Photovoltaic solar projects have become a conventional asset class. The technology is proven at scale, the revenue stream looks and feels like an annuity, and with mainstream customers like Walmart and your local utility, the sizzle has faded.
In recent years, investors have flocked to the space hoping to seize on the final few opportunities for high returns coupled with infrastructure-like stability. As the market matured, margins compressed and double-digit returns are now likely permanently in the past. Still looking for sizzle, investors, now comfortable with solar as a generating asset, are exploring ways to invest earlier in the development cycle. The increased risk ought to provide increased yields, or so the thinking goes.
Happy to oblige, developers have been offering up their development pipelines for sale. These pipelines promise attractive returns, and the offerings are timely. With the federal Investment Tax Credit set to step down at the end of the year, projects must commence construction by December 31, 2019 in order to take advantage of the current 30 percent tax credit. Adding to the frenzy is a sense that we may be approaching market saturation for investment-grade offtake.
Projects with strong contracted revenue streams from investment-grade-rated counterparties are scarce, and offtake tenures, once a standard 20-25 years, continue to plummet. Given these circumstances, the market will continue to see increased investment in solar platforms and development pipelines.
The question inevitably arises whether the investment community understands solar development assets as well as it understands solar operating assets. If the glossy investor presentations in circulation now are any indication, the answer is no.
This is part one of a four-part series exploring how to value and diligence a solar development pipeline. This series will consider commercial and industrial (C&I) and utility-scale pipelines and will not address residential pipelines.
Development pipeline and operating portfolios are measured in megawatts. Generally, investments in solar portfolios at the stages of either “notice to proceed” (NTP) or “commercial operation date” (COD) are assumed to be de-risked. System sizes tend to decrease slightly from NTP to COD, but these changes typically do not go beyond post-closing quibbles over liquidated damages.
Development pipelines, on the other hand, are a mixed bag of risk. Pipelines tend to include (in order of declining risk): early-stage assets, later-stage assets and “NTP-ready” assets. Since attrition occurs as projects move from the early-stage to NTP-ready phase, developers looking to sell their pipelines often provide their views on the pull-through rate for projects in their pipelines.
A common way to think of a pull-through rate is in the context of the offtake agreement. The offtake agreement, often a power-purchase agreement (PPA), is the centerpiece of the solar project. Developers pour an enormous amount of sweat equity into acquiring offtake. Sales cycles for unsolicited PPAs last anywhere from three months to three years. Sophisticated offtakers hold competitive RFP processes that reward bidders that are willing to build projects below cost in the hope that they will be awarded follow-on business.
With the exception of feed-in tariffs directly with a utility, offtake agreements are bespoke products of painstaking negotiation. Rightfully, many developers consider the PPA to be their biggest value-add and the most critical element of a project’s success.
Therefore, a potential investor may see pipelines broken down into PPA-related categories for the purposes of determining attrition. For instance, a common set of categories and pull-through rates would be as follows: Projects in the “proposal” stage have a 5 percent likelihood of success; projects in the “term sheet” stage have a 30 percent likelihood of success; projects in the “negotiation” stage have a 50 percent likelihood of success; and projects in the “executed PPA” stage have an 75 percent likelihood of success. This approach is elegant in its simplicity, while maintaining just enough number-crunching for an analyst.
If you are thinking that it probably takes more than a few short clicks to get to the probability-weighted megawatt number of a development pipeline, you’d be right.
Every individual solar project has four pillars on which it succeeds:
- Pillar I: Revenue streams
- Pillar II: Interconnection
- Pillar III: Site control
- Pillar IV: Permitting
A fault in any of the four could represent a binary risk to a project. In order to value a pipeline, one must diligence each of the four pillars and be able to assign a stage of development to each project for each pillar. Complicating matters, within a single pipeline there is often a stunning lack of standardization across the project documents that govern the four pillars. Interconnection requirements vary by utility, down to the feeder. Permitting requirements vary by jurisdiction, down to the subdivision. And site control is, well, site specific.
This post will explore the first pillar of project success, revenue streams, and end with a bonus section on geographic diversity.
Pillar I: Revenue Streams
Structure and authority
Within a single development pipeline, you may encounter the following types of offtake agreements:
- Feed-in tariff (a project directly with a utility)
- Net-metered PPA (a project sited on or off the offtaker’s premises)
- “Behind-the-meter” PPA (a project sited on the offtaker’s premises)
- Contract for differences (a project sited remotely from the offtaker)
- Community solar agreement (with subscription agreements)
Because each of these agreements rely on specific statutory authorities, legal review is essential. This post will not address the legal considerations of the terms and conditions of PPAs. Instead, we will focus on the nature of the offtake agreement and raise certain considerations for pipeline valuation.
Feed-in tariff: This agreement generally represents the least amount of risk. The offtaker is a utility that likely maintains an investment-grade rating, the agreement is drafted by a sophisticated party, and the agreement itself is sanctioned by the authority having jurisdiction. Therefore, early diligence questions may be limited to any deadlines associated with the commissioning of the system and ensuring that the project generally complies with the terms of the feed-in tariff. Additionally, look out for hefty performance and payment assurance provisions that require substantial bonding, a letter of credit or cash collateral.
Net-metered PPA: This PPA is executed pursuant to a net-metering tariff authorized by the state public utilities commission or public services commission and implemented by the utility. It is important here to ensure that the PPA and the project are structured in accordance with the applicable net metering tariff and all eligibility requirements are met including timely submission of application. Net metering tariffs vary by state and, in some cases, by the utility territory.
Additionally, some states have multiple net-metering tariffs. It is not unusual to find that an executed PPA may not fit within the confines of the net-metering tariff that the developer intends to use. This increases regulatory risk and may require redevelopment, transforming a later-stage asset to an early-stage asset. It is particularly important to understand the applicable net-metering rules related to system size, co-location of multiple systems, remoteness from the offtaker, and the eligibility of the offtaker itself.
Behind-the-meter PPA: This is a bilateral agreement between the system owner and the offtaker for a system located on the offtaker’s property. The primary diligence question here is whether behind-the-meter PPAs are enforceable in the jurisdiction where the system is set to reside. If so, these agreements can be the simplest on which to perform due diligence. Generally, the offtaker also grants site control for the project, which also streamlines review.
Risk for these projects may be particularly concentrated on the individual offtaker, as the single counterparty responsible for the revenue from and access to the system. What’s more, because the system is generally sited on the offtaker’s land or roof, in the event of termination or at the expiration of the PPA, alternative offtake opportunities may be limited.
Contract for differences (CFD): This is used for projects sited remotely from the offtaker, but within the same utility or regional transmission organization (e.g., PJM) territory. The CFD provides a fixed-for-floating rate and the agreement may indicate that it is for the physical delivery of power at the node. It is important to consult with a legal expert when reviewing this contract to ensure compliance with Dodd-Frank and other applicable regulations.
Community solar: This offtake arrangement (often a form of net metering) is enjoying popularity at the moment. “Community solar” is used to designate a wide variety of project configurations in the development community. If often means a structure whereby the system owner sells electricity to the utility, provided that the system owner is able to amass a certain amount of subscribers within the utility’s territory. Compliance with the precise statutory authority and the utility’s guidance is critical here.
Early diligence should reveal the number of subscriptions and the total megawatts subscribed, as well as the number of subscriptions and total megawatts required to be subscribed in order to commence construction and to achieve commercial operation. Additionally, there may be quota limitations with regard to certain classes of subscribers.
PPA tenure and price
Twenty years used to be the gold standard for solar deals. Recently, as the cost to deploy solar has fallen, so too have PPA tenures. Today, 10-year tenures are not unusual. Conversely, the useful life of photovoltaic systems continues to lengthen and the degradation of the panels themselves is lessening.
Thus, in order to recognize the true value of the system (and to stay competitive), investors are assigning value to the “tail period” after the expiration of the PPA. Some considerations for tail-period valuation are listed below.
Questions related to potential or additional offtake: Where is the system located? Is it on the offtaker’s property? Is it on a building or near a population center where continued occupancy is expected? How long are the roof warranties valid? How long does the site control last? Does the system have the right to be on the land post-PPA? For how long? What are the renewal terms? How competitive is the lease rate? What alternative offtake arrangements could be made given the regulatory landscape?
Questions related to individual investor risk appetite: Where else/for what other investments/under what circumstances does the investor take merchant risk? Is there a hedge or insurance product to meet any floor return requirements?
Along with tenures, PPA prices continue to fall. It is important to understand each of the various revenue streams of a project individually to appreciate the significance of the portion flowing from the PPA. In certain areas with high market rates for solar renewable energy credits (SRECs), it is not unusual for PPA rates to be at $0.02 per kilowatt-hour or lower. It is important to understand your risk appetite and desired balance of contracted PPA revenue and market-based incentive revenue.
Most investors know to diligence the creditworthiness of the offtaker in order to determine a default rate. In recent years, many investment-grade rated offtakers have made significant renewable procurements (as seen in splashy PR campaigns and Super Bowl ads). There is growing concern that investment-grade rated offtake is no longer readily available in the market. Therefore, many investors are now investing in projects with unrated offtakers or offtakers with below investment-grade credit. Shadow ratings are gaining acceptance.
Another important consideration is PPA price. If the PPA rate is lower than the avoided cost of energy, a default is less likely. If, on the other hand, the developer were to be so lucky as to have executed a PPA with a rate above the avoided cost of energy (maybe even with an escalator), it is important to consider the possibility an economic default. Finally, if a default is a genuine concern, attention should be paid to the location of the system and possible alternative offtake arrangements.
Projects that rely heavily on SRECs or other incentives present their own set of diligence considerations. If the incentives, like SRECs, are based on production, the yield of the system is critical. Therefore, it is important to check the developer’s yield assumptions, if provided. Engaging an engineer to review the early energy models for larger projects is most prudent.
Another consideration is that the value of tradable incentive, like SRECs, fluctuates over time. Thus, the value of the asset changes over time. This could be a critical consideration for an asset in early-stage development that relies heavily on SRECs for its economics, particularly in a state where the renewable portfolio standard is set to decline. Such fluctuations in value could mean that an otherwise normal development delay of six to nine months poses a binary threat to the economics of the project.
Finally, if the incentive is grant-based, it is important to understand, at least in broad strokes, how the grant is awarded and recognized, which may affect the tax and accounting treatment of a project.
Stages of development
Given the diverse array of offtake varieties, it is not surprising that there is no industry standard for stages of development related to a PPA. Therefore, when considering acquisition of a pipeline or platform, it is important to understand how the developer categorizes its own development stages. Additionally, investors ought to consider their own monetization strategy for the assets in the pipeline in order to determine the relative importance of the offtake.
For instance, is the investor intending to build, own and operate the assets? Is the investor looking to sell the assets at COD? Or is there a strategy to obtain large amounts of megawatts for a different type of exit? If you have the answer to these questions during the diligence process, the relative value of the stages of development for the PPA may emerge much more clearly.
In our next post, we will discuss the second pillar: interconnection.
Bonus section: Geographic diversity (does it matter?)
Geographic diversity is a classic tool for spreading risk. For residential solar portfolios, geographic diversity is of central importance. For C&I and utility-scale solar, investors ought to consider a few additional layers of diversity:
- Region or regional transmission organization (in order to mitigate against fluctuations in the avoided cost of energy and any changes to grid-based incentives)
- State (in order to mitigate against regulatory and RPS risk)
- Region within the state (in order to mitigate against weather phenomena)
- Utility territory (in order to mitigate against interconnection and congestion risk)
In addition to geography, it is important to ask whether the offtakers are diverse. For instance, a portfolio may include 100 projects across 15 states. But if there are only three unique offtakers for all of those projects and/or all the offtakers are in the same industry, the geographic diversity does little to mitigate the concentrated offtake risk. This should be weighed against any cost savings that may be recognized in a pipeline with few offtakers, such as lower transaction costs and more efficient asset management.
Additionally, diversity of offtake type (i.e., net-metered PPAs, CFDs, feed-in tariffs, etc.) may help to mitigate against regulatory risk. Diversity is key, and geographic diversity is just the beginning of the inquiry.
Leslie Hodge is an associate at Mintz, Levin, Cohn, Ferris, Glovsky and Popeo. Her practice focuses on energy project finance, general commercial transactions, startup and corporate matters, contract disputes and litigation.
The result is underpaying on some small-scale projects and overpaying for others, with billions of dollars on the line.
Most policies designed to reward small-scale clean energy installations don’t properly account for the values and costs these investments create.
Advocates for distributed energy, like rooftop solar and home batteries, laud the benefits of siting these tools among customers, rather than in the desert far from population centers. Doing so can prevent line losses, outmaneuver congestion in the transmission grid, provide local resiliency and even offset more expensive grid upgrades, depending on where exactly the assets get built.
“Like real estate, it’s all about location, and yet the credits we provide tend to be the same subsidy provided across the entire state or utility territory,” said Jesse Jenkins, coauthor of a new paper on the topic with three other current and former MIT energy researchers.
The federal Investment Tax Credit, a major driver for solar adoption nationwide, applies equally to a rooftop system that helps defer a substation upgrade as to one that doesn’t. Net metering pays the same for exports that deliver to a neighborhood starved by grid congestion as to one that’s already flooded with solar exports. Time-of-use rates add more sophistication by paying more when power is worth more, but they still don’t touch the locational variable.
In fact, besides New York’s Value of Distributed Energy Resources tariff, which is still going through the back and forth of stakeholder comments and revision, it’s hard to find any jurisdiction in the U.S. that is systematically taking DER location seriously.
That’s bad news, because it sets up a misallocation of societal resources, with billions of dollars in incentives on the line, Jenkins and his colleagues argue.
“If sited at the right locations and operated at the right times, DERs can deliver more locational value than more centralized resources,” they write in the latest issue of IEEE Power & Energy Magazine. “However, DERs also tend to cost more on a per-unit basis than their centralized counterparts, which is due to economies of unit scale.”
They suggest that policy should quantify the locational value of an energy asset at a specific place and compare that to the incremental costs of buying that resource at smaller, more expensive scale, rather than at larger scale elsewhere. Optimal policy would steer resources to cases where the locational value outweighs the incremental cost.
Not all solar is the same
States that want to increase their installed solar capacity have some choices to make.
They could focus on the big stuff, with a renewable portfolio standard the compels utilities to procure large amounts of clean energy. They can also create programs to lower the cost of distributed solar, so more households can benefit from local, carbon-free electricity. Many jurisdictions pursue a mix of both.
The major difference is that small residential solar, like home batteries, can easily cost twice as much as utility-scale facilities on a per-kilowatt basis. That hasn’t stopped numerous states from creating programs specifically to advance small-scale clean energy.
Allocating funds to distributed solar can serve other goals, like boosting jobs in that sector and making voters happy. But those metrics fall outside the calculus of optimal energy system planning.
“There’s a real question about whether we’re getting the most net value out of a particular solar system, or could have saved on cost,” Jenkins said.
An opponent of distributed solar would say subsidies for it are a waste of money and call it a day. That’s not what this paper is about: It’s calling for a framework to reward distributed assets for the things they really do better than centralized systems, while acknowledging the places where they don’t really help.
In the long run, this approach serves the goal of grid decarbonization by prioritizing the clean energy projects that deliver the most bang for the buck.
“Decarbonization is a big challenge. We have a long way to go, and we need to be investing our limited capital intelligently,” said Scott Burger, lead author of the study.
Name the values
Large power plants take up space and need access to higher-voltage wires to transmit their output. They can’t simply drop into dense urban areas where demand is clustered.
DERs, on the other hand, can move more nimbly, and that generates three major values, as outlined in the study:
- Energy delivery: Assets located close to load can overcome transmission grid constraints. This value rises in areas that are more constrained. They can also minimize resistive losses, which average roughly 7 percent in the U.S. and Europe, the study notes.
- Non-wires alternatives: DERs in the right place can defer or entirely avoid an otherwise expensive grid upgrade, like new wires or a substation. This value depends on where a utility would need to improve the existing infrastructure, either due to age or in response to load growth.
- Reliability: When the macro grid fails, DERs can keep the lights on. The authors note, however, that this typically results in private value for whoever’s home or business maintains power in a blackout. That’s a good reason for those people to pay for those DERs, but not for the public at large to foot the bill, the authors argue.
To illustrate how these values play out in different places, the authors — who also include Samuel Huntington and Ignacio Pérez-Arriaga — describe a case study comparing solar installed in a high-congestion spot on Long Island and an average grid location in Mohawk Valley.
After crunching the numbers for locational transmission value, distribution losses and network investment deferral, the illustrative model shows a clear difference. A 1- to 2-megawatt system delivers $36.8 per megawatt-hour of added value, whereas a 1- to 10-kilowatt system, representing a typical home rooftop installation, incurs $79.3 per megawatt-hour of opportunity cost relative to a 30-megawatt utility-scale project.
Based on the locational accounting at that site, the higher unit cost of the smallest system overruns the quantifiable benefits it provides to the system, so it would be better to invest in larger-scale systems.
At the less-congested, lower-priced Mohawk Valley site, neither the rooftop system nor the 1- to 2-megawatt system added enough locational value to justify their incremental cost. The grid need for them simply wasn’t big enough.
Make it happen
It’s hard to argue with the logic that an investment’s value should outweigh its incremental cost. There’s a strong intellectual case for rate design that incorporates not just time variance but locational variance, and rewards it appropriately. And yet, locational value is in practice hardly anywhere in the U.S.
New York’s Value of Distributed Energy Resources tariff has a head start on this for the U.S., but it’s also a reminder that actually delivering on this concept can be highly technical and complicated, and can’t be finalized overnight.
“There are real technical, regulatory and political barriers there,” Burger said of implementing locational value in practice.
On the technical side, going through the math to calculate the locational values is tricky, and it becomes nearly impossible in areas where the distribution systems haven’t been digitally mapped and customers lack smart metering.
For regulatory obstacles, locational value flies in the face of the principle of treating all customers equally; the whole point is that some customers should earn more for their DERs than others. That requires customer education, to ensure people know what they’re getting into.
The deeper looming question revolves around utility incentives. As long as distribution utilities earn profits through capital investments, they’ll have good reason to look for things to build. The promise of DERs is to avoid capital-intensive investments with smaller, cheaper assets that achieve the same function.
Fully internalizing this logic of DERs will likely require a reimagining of utility incentives, like the New York REV principle of awarding profit when utilities save money by deferring a large investment.
As for political challenges, they revolve around the popularity of blanket incentives for distributed solar. The constituencies that like these incentives, including the solar industry itself, gear up when states try to take away net metering.
“Any reform to pricing or subsidies is going to result in a benefit that accrues in the long term,” Burger noted. “That reform might have real political consequences now.”
Then again, when California replaced pure net-metering with time-of-use rates, the more complex tariff sent a much stronger price signal for solar paired with storage. Installers like Sunrun responded by successfully pushing a higher-value product.
Adopting locational rate design would lower compensation for some solar sites, but could make the higher-value locations much more lucrative. That could be the key to getting industry on board with the concept.
“The whole idea of DERs is that they are able to capitalize on locational value,” Jenkins said. “The only way that they can do that effectively is if the rates reflect that.”