owner considers solar or CHP distributed generation under a PPA model, there are certain legal risks and issues that need to be considered. While this analysis focuses on the risks and issues of importance to the host (i.e., the buyer under the PPA), it also addresses issues and considerations pertinent to the viewpoint of the developer where appropriate. In some cases, negotiated compromises will facilitate the execution of the PPA.
DG Design and Contracting
The host should have a significant role in the siting and design of the facility, including the right to review and approve designs, and the right to inspect the facility during construction. Since the facility will be located on the host’s roof, or within the host’s premises in the case of a CHP facility, the host will have an important and legitimate desire to ensure that the premises will be able to accommodate the location and operation of the facility safely and reliably. The host should ensure, often with the assistance of an engineer consultant, that the facility is sited and designed not only to operate reliably but also to operate in a manner that minimizes any effect on the remainder of the host’s premises. As important, the host will need to draft contractual language in the PPA excusing the host from any liability associated with its review of the design and specifications of the facility.
The host will need to provide appropriate property access rights to the roof or to other designed areas of the host’s premises where the DG facility is to be located. The PPA will typically provide for the developer to have such access during construction and during the operation of the facility throughout the term of the PPA, including—if applicable—the period during which the facility will be removed from the host’s premises. The manner of conveying such rights to the developer is through access language in the PPA or through the execution of a separate site lease. In either case, PPAs typically don’t provide for the host to receive, or for the seller to pay, compensation for such access.
The primary obligation of the host under a PPA structure is the requirement to purchase electricity—and thermal energy under a CHP PPA. The host should insist on drafting clear terms regarding its purchase obligation, including the amount of electricity and thermal energy to be purchased. Will the developer require the host to purchase all of the production of the facility, or just the amount that the host needs at the time of production and delivery? If the former, then the host must be concerned with the economic consequences of purchasing more than its full requirements. For example, if the host is eligible for a utility net metering program (which permits the host to inject the excess electricity into the utility grid and receive a billing credit from the utility) then the economic consequences of buying more than the host requires can be mitigated.5
The pricing methodology of many PPAs is based on a fixed, volumetric rate (e.g., $/MWh) applied to the amount of electricity delivered at a designed point of delivery (e.g., a newly installed meter located at or near the facility). In order to provide economic benefits to the host, the rate is often set at a current-discount from the otherwise applicable utility rate, and is often subject to a fixed price escalator. Typical annual escalation rates in today’s market are between 2 percent and 4 percent. The risk associated with this common structure for the host is that the overall cost of power under the PPA can be higher than the host’s costs would have been if it had purchased its power from the utility. Over the course of a typical PPA term of 15 to 20 years, there’s a possibility that the fixed rate can exceed the utility rate. One method for addressing this risk is to subject the fixed rate to periodic adjustment to reflect a discount from the then-current utility alternative rates, while always being subject to the minimum payment obligation.6
In order to finance the construction of the facility, the developer will need to show that the PPA is bankable, which means that the PPA will support the financeability of the project. One key component in rendering a PPA bankable is the presence of a minimum payment obligation on the part of the host that isn’t dependent on how much the host actually consumes. The minimum payment obligation is set at a level to ensure that the developer can at least cover its financing costs (loan principal and interest, insurance, etc.) over the term of its loan plus additional fees. The host that opposes such a provision could risk jeopardizing the project, but there are ways to protect the host and to facilitate financing under these circumstances. For example, the difference between any fixed minimum and the amount actually owed by the host can be tracked in a notional account and can be returned after the financing period—which typically is shorter than the PPA term—expires through an additional discount to the purchase rate.
Terms and Guarantees
The developer typically will require a duration of between 10 and 20 years, subject to certain tax considerations, for the PPA. The term is often crafted to commence on the commercial operation date (COD) of the facility, which is specifically defined in the PPA. Typically, the COD is deemed to have occurred when the facility construction is complete, the facility is properly connected to the utility grid and tested, and the facility is operated for a minimum period of time to demonstrate that it can operate within specified technical parameters, the confirmation of which can be reflected in a report by an independent engineer. This engineer likely will provide a report to the project lender confirming the COD and the satisfaction of required technical criteria. The commercial operation of the facility must be coordinated among a number of parties, including the host, the developer and the utility to whose distribution system the facility will be interconnected.
In order to motivate the developer to keep the development of the facility on track, the PPA will often contains milestone dates by which certain key project developments need to be accomplished, such as closing financing, ordering equipment, and directing the commencement of construction under a major construction agreement with a contractor. A host would do well to require such milestone performances but also to couple each such provision with a liquidated damages clause to compensate the host for the economic harm that it might suffer as a result of the delay in meeting the milestone. If the electricity—and thermal energy—is being purchased at a discount from the otherwise applicable utility tariff, for example, then any milestone delay simply defers the commencement of dollar savings to the host’s detriment.
PPAs typically contain output guarantees, or what are sometimes referred to as “minimum performance guarantees.” These provisions assure the host that the DG will actually perform (i.e., will generate a specified minimum amount of electric and thermal energy, or both) as promised. The host owner should bargain aggressively for such a guarantee, even if the host, the buyer under the PPA, is only obligated to purchase its energy requirements. The installation of a distributed generator on the host property entails risk for the host (e.g., misoperation affecting the remainder of the host premises). To induce the host to accept this risk, the developer must provide assurances that the distributed generator will perform consistent with its promised capability. Both the developer and the host have a common and legitimate interest in maximizing the performance—and the persistence of that performance—of the distributed generator over the course of the PPA.
A provision often confused with a performance guarantee is an availability guarantee. The key difference between the two is that a performance guarantee will provide assurance of how much output (electrical and thermal) the facility will produce assuming that it’s operating within certain parameters. An availability guarantee provides assurance as to how often (i.e., what percentage of all available hours of operation) the facility will operate. Another way to consider these two different guarantees is through a consideration of risk. If a host owner receives a performance guarantee with no availability guarantee, then the host assumes the risk that the facility doesn’t operate.
From a practical perspective, if the generation facility performs at lower availability levels, the host will suffer a loss of economic benefits. To protect against that loss, the host should negotiate for both a performance guarantee and an availability guarantee with an express obligation by the developer to make a designated payment to the host if either or both aren’t met. Such a payment would be sufficient to place the host in the same position economically as if the facility had produced the higher, expected level of output. For example, an amount payable to the host equal to the product of: i) the amount of energy not produced and delivered; and ii) the difference between the PPA rate and the presumably higher alternative utility rate should be economically protective of the host.
Performance and Default
There are myriad obligations of a seller under a long-term PPA and, consequently, ample opportunity for a seller default to be triggered. Some potential seller defaults include: a failure to commence commercial operation by the requested milestone date; a failure to deliver the agreed upon output of the facility; the facility’s failure to attain a certain availability factor; and the seller’s failure to properly maintain the facility.
Given the numerous possibilities for a seller default under a PPA, and the long duration of such contacts, it’s critical that the host have clearly designed remedies that can be exercised in the event of a default, including the host’s right to terminate the PPA. In addition to the right to terminate, the host should have the right to demand that the seller or developer pay damages as compensation. Typically, the measure of damages is based on the amount of money that, if paid, would place the host in the position it would have been in had the contract been performed by the seller. This measure of compensatory, direct damages would either be specified in the PPA for each year of the term (i.e., liquidated damages) or it would be calculated as the product of the amount of energy (electrical and thermal) not delivered by the seller and the positive differential between the market cost to replace that energy and the cost that the host would have paid under the contract had the promised energy been delivered (i.e., cover damages).
If the contract is terminated due to the seller’s default, then the host must have the right to require the seller to remove the generation facility from the premises and restore the premises to the same condition, except for reasonable wear and tear, that it was in on the effective date of the PPA.
In addition to being mindful of seller’s non-performance, and available remedies, the host must be careful in structuring remedies available to the developer if the host breaches the PPA. In addition to the right to terminate the PPA, the developer will often negotiate for a formula or scheduled form of liquidated damages that seek to place the seller in the same economic position it would have been in had the PPA been fully performed. The host should ensure that the formula or schedule bears a reasonable relationship to the seller’s losses (i.e., it isn’t punitive). As well, the host should require the seller to transfer title to the facility to the host once the damages are paid by the host.
If the host ceases to do business at the location specified in the PPA, there are several options for the host: a) the host can pay to move the facility and continue to buy electricity at the new location; b) the host can attempt to negotiate an assumption of the PPA (perhaps with a release of the host from further liability) with the new occupant of the premises; or c) the host can pay a liquidated termination fee, either based on a formula or schedule, and be released from the contract—with a transfer to the buyer of title to the facility.
Given the diverse monetary obligations present in a typical PPA, it’s often the case that a party might require the other party to post assurance or security that it can perform. For example, a seller could require a buyer who isn’t deemed sufficiently creditworthy to post security (e.g., letter of credit or parent guarantee) to support the buyer’s obligation to pay for energy. Likewise, a buyer might require a seller—who is often a special purpose entity (SPE)—to post security to supplement the SPE’s primary asset, namely, the DG facility.
In addition to assurances or security that might be required to be in place at the inception of the PPA term, it’s customary for a PPA to contain a reciprocal demand-for-assurances provision that permits a party with a reasonable basis for being insecure about the party’s ability to perform to demand assurances (e.g., the posting of collateral). If the assurance demanded isn’t posted, or isn’t posted in a timely way, the demanding party typically can declare a breach of contract.
Parties to a PPA, particularly buyers—who are more often than not the party required to post security—should be careful to draft assurance and security provisions that can be easily implemented with precise triggering events, that reflect express criteria for the amount and type of security to be posted, and that provide ample opportunity to post, or to cure an inadvertent failure to post, a demanded assurance.
Many PPAs provide an election for the host to purchase the facility at the expiration of the PPA term. Some PPAs also provide for the host to purchase the facility at specified points during the PPA. Hosts and developers or sellers should be aware of the tax and financing considerations related to these purchase options.
With respect to purchase options at the end of the PPA term, the parties need to craft the option to ensure that a) the duration of the PPA term—including the initial term and extensions and renewals—is no greater than 80 percent of the useful life of the DG facility (e.g., a distributed generator with a useful life of 25 years could be the basis of a PPA with a term, including extensions and renewals, not exceeding 20 years), and b) the purchase option, if exercised, will be at the facility’s fair market value, determined at the time the option is exercised. A PPA structure that doesn’t satisfy these criteria might be considered to have conferred tax ownership of the facility on the host, thereby conferring the tax benefits of ownership on the host instead of the developer or seller. Such a result could be very problematic from a financing and tax perspective for both the seller and the host.
Purchase options that can be triggered by the host before the expiration of the PPA are subject to other considerations. One of the most compelling considerations for the developer is avoiding recapture of investment credits and depreciation deductions, which are vital to the initial financing of the project. The investment credit for solar equipment is 30 percent of the cost of the equipment (and 10 percent for CHP), and represents an important component in the developer’s ability to finance construction and attract investors. The taxpayer who claims the credit, however, might be required to repay some or all of the credit (i.e., the incentive can be clawed back) if the property is sold or transferred during the first five years after it achieves commercial operation. Accordingly, most PPAs won’t contain a purchase option excusable during the first five years following commercial operation. The host and the developer or seller are well-advised to consult with counsel regarding the tax and commercial implications of purchase options they might be contemplating in a PPA.
There are a number of regulatory considerations for the host to consider, including certain considerations directly affecting the developer or seller. It’s extremely important for both the host and the developer or seller, for example, to consult the applicable regulations of the local utility serving the host premises. In the case of a solar installation, these regulations might be limited to the local electric utility. For a CHP facility, however, the applicable regulations can include those of the utility supplying the premises with electricity, gas and steam. These utility regulations can affect the timing of the installation, the cost—which will largely be borne by the seller or developer in a PPA structure—and the economic effect of the arrangement from both the developer and seller and the host’s perspective.
Utility regulations might address the technical requirements for interconnecting the distributed generator, whether those regulations address electric interconnection requirements or natural gas piping infrastructure. These technical requirements might affect the cost to construct the distributed generator and, hence, the price the seller or developer might offer. Additionally, the complexity of the regulations and the duration of the process undertaken pursuant to the utility’s procedures can have a profound effect on the timing for constructing the facility and placing it into commercial operation. For example, the number and scope of interconnection studies that the electric utility needs to conduct to determine the effect of the distribution generator on the safety and reliability of the utility’s distribution system could extend the commercial operation date.
An important consideration for the developer or seller involves the level of regulation that might be imposed on the developer or seller by federal and state authorities if the seller engages in both retail and wholesale sales of excess energy.7 The host needs to be concerned about this level of regulation because the easier it is for the developer or seller to engage in these sales of excess energy, the greater the likelihood that the seller will realize additional revenue. That additional revenue not only bolsters the seller or developer’s financial wherewithal to perform under the PPA (e.g., undertake operations and maintenance tasks), but also provides a potential source of additional revenue for the host. It’s often the case that a seller or developer might offer, or a host might negotiate for, a percentage of the revenue from such excess sales.8
There are two key regulatory considerations for the host. First, the host must consider whether it’s eligible for net metering. Under net metering programs, energy from the project will offset the host’s retail purchase from its local utility, and when the project is producing more power than the host needs, the utility meter runs backwards, reducing the net amount of the host’s electric purchases. Most states require that utilities implement some form of a net metering program. There are often size, technology, and other restrictions, however, that limit eligibility for the program,9 so as with retail sales in general, the host should become informed of the local rules prior to negotiation of a PPA.
Second, the host should consider the economic effect of the local utility—whether it’s the electric, gas, or steam utility—placing the host on a different tariff for those purchases to be made by the host for supplemental energy (i.e., energy not supplied by the on-site or distributed generation facility). Very often utilities will place a customer with on-site generation on what is referred to as a “standby service” tariff. Such tariffs commonly have a rate structure consisting of a fixed monthly contract demand charge and a volumetric charge that is applied to the amount of energy consumed. Because the contract demand charge can be established on the assumption that the utility needs to be compensated for standing ready to serve the entire host load (i.e., it assumes that the DG facility isn’t operating), this charge could be onerous. Therefore, a host should factor potentially higher standby service charges into the calculation of net economic benefits associated with the installation of a DG facility.
Depending on the state in which the DG facility is located, and the technology adopted to produce electricity, the generation of electricity from that unit can also create a separate commodity referred to as a renewable energy certificate (REC), or environmental attribute.10 In certain states, this separate REC commodity can have value for the title holder because the REC might be marketable (i.e., it can be sold in a liquid market to realize revenue). Often, utilities might be willing buyers because they’re required under a related law (i.e., a renewable portfolio standard (RPS)) to procure a certain percentage of the power they purchase from renewable resources. Often such a legal requirement permits the utility or other entity obligated to meet the RPS requirement the option to buy renewable power or RECs.
Because RECs might have economic value separate from the energy produced by the generation facility, the developer or seller will negotiate for a provision in the PPA that allocates all right and title to those RECs to the developer or seller. While a host might attempt to negotiate for a revenue-sharing provision, the host should be prepared for a resistant developer or seller, who will argue that the main economic benefit for the host is the discount from utility rates and not additional revenue. As well, the developer or seller will assert that it’s assuming the financing construction and operation risk related to the facility and, hence, it’s fair to capture such incremental economic value for its account.
A provision that engenders much negotiation in a PPA is the change in law and regulatory-out clause (the “reg-out clause”). As typically structured, a reg-out clause will permit the seller, but usually not the buyer, to either modify the sales price or terminate the agreement if a change in law or regulation imposes a requirement on seller that materially affects the seller’s ability to perform. An example could be a new regulation that imposes an incremental cost on the seller (e.g., an RTO or ISO imposes a new fee on energy scheduled by the seller into the market administered by the RTO or ISO). The seller will want to flow the increases cost through to the host and the host, not surprisingly, will resist the increase in cost.
The parties often can strike a compromise based on one of several alternatives. A common resolution permits the seller to allocate incremental costs to the buyer associated with a change in law or regulation, if the increase in cost is within a negotiated percentage cap. If the proposed increase exceeds the percentage cap, then the seller and buyer are required to negotiate for modification to the PPA to restore the economic balance of the agreement. If the parties fail to arrive at an amendment to the PPA to restore such economic benefit, then the buyer can be given the right to terminate and the parties will negotiate whether the right to terminate entails an obligation to pay the seller some form of termination payment. Another alternative involves a narrowly tailored reg-out clause that specifically identifies the anticipated event or development that will trigger a rate modification. Combining such a limited clause with the negotiated cap format gives the host a level of protection against rate adjustments that could be materially detrimental.
For a host considering the installation of a DG facility, several ancillary arrangements need to be examined to ensure that the installation and PPA don’t detrimentally impact the host.
For example, if the host owns premises that are subject to a mortgage or security interest, then the host should consider whether the installation of the DG facility and its operation will trigger any defaults under the documentation creating the mortgage or security interest. A related issue for the host is its ability to obtain, if requested by the developer or seller, a waiver from the holder of the mortgage on the host’s premises. Often developers or sellers will want such a waiver (as will the lenders of the developer or seller) to protect the generation facility (which will be deemed personal property and not a fixture) from foreclosure by the mortgage holder. The process for obtaining such a waiver might be protracted and needs to be carefully managed by the host since it could affect the timing for financing, and hence constructing, the generation facility.
A host’s insurance requirements also need to be examined if distributed generation is being seriously contemplated. The presence of the facility likely will change the risk profile of the host, which could increase the cost of existing coverage or require that the host procure new coverage. The additional cost of insurance coverage typically won’t be absorbed by the developer or seller and, hence, it will have a direct effect on the anticipated economics of the transaction for the host.
The PPA structure for financing the installation of distributed generation has stimulated a significant amount of solar PV construction and development, and can successfully provide the impetus for the growth of CHP installations. But, the PPA structure isn’t without risks and exposure for both the developer and the host. In exchange for allocating the risk of construction operation and maintenance to the developer, the host under a PPA remains subject to liability (e.g., damages for failing to accept power) that, while potentially detrimental, can be well managed with properly drawn PPAs. A well-drafted PPA can adequately protect the legitimate interests of both parties while achieving the level of bankability that is crucial for financing.
1. In this analysis, the typical distributed generation facility has a name-plate installed capacity of 2 MW or less. While many of the contractual and regulatory considerations examined are equally applicable to units sized above 2 MW, other unique contractual and regulatory considerations (e.g., more complex interconnection procedures) could be triggered in connection with larger facilities.
2. At times, these zero capital-outlay packages are structured as leases under which the host makes a series of lease payments to the owner of the distributed generation facility in return for acquiring title to the electricity produced by the facility. Issues involving power purchase agreements are, for the most part, equally relevant to such a lease structure.
3. The PPA structure will typically permit the sale of energy products to be treated as a service and, hence, an off-balance sheet transaction. The factors that could affect the characterization of a PPA as a service contract for tax purposes are beyond the scope of this analysis. Please refer to the section titled “Purchase Options” for an examination of how purchase options can impact the tax characterization of a PPA.
4. Indeed, new financing products and arrangements are being considered by legislators and investors, including securitization, real estate investment trusts (REIT), master limited partnerships, and crowd funding, that have the potential to stimulate renewable energy development and the use of more standardized PPAs.
5. As discussed in the section titled “Regulatory Considerations,” the host’s eligibility to engage in net metering is an important consideration for both the host, and the developer or seller. If the host can’t engage in net metering (e.g., because the distributed generation facility is too large), then the host won’t want to assume a purchase obligation that extends beyond its consumption needs at the time the electricity and thermal energy is delivered. Likewise, the developer or seller will need to consider options for disposing of excess electricity if net metering is unavailable to the host (e.g., wholesale sales of electricity into available energy markets), several of which will trigger regulatory compliance issues, such as the need for Federal Energy Regulatory Commission approval to engage in wholesale sales of electricity. The disposal of excess thermal energy, while not as complex as the disposal of excess electricity, might also entail regulatory compliance issues.
6. A PPA pricing model that has been used in some cases is the fixed-discount structure, in which the PPA price is always set at a fixed discount (e.g., 10 percent) from the otherwise applicable utility rate. The advantage of this structure is that the buyer knows it will always pay a discount from the utility rate, but the disadvantage is that the rate will fluctuate with changes in the utility benchmark rate, thereby hampering price certainty.
7. If the developer or seller structures the PPA such that it has the right to sell all of the output of the generation facility to the host, then the regulatory considerations for the seller are reduced, but there are heightened regulatory considerations for the host. If the host doesn’t have a mechanism to dispose of energy that it doesn’t need for some economic return, but is forced to buy the excess, then the economic consequences for the host could be detrimental.
8. A host and developer or seller might wish to consider whether additional generation capacity can be installed on the premises—without triggering onerous regulatory or financial burden—for the purpose of providing incremental electricity for sale (e.g., to an energy service company or directly into the available energy and capacity markets).
9. The net metering programs offered by utilities in New York, for example, are constrained by size limitations created by statute (i.e., section 66-l of the Public Service Law), which creates the following size limitations on eligibility: a) solar electric (residential): not more than 25 kW; b) solar electric (non-residential): not more than 2,000 kW; c) farm waste: not more than 1,000 kW; d) micro-combined heat and power: not more than 10 kW; e) fuel cell (residential): not more than 10 kW; f) fuel cell (non-residential): not more than 1,500 kW; g) micro-hydroelectric (residential): not more than 25 kW; and h) micro-hydroelectric (non-residential): not more than 2,000 kW. New York’s net metering law also authorizes certain “customer generators” to engage in “virtual” net metering by permitting net metering credits to apply to meters serving property owned or leased by that customer generator that is located in the same service territory and load zone. See Section 66-l(e).
10. This analysis refers to the broad group of such certificates and attributes as RECs. A developer or seller and host should consult with applicable state law to determine what type of commodity the proposed generation facility may produce. If the host has an important interest to be served by showing that it has purchased the RECs associated with the facility, then the host must make sure that the PPA contains express language transferring title to the RECs to the buyer and requiring the seller to take reasonable steps (e.g., submitting a certificate confirming that the facility produces renewable energy) to cooperate with the buyer to ensure that the buyer receives the economic benefits of the acquired RECs.