Power Purchase Agreements: Utility-Scale Projects

I. The Revenue Stream. When a solar project is owned by an independent power producer rather than a utility serving its own load, the agreement that provides for an assured source of revenue from the energy output and related environmental attributes of the project is central to the project’s viability. In theory, the energy output of any resource—solar included—can be sold into the many local spot markets without a long-term output agreement on a “merchant” basis. In practice, however, the risk attendant to such merchant sales—where the project owner takes the prevailing market price at the point of interconnection—has proven too great to enable investors (and most developers, for that matter) to get comfortable that the project will be and remain economically viable. In part, this is due to the fact that such market prices are difficult to predict and historically have tended, on average, to be lower than prices that would be available under a long-term power purchase agreement (“PPA”). In tight markets, the spot market can soar well above the long-term contract price, as it did in California circa 2001 or during the more recent winter storm Yuri that hit Texas in February 2021. Such spikes in market prices tend to not only be rare and short-lived (often lasting no more than a few hours during peak load times), but more importantly, they are unpredictable and thus cannot provide the requisite assurance that the project will produce sufficient revenues over time to maintain its economic viability.

As a result, the standard model for solar projects is to have some sort of output agreement that either provides for the long-term sale to a utility of the energy output (and typically associated environmental attributes) at a specified price or provides a hedge against the price volatility inherent in the spot market. The primary vehicle historically used in this regard is a long-term PPA with an offtaker under which the offtaker agrees to purchase, at a specified price, all energy and related environmental attributes as and when the same are produced by the solar project. That offtaker is often a load-serving utility, but large commercial and industrial customers have been significant players in the PPA arena in order to accomplish corporate renewable energy goals and/or hedge their own power costs, though, with these offtakers, the typical structure is a virtual, not physical agreement.

Alternatively, in the organized energy markets, it is possible to protect against market price risk by entering into an energy hedge or a contract for differences (“CFD,” also known as a virtual power purchase agreement (“VPPA”)) with a creditworthy counterparty. Energy hedges and CFDs have some advantages over PPAs, and they are often favored by commercial/industrial offtakers because they avoid triggering state laws that may restrict direct retail sales—one of the reasons that CFDs and VPPAs are often the type of agreement preferred by corporate offtakers. They are not contracts where the “buyer” (i.e., the counterparty to the seller/solar plant owner) intends to use the energy to meet its own needs, as is the case with a utility under a PPA that is buying energy to meet its own load. As a result, in theory, the counterparty can be located anywhere, without regard to its needs for energy in the area in which the solar plant is located.

In this chapter we will explore the basics of these output agreements, with a focus on some of the key differences between traditional PPAs and CFDs that continue to be the principal output arrangement in solar energy.

II. The Parties.

A. The Seller. With few exceptions, the seller is a special purpose entity (often called an “SPV” or the “project company”) that owns and operates the solar plant that will generate energy and environmental attributes (“output”). For a variety of reasons (e.g., limiting liability and having a tidy, “one-stop” security package for investors), such SPVs generally only own one asset: the solar plant in question. But the seller may also be a power marketer that is buying the output of a plant from the developer-owned SPV and reselling it to one or more purchasers. If the power marketer is reselling output, the resale PPA will usually track the relevant terms of the underlying PPA because the marketer will not want to promise more than it has the right to deliver. As a result, the marketer will often use a “back-to-back” PPA for the resale. The resulting terms will be almost the same as those in the underlying project PPA, except for price or other unique items that the marketer does not wish to pass through to the ultimate buyer.

B. The Buyer. The buyer is often a utility that purchases the solar project’s output to serve its load. Utilities tend to be the ultimate end-user of the output simply because, under the laws of most states, only regulated utilities can sell electricity to the end-user (e.g., a business, commercial, or residential user).¹

But utilities are not the only buyers. Large corporations are a larger and larger share of energy transactions in the market as corporations seek to achieve sustainability goals. Due to legal restrictions that may prevent an end-use customer from directly purchasing renewable energy, transactions with corporate customers tend to rely on a variety of structures. These structures include direct retail sales where state law allows it, pass-through deals involving the local utility, financial arrangements that do not involve a physical delivery of power (including CFDs), and true wholesale deals where the corporate customer has the capability to operate in that market. Corporate customers also often demand different contractual terms than utilities for accounting, public relations, or other reasons. We will get into some of these differences below. Power marketers may also buy output for resale to one or more third parties. Power marketers sometimes can purchase all of a project’s output (something that no other single-market player may be able to do), taking a “merchant position” and enabling the owner to finance the plant.

C. Credit Support Provider. The physical delivery PPA will require the offtaker to purchase the output that the seller delivers. In a VPPA, generally, the offtaker pays the seller when an agreed-upon market price exceeds the fixed price in the agreement; and the seller pays the offtaker when the fixed price exceeds the agreed-upon market price. In each structure, the agreement will typically also require the seller to pay the buyer if the project is not built on schedule or fails to achieve certain performance standards. Each party will be concerned about the other’s ability to satisfy these payment obligations. If one party is not creditworthy, the other may require it to provide a guarantee or post a letter of credit or other security to ensure that amounts due under the PPA will be paid. In fact, it is only the rare offtaker that does not insist that the seller provide substantial security for its obligations under the PPA.

But it should be noted that this tends to be a one-way street in utility agreements: the seller posts security in favor of the offtaker, but the utility offtaker almost never posts security in favor of the seller. Traditionally, most utility offtakers tend to be acceptable credit risks (most investor-owned utilities being rated in the “BBB” category, while most municipal utilities are rated “A” or higher), and their gross revenues in comparison to their liability under the PPA are more than adequate to give assurance that meaningful recourse can be had against the offtaker should it default in its PPA obligations. That said, offtakers that are not traditional utilities pose a different set of questions for sellers to consider when negotiating credit support terms. For example, sellers may wish to revisit the offtaker credit support question if the offtaker is a subsidiary of a large corporate offtaker without assets or a community choice aggregator with no credit rating and a short operating history. In some cases, a creditworthy or credit rated offtaker will not agree to post credit support up-front but may be obligated to do so if its credit rating falls below a negotiated threshold, such as investment grade levels. In these instances, the buyer’s options for posting credit support tend to be similar to seller’s (i.e., letter of credit, cash, or guarantee from a creditworthy guarantor).

Sellers are usually given the option of posting security in one of three forms: cash deposited in escrow, a letter of credit from a highly rated (“A” or better) bank, or a guarantee from a creditworthy entity. Except as a temporary expedient (e.g., while awaiting receipt of a letter of credit), cash is virtually never posted as security. It is simply too expensive to tie up such large amounts of cash and, in any event, an SPV that owns the solar plant generally is not cash rich (to the contrary—SPVs tend to be funded on a “just in time” basis by their parent). And because most solar plants are financed via tax equity investments where the tax equity investors will become equity owners of the SPV, sellers’ parents generally do not want to take on the additional risk inherent in being the source of the cash posted as security, but would prefer to have the SPV itself provide the security (and thereby share the cost of providing the same and the risks it entails with all the owners of the SPV, including tax equity).

Guarantees from a creditworthy entity—usually the parent of the developer or corporate subsidiary—are used in certain instances but, for reasons similar to those noted above in connection with cash deposits, are not the most favored form of security. From a cost standpoint, one could assume that a guarantee is the least expensive choice, since it does not require foregone investment opportunities (as the posting of cash does) or an annual out-of-pocket fee (as does a letter of credit). But encumbering one’s balance sheet with a multimillion-dollar guarantee does, indeed, impose a cost on the guarantor in terms of the diminished credit capacity resulting from the contingent liability represented by the guarantee. In fact, in many large companies, there is an internal charge for such use of the company’s balance sheet. Furthermore, imposing the guarantee liability on the developer’s parent shifts part of the project risk from the SPV to the developer’s parent and undermines the notion that all equity owners of the SPV (including tax equity investors) should share in the cost of doing business.

There is no universal standard for the amount of security that is required to be posted. In most PPAs, the security is divided into construction period security and security from and after the date the solar plant achieves commercial operation. In such cases, the construction period security is usually required in an amount equal to the per diem amount of any delay damages that may be owing if the seller does not achieve commercial operation by the target date set forth in the PPA, multiplied by the number of days between such target commercial operation date and the “drop dead” date (i.e., the date the utility can terminate the PPA if commercial operation has not yet been achieved). For the post-commercial operation security, the amount is usually set somewhere between six and 18 months of expected payments under the PPA. However, where the PPA price is a “levelized” price throughout the entire term of the PPA (e.g., $27/megawatt-hour (“MWh”) for 20 years, as opposed to an inflating price of, e.g., $20/MWh in the first year, increasing at the rate of 2.5 percent per annum), occasionally, though not very commonly, the security amount increases over time until a certain “crossover” point is reached (usually between years 12 and 15 of a 20-year PPA). This approach is based on the theory that with a levelized price, the utility is paying more than it should in the early years and less than it should in the later years.

III. The Term. The term of the traditional utility PPA has typically been around 20 years, to enable amortization of project debt and a period of return for the project sponsor. However, offtakers, particularly corporate offtakers, are increasingly requesting shorter terms, such as 15, 12, and even 10 years. Where the term is shorter, sellers will need to very carefully consider the expected financing model, especially if it is dependent upon expected returns after the end of the initial PPA term.

A. Effective Date. The PPA will be binding on the date it is signed (often called the “effective date”). This ensures that the offtaker will buy the output once the project is built and that the project owner will build the project and not sell its output to anyone other than the purchaser.

B. Commercial Operation Date. The term of the PPA usually begins on the effective date, but the length of the term is often defined by reference to a “commercial operation date.” For example, the term might end on the 20th anniversary of the January 1 following the commercial operation date. In other PPAs, the delivery term begins on the commercial operation date and extends for a specified number of years.

The commercial operation date often starts the PPA’s delivery term, determines whether the project has avoided liquidated damages by achieving its “guaranteed commercial operation date,” and establishes the point at which the price switches from a “test energy rate” to a “contract rate.” It is therefore important to define “commercial operation date” carefully. Generally, “commercial operation date” can be defined as the date on which all or some specified portion of the project and all other portions of the project necessary to put it into operation with the interconnection facilities and the transmission system have been tested and commissioned and are both authorized and able to operate and deliver energy to the transmission system in accordance with prudent utility practices. The parties often negotiate more specific standards for judging whether commercial operation has been achieved and occasionally require that an independent engineer be engaged to make findings that support the achievement of commercial operation.

In most cases, “commercial operation date” is defined in a manner that allows the project owner to achieve commercial operation even if it has installed fewer than all of the solar units called for by the PPA. For example, the PPA may call for an installed capacity of 50 MW, but the commercial operation date may occur when 45 MW of capacity have achieved commercial operation (i.e., when the project has been “substantially completed”). Such PPAs typically require the seller to continue building the project until all of the project’s installed capacity has achieved commercial operation. If the seller achieves commercial operation for substantial project completion but thereafter fails to complete the remainder of the project, it may be liable to the buyer for liquidated damages for the incomplete capacity. A developer’s ability to declare commercial operation with respect to a portion of the project’s expected installed capacity may also be useful to the developer in situations where partial force majeure, delayed interconnection, or an unanticipated permitting or land issue might create a problem as it relates to timing issues around the investment tax credit.

C. Termination Before the Commercial Operation Date. PPAs usually include “off-ramp” provisions that enable the offtaker to terminate the PPA if certain events occur or fail to occur. Perhaps the most common provision for early termination in a utility offtaker PPA includes the failure of a public utility commission to approve a PPA or to allow its costs to be passed through to ratepayers. Developers should carefully consider the timing of the expected development costs it will incur to advance the project while the buyer retains an ability to terminate. In other words, a developer should not be required to incur substantial development costs, and certainly not to start construction, prior to the time in which the buyer is bound by the PPA. Accordingly, a buyer’s termination right associated with commission approval should have an end date so that the developer can adjust its schedule accordingly. In the not-too-distant past, developers could also obtain early termination rights for reasons such as the failure to obtain reasonable financing. But such termination rights in favor of developers are becoming increasingly rare, as offtakers expect developers to be experienced and to take on the risks of project development. Other early termination rights that may be available are a seller’s inability to obtain interconnection on acceptable terms, particularly costs and timing, consistent with the seller’s expectations and the inability or delay in obtaining permits required to build or operate the project. In cases where the buyer can invoke a termination right after the seller has exhausted its right to pay delay damages, careful attention should be paid to limiting the developer’s liability and the purchaser’s remedy to the delay damages already paid to the buyer or to some other clearly defined payment.

Another termination right commonly included is a termination right for a seller’s extended failure to achieve the commercial operation date. If the seller has not demonstrated commercial operation by a specified expected commercial operation date, then, typically, the seller will owe delay damages to the buyer for each day of delay until the earlier of the date that commercial operation is achieved or some maximum delay period. Once the maximum delay period has expired, one or both parties will have a right to terminate and there may be an additional payment due from the seller, either in liquidated damages (typically capped at development period security) or a termination payment calculated with the seller as the defaulting party. Other milestones are discussed further below in Section V.C.

IV. Purchase and Sale.

A. Delivery Point. The PPA will require the sale of energy to occur at a specified delivery point. If the energy is to be delivered at the plant in a “busbar” sale, the delivery point will usually be the high side of the transformer at the project’s substation. In a busbar transaction, the buyer provides the transmission required to transmit the energy from the plant to the point where the buyer intends to use it (or to deliver it to another party in a resale transaction). The PPA may also require the seller to provide necessary and adequate transmission to take the energy away from the project’s busbar or otherwise assign to the seller the curtailment risk associated with inadequate transmission away from the project. Alternatively, the PPA may also require the seller to deliver energy to a specific point some distance from the plant, in which case the seller will be responsible for securing the required transmission to the delivery point, and the buyer will be responsible for obtaining the transmission required to take the energy at the delivery point. Transmission ancillary services can be fairly costly and should be specifically allocated in the agreement. Title and risk of loss pass from seller to buyer at the delivery point. In a VPPA, energy is not actually delivered to the offtaker. Instead, energy is typically sold into the energy market with which the project is interconnected at such point of interconnection. That said, the settlement under the VPPA is typically at a different point on the system (often a hub or collection of nodes), which exposes Seller to basis risk between the point of interconnection and hub as described further below.

B. Pricing.

1. Contract Rate. Price is usually the most important part of the PPA. The price may be flat, escalate over time, or contain other features. An escalating price is often set to escalate at the beginning of each new “contract year,” thus encouraging the seller to lock in the initial price and the escalation rate by achieving commercial operation as soon as possible.
2. Test Energy Rate. Because an electrically distinct array (panels behind a single inverter) can generally function independently of other arrays, the PPA may require the purchaser to buy power from the arrays as they are installed, connected to the transmission grid, and made operational, even though the project as a whole has not achieved commercial operation. To encourage the seller to achieve commercial operation as soon as possible, such energy is often sold at a test energy rate, which is lower than the contract rate that will be paid once the commercial operation date is reached. However, in Independent System Operators (“ISOs”)/Regional Transmission Organizations with energy markets (e.g., the Midcontinent ISO), the seller may choose to sell its test energy into the market rather than to the purchaser, or alternatively the purchaser may pay the market rate for test energy.
3. Excess Rate. A PPA often requires the seller to specify how many MWhs the plant is expected to produce each year. This output estimate may form the basis of an output guarantee or a mechanical-availability guarantee. To encourage the seller to make an accurate estimate of expected output, the seller may be paid less than the contract rate for each MWh of energy in excess of, for example, 110 percent of the estimated annual output.
4. Fixed for Floating Pricing. While there are a number of different variations for how a fixed for floating price can be structured, the general concept is that the offtaker agrees to guarantee to the developer a fixed price per MWh of metered energy. A developer delivers energy from the project into the energy market, either the day-ahead or real-time market, and receives the locational marginal price (“LMP”) revenue (or pays the LMP cost for negative LMP) at its Pnode from the ISO in connection with such metered energy. The parties also agree on a floating price, which can be at the Pnode but more often than not is at another point in the ISO, typically a more liquid hub, i.e., an averaged collection of nodes within the energy market. Over an agreed-upon time period, the parties compare the floating prices to the fixed price and a payment is made to or from the offtaker so that the end result is the developer receives no more or less than the fixed price per MWh. Variations of this structure include determining which market the seller will participate in (day-ahead or real-time), establishing a minimum floating price and mechanisms to share upside floating prices or extreme basis events. If a hub price is used, a developer must understand and mitigate the basis risk (or price differential risk) between the project’s LMP and the hub price that it is taking. In addition, the offtaker will typically want to limit its exposure to negative floating prices. This is often accomplished by setting a negative LMP floor price, below which either the project is deemed to have no metered quantity or the floating price is replaced by an agreed-upon minimum price when calculating the settlement amount.

C. Environmental Attributes; Other Products. Environmental attributes are the credits, benefits, emissions reductions, environmental air-quality credits and emissions-reduction credits, offsets, and allowances resulting from the avoidance of the emission of a gas, chemical, or other substance attributable to the solar project during the term of the PPA, together with the right to report those credits. Environmental attributes are sometimes called “green tags,” “green tag reporting rights,” or “renewable energy credits.” The PPA should make it clear that investment tax credits, solar energy incentives (such as those that may be provided under a state program), and any other environmental attributes necessary to generate the quantity of power being sold to the purchaser are not part of the environmental attributes and thus are not being conveyed to the purchaser.

The seller will usually warrant title to and the current eligibility of the attributes but will not universally warrant the future use or value of the attributes or whether and to what extent they will be recognized by law after a change in law. Instead, the seller will often agree to spend up to a negotiated amount of money (either annually and/or in total) to maintain the value and use of environmental attributes after a change in law. Once that financial cap is reached, the seller is under no further obligation to spend money in an effort to shield an offtaker’s environmental attributes from a change in law. As a result, the purchaser assumes some risk that the law or the market might change in a way that reduces the value of the environmental attributes. To the extent the buyer is entitled to future environmental attributes, there is typically an agreed-upon allocation regarding future costs associated with seller becoming eligible to provide such future environmental attributes.

In addition, parties should address whether capacity and other ancillary services are part of the product being sold. If they are part of the product, then there may be a guarantee of performance for capacity delivered under the applicable regulatory construct, with damages payable for any shortfalls. If they are not part of the product, then the seller should confirm that its energy sales under the PPA do not conflict with its plan to monetize the capacity and/or ancillary services separately from the PPA. Further, sellers should be cognizant that corporate offtakers will often require the seller to prioritize energy and renewable energy credit deliveries over capacity or ancillary services sales.

D. Allocation of Taxes and Other Charges. The PPA should specify who pays any sales, excise, or other taxes arising from the transaction. Although most states do not tax wholesale energy sales, the parties may wish to consider allocating the tax liability that might result from future legislation.

V. Permitting and Development.

A. Commitment to Develop. The PPA will make the project owner responsible for developing and constructing the project. Many negotiations revolve around what the seller will or will not be required to do to develop the project, as well as the off-ramps that each party has if the project does not achieve certain stated milestones.

B. Status Reports. The buyer is typically interested in the ongoing development of the project because it needs to know when the energy will be delivered onto its system or when it will need to take a hedge position. As a result, the PPA usually requires the seller to deliver regular reports to the buyer about the status of permitting and construction.

C. Milestones and Delay Damages. The PPA often includes a schedule of certain project milestones (e.g., the date by which the seller must secure project financing, the date by which equipment must be ordered, the date by which all permits and the interconnection agreement must be in place, and the commercial operation date). If the seller fails to achieve a milestone, the buyer may have a right to terminate the PPA, collect delay damages, or require the seller to post additional credit support. The seller will therefore want to limit the number of milestones and bargain for some flexibility, especially in cases when a delay in achieving an interim milestone is not likely to delay a project’s completion date. Sellers would prefer PPAs that provide that the buyer’s only remedy if the seller fails to meet a project milestone is to terminate the PPA without recovering damages; however, it is very rare that a PPA provides for termination without damages. Buyers are concerned that such structure would give the seller a right that resembles a put and strongly prefer to require the seller to suffer some consequences if project milestones are missed. Many interesting negotiations revolve around the off-ramps that the seller will have versus the damages it will pay to the buyer if it fails to build the project in accordance with the PPA. A common middle ground is for the seller to agree to pay delay damages up to an agreed-on cap (often the credit support posted by the seller during development), which defines the limits of the seller’s exposure if the project is not built but gives the seller an incentive to use diligent efforts to finish the project on time.

VI. Interconnection and Transmission. The PPA will require the seller to bear the cost of interconnection (including any network upgrades required by the new project) and all costs of transmitting the energy to the delivery point. If the seller is the project owner (as opposed to a marketer), it will also be responsible for negotiating the interconnection agreement with the transmission provider. The buyer will be responsible for arranging and paying for transmission from the delivery point. (For more information on interconnection and transmission-related issues, see Chapter 5.)

VII. Performance Incentives. Although a seller would prefer to enter into an “as-delivered” PPA, which means that the seller is obligated to deliver only what the project actually produces, PPAs today will require the seller to warrant or guarantee that the project will meet certain performance standards. Such guarantees usually enable the buyer to recover all or part of its incremental cost of purchasing replacement power and environmental attributes in the market to the extent that the project fails to perform as expected. Performance guarantees enable the buyer to plan around the plant’s expected output for both load and, if applicable, Renewable Portfolio Standard (“RPS”) compliance, and strongly encourage the seller to maintain a reliable and productive project.

A. Output Guarantees. The PPA may include an output guarantee to the buyer. An output guarantee requires the seller to pay the buyer if the project’s output over a specified period fails to meet a specified level, after taking into account output lost because of force majeure, curtailments, or maintenance or other agreed-on subtractors. The period is typically annual or biannual (although there are occasionally seasonal guarantees in today’s PPA market). The reason to establish the guarantee over longer time periods is to minimize the impact of particularly low or high solar irradiation years.

B. Availability Guarantees. An availability guarantee requires the solar arrays in the project to be available a certain percentage of the time, after excluding hours lost to force majeure, curtailments, and a certain amount of scheduled maintenance and other excused non-available hours. Mechanical-availability percentages usually range from 90 to 95 percent, but they may have a lower percentage in the first measurement period. Mechanical-availability guarantees had become rare in utility PPAs where the utility had RPS obligations to satisfy, but they are standard in PPAs where the offtaker is a corporate or industrial user, due to accounting issues that cause these offtakers to prefer an availability guarantee over an output guarantee.

C. Liquidated Damages. If a guarantee is not met, the PPA usually provides a mechanism for determining the damages suffered by the buyer. First, in the case of an output guarantee, the parties determine the output shortfall (stated in MWhs) relative to the amount of output that the buyer would have received had the project lived up to its guarantees or, for an availability guarantee, the availability shortfall (stated in a percentage) relative to the guaranteed availability percentage. Second, the output shortfall is multiplied by a price per MWh determined by reference to an agreed-on index or a fixed price (a liquidated damage for shortfalls). Because market indexes currently cover only power prices and do not include the value of environmental attributes, the PPA may include an adjustment to account for the assumed value of the environmental attributes or may use a firm price index as a proxy for the value of the energy plus the environmental attributes. The availability guarantee damages are usually a set amount per percentage of shortfall, or the shortfall is converted into an output shortfall and then the damages are calculated similar to the output guarantee damages. The seller pays the liquidated damages to the buyer or credits the damages against amounts owed by the buyer under the PPA. The seller may in addition seek to include the right to cure any output shortfall through delivery of replacement energy and environmental attributes at its option where the seller and the buyer can mutually agree on the time and place for such replacement deliveries. In any case, the seller may also seek to cap liquidated damages or its replacement obligation on an annual or aggregate basis.

D. Termination Rights. To protect against chronic problems at an unreliable solar plant, the PPA may allow the buyer to terminate the PPA if the output or mechanical availability of the project is below a stated minimum for a certain number of years.

VIII. Curtailment and Force Majeure.

A. Curtailment. The PPA often describes circumstances in which either party has a right to curtail output. For example, the seller may have a right to curtail deliveries if the plant is affected by an emergency condition. The PPA may permit the buyer to curtail for convenience or what is often referred to as “economic curtailment,” in which case the PPA usually requires the buyer to pay the purchase price for the curtailed generation. In organized markets, where the offtaker is also the scheduling coordinator for the facility and in which generation dispatch by the ISO is affected by the bid curves submitted by the scheduling coordinators, it is important that the PPA indicate that curtailments caused by the offtaker’s bidding strategies are deemed to be economic, and therefore compensated, curtailments. However, buyers often negotiate the right to a certain amount of uncompensated curtailment. Facility curtailments caused by transmission congestion or conditions beyond the point of delivery are often allocated to the seller, although the topic of curtailment is frequently a difficult issue in PPA negotiations.

B. Force Majeure. If an event beyond a party’s control and which cannot be mitigated by such party occurs, the party’s duty to perform under the PPA may be excused. For example, if a natural disaster disables the facility by damaging a transformer, the seller should be excused from delivering energy until the transformer is repaired. The party responsible for maintaining the transformer would, of course, be required to use diligent efforts to make repairs.

Parties often heavily negotiate force majeure provisions, and such provisions are increasingly extensively negotiated in light of supply chain disruptions caused by the COVID-19 virus and other interruptions to global trade. Good provisions should carefully distinguish between events that constitute “excuses” (which relieve the affected party from its duty to perform) and those that are “risks” (which are simply allocated to a party). The ability to buy energy and environmental attributes at a lower price or sell them at a higher price is not a force majeure event. Moreover, a party’s inability to pay should not constitute a force majeure event under the PPA. A well-drafted force majeure clause will usually list a number of items that both parties agree are force majeure events, as well as list items that the parties agree are not force majeure events. Often, the parties address termination rights for extended force majeure events. Parties should carefully consider how to address risks that are not included in the force majeure provision in the performance guarantee calculations and defaults. For example, if a serial defect or failure of long-lead time equipment would be excluded from a force majeure claim, then sellers and buyers often consider how to address the occurrence of such an event when assessing sellers’ performance for purposes of the guarantee.

IX. Defaults and Remedies. The PPA will usually list events that constitute defaults. These may include:

• failure by any party to pay an amount when due;
• other types of specified material defaults;
• the bankruptcy, reorganization, liquidation, or other similar proceeding of any party; or
• failure to provide or replace credit support within an agreed time.

The default clause should specify how long the defaulting party has to cure a default. If the default is not cured within the agreed period, the non-defaulting party usually has the right to terminate the agreement and pursue its remedies at law or in equity or to suspend performance of its obligations. The remedies clause may also limit remedies or place a cap on the seller’s damages, although a cap on damages usually, but not always, applies to only those events of default occurring before the commercial operation date. It is worth noting, however, that where a seller’s damages are capped after the commercial operation date, the offtaker typically has a right to terminate the PPA if the seller will not agree to continue paying damages, so the cap may be nominal only.

X. Project Lenders and Equity Investors. Even if the project is expected to be financed off a developer’s balance sheet, the terms of the PPA will usually take into account the possibility that the PPA will be assigned to a lender as collateral for project debt. The PPA will therefore contain provisions authorizing the seller to assign the PPA as collateral; requiring the buyer to provide consents, estoppels, or other documents needed in connection with financing; and giving the lender various protections (including additional time to cure defaults). Sellers should also ensure that any restrictions on change of control of seller do not include transfers of equity interests (direct or indirect) of seller to tax equity investors in connection with tax equity financing. In addition, the PPA will typically exempt certain affiliate and successor in interest equity transfers provided the transferee agrees to be bound by the terms of the agreement and the project remains operated by a qualified operator. The PPA may also include provisions to address the concerns and cure rights of future lenders or tax equity investors, such as transfer rights under the PPA in connection with the exercise of remedies by lenders or tax equity investors.

XI. Buyer Options to Purchase the Project or Special Purpose Entity. Many utilities have shown a strong interest in owning solar energy projects. In PPAs, this interest often takes the form of an option to purchase the project or the entity that owns it on or after a specified date. Such options should be handled carefully. An option to purchase the project or the interests in the special purpose entity that owns the project for anything other than the project’s or entity’s fair market value at the time of exercise has been generally disfavored by tax attorneys. Other types of options can raise a fundamental question as to whether the owner of the project is an owner for federal income tax purposes or whether the financing arrangement is something other than “ownership” (e.g., a loan). Rev. Proc. 2007-65, 2007-2 C.B. 967, explicitly provides as one of the qualifying elements that there is no developer/investor/related party purchase option for less than fair market value (at exercise). Developers should ensure to carve out transfers associated with financing arrangements (e.g., tax equity investment, lender exercise of remedies) from right of first offer structured options.

XII. Basic Structure of Hedge Arrangement. The essence of energy hedges and CFDs is that the parties agree upon a price (typically referred to as the “strike price”) for the energy produced. If, at the time the energy is produced, the market price at the point of interconnection with the transmission grid (or at an agreed-upon pricing node on such transmission grid) exceeds the strike price, then the solar plant owner pays the hedge counterparty an amount equal to the difference between such market price and the strike price. Conversely, if the market price is lower than the strike price, the hedge counterparty pays the solar plant owner the difference between the market price and the strike price. In this way, the solar plant owner is assured that it will receive the strike price for all energy covered by the hedge and thus have an “output arrangement” that provides some revenue certainty in a manner similar to a PPA. The hedge counterparty reaps its return by endeavoring to structure the terms such that, if its modeling of energy prices proves accurate, the market price for energy is likely over time to exceed the strike price, thus producing the desired profit or return. Alternatively, the hedge counterparty may execute a mirroring “back-to-back” hedge with a commercial entity and reap a spread between the two otherwise offsetting transactions.

The actual energy produced that is subject to the hedge is often sold into the local market at the prevailing nodal price. But a hedge can be structured to give the counterparty the option of picking up the energy at the interconnection point (or even perhaps at some remote point agreed upon by the parties, if transmission to that point is available) so that it can resell it in bilateral sales to third parties. The motivation for such sales to third parties can be either the anticipation of a price higher than the prevailing market price or a more certain price that eliminates the risk inherent in market price volatility.

Where the energy is not physically delivered to the offtaker, the hedge is a pure financial transaction that is basically the same as an interest rate swap, with the strike price and market prices for the energy substituting for the “strike price” interest rate and interest rate indices used in interest rate swaps. In the event that the energy is physically delivered to the counterparty for resale, it takes on added elements similar to a physical PPA in certain respects. Note that where the hedge is a pure financial transaction, securing transmission to deliver the power to load is not required. But transmission considerations can still play a key role, as the location of the solar plant may be such that it is on the wrong side of a grid congestion point, thus adversely affecting the market price of the power and thereby affecting the economics (and perhaps even the availability) of the hedge.

The hedge does not always cover 100 percent of the energy anticipated to be produced by the solar plant. Rather, it is sometimes structured to be a certain percentage of the output, with the remainder being reserved to be sold on a merchant basis. The amount of production excluded from the hedge is based on a calculation by the concerned parties (the developer, financing parties, and the hedge provider) of the amount of risk the merchant portion of production entails and the likelihood that it will jeopardize the project’s financial viability under certain conservative operating scenarios. In a variation, rather than reserving a certain percentage of the energy, these arrangements are sometimes structured to allow the developer to withdraw all or a portion of the energy produced during certain periods of the year.

Energy and environmental attributes can be bundled under an energy hedge in the same manner as is done under PPAs. The context in which such a bundled arrangement is likely to be desirable is where a major commercial or industrial user acts as the hedge counterparty with a view to both “greening up” its own load and also providing itself with a hedge against rising energy prices in the markets in which it purchases energy to serve its own load. The developer may enter into a hedge directly with such commercial or industrial user, or with a power merchant that then enters into a “back-to-back” hedge with such commercial or industrial user. By entering into such a bundled hedge, the industrial or commercial counterparty gets to claim the environmental attributes and obtain whatever credit might be available to it in terms of public relations and perhaps in terms of meeting certain legal requirements relating to emissions. And by locking into a fixed strike price for an extended term, the industrial or commercial counterparty has reasonable prospects of being the net beneficiary of payments under the hedge as market prices rise over time, thus providing a hedge against similar rising prices of the electricity it purchases from third parties to serve its own load.

A. Other Terms and Conditions. Like the security a developer is required to post under a PPA, developers are also required to post substantial security to secure hedge obligations. The security most often takes the form of a letter of credit, but guarantees from a large balance sheet parent with good credit can also work. The amount of security required to be posted is determined in a manner similar to that under PPAs, based on the hedge counterparty’s assessment of its exposure given the nature of the project and the market in which the hedge is settled, but may also include features of margining as exposure to the strike price varies over time.

Unlike a traditional utility PPA where, in the ordinary course, it is the utility that is expected to pay the developer, energy hedges, like CFDs, may require the developer to post additional credit support in the form of variation margin posted to the hedge provider when market prices exceed the strike price (i.e., when the developer is “out of the money” on the hedge), although this tends to be a heavily negotiated point as developers generally want to cap their potential exposure to higher energy prices. As a consequence, the right to project cash flows as among the hedge provider, lenders, and other project participants can be more complicated than in other circumstances not involving a hedge. In general, because the hedge serves the “revenue assurance function” that a PPA serves in other contexts, the hedge provider typically has paramount rights to project cash flow. The reason is simple: if the hedge provider is not timely paid what it is owed, the hedge can be subject to termination. And termination of the hedge would be a disaster akin to the termination of a PPA.

B. Regulatory Considerations. A unique regulatory requirement that applies to energy hedges but not to PPAs is the Dodd-Frank Wall Street Reform and Consumer Protection Act, Pub. L. No. 111-203, 2010 U.S.C.C.A.N. (124 Stat. 1376) (the “Act”), which is administered by the Commodity Futures Trading Commission (“CFTC”). While the provisions of the Act are complicated, suffice it to say that energy hedges are “swaps” within the meaning of the Act,² and as a result, it may be necessary to comply with certain registration, recordkeeping, reporting, and clearing requirements of the Act.³ In most cases, the reporting requirements will be imposed on the hedge provider, which may be a “swap dealer” or “financial entity” within the meaning of the Act. However, if neither entity is a financial entity, swap dealer, or major swap participant, then the parties are required to agree between themselves as to which will comply with the recordkeeping and reporting requirements.

XIII. Retail Sales Structures. As RPS demand has dipped in recent years, utility renewable procurements have, to some extent, slowed as well. However, the waning of utility demand has not, in all cases, corresponded to a lack of demand for renewable energy from customers directly. Accordingly, another option available to developers in some states is a direct sale to the end-user of energy (retail sale). This structure is particularly attractive to customers motivated by the desire to serve their loads with green power directly. The number of structures available for this type of sale varies depending on the size of the project and the jurisdiction in which the sale will take place.⁴

Generally, sales of energy directly to the end-user are regulated by state utility commissions as opposed to the regulation of wholesale power sales that is within the purview of the Federal Energy Regulatory Commission. Historically, the seller of energy to a direct end-user was regulated as a public utility under state laws, typically by the state utility commission. Moreover, in many jurisdictions, in order to incentivize such public utilities to make the necessary investments to serve retail end-users, public utilities were granted an exclusive right to serve the customers within the service territory granted to such public utility (i.e., the franchise). Without legislative changes to this typical legal structure, a direct sale to an end-user might have two unintended consequences to the solar energy developer: (1) the solar energy developer may find itself regulated as a public utility under state law (including a requirement to justify its rates for the sale of energy on a cost basis); and (2) it may find its sale to be in violation of the exclusive franchised service territory of the incumbent utility.

As a result, the key hurdle a developer must overcome in determining whether a retail sales model is available to it is whether the state regulations and laws would permit such a sale. The answer to the question varies a great deal from state to state.

Other approaches enabling direct sales that vary depending upon jurisdiction include an exemption for certain small projects (i.e., net energy metering arrangements) from rate regulation (though safety regulation may still apply) or an exemption for a developer making sales from any renewable facility to an end-user from regulation as a public utility. Yet another approach enabling direct sales is to permit sales from one affiliate to another, provided the sales are on adjacent property. The key inquiry for the prospective seller is what types of structures (and at what sizes) may be permissible under the state law.

While beyond the scope of this chapter, if the generation facility is remote from the retail load, the developer interested in direct retail sales will also have to understand the options available to it for utilizing the transmission infrastructure to deliver the energy directly to the end-user, as the ability to use the transmission grid for retail wheeling is limited in many areas.

If the developer can overcome these obstacles, then the retail sales structure for direct sales to the consumer is, in many ways, much like the typical PPA, with many of the same considerations previously discussed in this chapter, including price, term, credit requirements, performance guarantees, and default terms. However, the developer may find itself grappling with some additional issues as well. For example, where the customer may still need some service from the utility, the quality of the service to the customer may impact the retail customer in ways that increase costs to such customer. The local utility may charge, for example, a standby rate to the customer for the costs to the utility of “standing by” to serve the customer in the event that the intermittent solar generation is not produced. These costs can be unexpectedly high and the developer should consider the rate impacts to the customer in various jurisdictions in developing its origination strategies. Another issue sometimes encountered in the direct end-user sales structure is addressing a desire of the customer to include a termination for convenience clause in which the customer would have a right to terminate the contract (typically with a negotiated termination payment) in connection with business interruptions, e.g., corporate shutdowns.

In short, developers will be well served to understand how the regulatory landscape in target jurisdictions may offer other sales options besides direct sales to the utility.

¹A sale of electricity to the ultimate user of the power (such as a business, commercial, or residential user) is called a “retail sale.” A sale of electricity to a party that is not the ultimate user of the power but that intends to resell it to a third party is called a “wholesale sale.”
²Although the CFTC has the authority to exempt, via regulation, certain swaps from the purview of the Act.
³As of May 11, 2022, energy commodity swaps are not required to be cleared under the Act.
⁴While net-metering arrangements offer one avenue for direct sales in some jurisdictions, given the size of the projects typically eligible for net-metering arrangements, these structures are not discussed in detail in this section. See Chapter 2 for more information on net-metering arrangements.