United States: How To Value A Solar Development Pipeline (Part 4 Of 4)

Last Updated: April 23 2019
Article by Leslie C. Hodge

Originally published on Greentech Media.

This year will break records. More gigawatts of solar will be installed than in any year before. In January, we learned that customer demand has reached unprecedented levels. And that is just one part of the story.

Behind the scenes, financiers and investors are fueling growth by lowering the cost of capital, entering the development cycle earlier, and providing a dynamic liquidity that many in the development community could not have imagined even a few years ago. Acquisitions of and investment in solar development platforms and pipelines will likely surge this year. It is fitting, then, that we end the first quarter of 2019 with this final installment of How to Value a Solar Development Pipeline.

Time value of money, an important consideration for any investment, takes on even greater meaning in the context of a solar pipeline. As an asset class, solar's development cycle is attractive. Conventional energy assets may take close to a decade to reach operation. And even solar's renewable peers, hydro and wind, have development cycles of between four to seven years.

A solar project, on the other hand, is typically operational between six months and two years from the execution of an offtake agreement. Nevertheless, industry vets refer to the "solar coaster" because that difference between six months and two years can be significant and, in the case of some projects, may pose an existential threat. In order to properly value a solar development pipeline, one must understand the anticipated development cycle and the potential impacts of delays. For an individual project, delay may cause diminution of value. For a pipeline, delay could mean megawatts' worth of attrition.

In this final installment of our series, we will explore the fourth and final pillar of project success: permitting. (Read Part 1 on revenue streams, Part 2 on interconnection and Part 3 on site control.)

Permitting generally represents the greatest unknown for the development timeline. There are a mere 5,000 utilities to worry about with regard to interconnection timing. Compare that to more than 100,000 "authorities having jurisdiction" or AHJs across the country. These entities include federal, state and local agencies with unique and overlapping purviews. Much has been written about the cost impact of this regulatory patchwork, which is felt disproportionally by residential and sub-utility-scale project developers. 

In fact, permitting costs are believed to be the single biggest contributor to the lag in residential solar adoption in the United States compared to other OECD nations, despite America being a home to technological innovation. In recent years, the Solar Energy Industries Association and the Solar Foundation have worked to create a framework for standardized solar permitting. These efforts are laudable and, if adopted by select state and local jurisdictions, could be a game-changer. However, for the projects in today's pipeline, developers and investors must navigate the byzantine status quo. 

A positive outlook

In this article, we will explore the various development stages of permitting and consider the most significant associated risks. Of course, before we deconstruct and list out a parade of horribles, it is important to set the tone for new investors in the space. 

Depending on the jurisdiction, solar permits are issued "by-right" or require a special exception. Even where a project must receive a special exemption, permitting is often not binary; it may add cost or time, but a "rejection" is not the most typical outcome. Solar permitting does not carry the same political risks as other infrastructure investments, particularly conventional generating assets. At the state and local level, political will continues to trend toward renewable investment, with support of voters in both major political parties.

In places where incentives have created a gold-rush-like atmosphere, the risks of 1) feeder congestion that renders interconnection impossible or 2) market saturation that leaves a project stranded without a customer outweigh the risk of a permit denial. Of course, there are exceptions to this rule. For instance, certain individual municipalities that have been flooded with permit applications may pass a moratorium on solar. Another exception may be found in agricultural regions where the economics of farm operations have become depressed at the same time that solar has achieved grid parity.

In these limited instances, there may be a risk that policies are enacted to prevent solar leases from taking agricultural land out of production. This concern, whether founded or not, is new for the United States. 

Stages of permitting development

The specific permits required for a solar project are determined by the location of the project, the size of the project, and the nature of the land or the building on which the project is sited. For ground-mounted projects, a variety of environmental permits are required from federal, state and local agencies. Additional scrutiny and permitting requirements apply to sites with wetlands, forestation and other environmental features, such as identified habitats for threatened or endangered species. In addition to environmental permits, permits may be required from historical, cultural or archeological authorities, federal and state departments of transportation, and the Federal Aviation Administration.

In certain cases, depending on project size, a lead agency may be designated. For instance, projects under 2 MW may fall within the jurisdiction of the county, and the county will coordinate the issuance of a final site plan approval or a special-use permit. For larger projects, the state department of the environment (or an equivalent) may be the lead environmental agency, with the public utilities commission also issuing a permit. Finally, larger projects or projects on federal lands may need to comply with the National Environmental Policy Act and obtain approval from the Bureau of Land Management.  

The stages of permitting development you may find in a typical pipeline include:

  1. Surveys, site studies, plans: Surveys and site studies from third-party civil engineers and environmental consults are typically required for initial submissions for permits. Additionally, a project may need to produce a set of plans, such as a stormwater pollution prevention plan, a reforestation mitigation plan and a decommissioning plan.
  2. Application for discretionary permits: An application for a permit generally kicks off a statutory timeline for review and decision by the AHJ. However, as with the statutory timelines established for utilities discussed in Part 2, consider these timelines soft and remember that the process may be iterative.
  3. Hearing for discretionary permits: Depending on the nature of the permit, a public hearing or other form of public presentation may be required. Generally, if there are any community or NIMBY risks, they emerge at this stage.    
  4. Discretionary permits issued:  Permits are issued specifically for the site plan that was originally submitted and include a set of conditions, which require compliant action during development, construction, operation and decommissioning. Timelines for the issuance of these permits range from 30 days to two years.
  5. Appeals period for discretionary permits:  Often, and especially in the case of federal and state permits, there is an appeals period, during which time stakeholders may appeal the issuance of a permit. 
  6. Land-disturbing permits:  In addition to the lead discretionary permits, these permits are specific to ground-mounted projects that disturb land, as in the case of a project that requires grading. Additional plans, such as an erosion and sediment control plan, may be required, along with bonding and other cost adders.
  7. Ministerial permits: These permits are not discretionary and ought to be issued as a matter of right. Generally, these include building and electrical permits that are obtained during construction. However, it is important to note that particularly in urban and suburban jurisdictions, ministerial permits may include additional requirements related to zoning and roadways. Timelines for the issuance of these permits range from two days to two years.

Key risks

Costs: Until all permits are obtained, the potential for a permit to add cost to a project may be significant. Permits may require expensive mitigation (e.g., reforestation or stormwater management), as well as costly design features (e.g., screens or buffers). Some of the more outrageous examples of cost adders include discretionary approvals or permits that require extensive road improvements (e.g., widening commercial roadways, constructing sidewalks and installing stoplights).

Diminution of value: As a general matter, megawatts decrease as development advances. In the case of permitting, a system layout may need to be reduced in size, so as to accommodate a stormwater management feature or meet setback requirements, or a rooftop system may need to be redesigned to allow for vents in order to bring the roof up to code. Examples like these abound. Conversely, there are virtually no permitting outcomes that increase system size. 

Delay:  Delay is the greatest threat that permits pose. Because permits are required before the commencement of construction, they are the ultimate gating item. Depending on the economics of the project or the development platform, delay can be an existential threat. Delays have the potential to:

  1. Increase cost to develop: Generally, development capital is the most expensive piece of the capital stack. Developer carrying costs are typically high. Therefore, permitting delays have the potential knock-on effect of making interconnection, customer acquisition, and all other activities more expensive.
  2. Decrease revenue: In markets where incentives are traded (e.g., SREC markets), depending on the curve for such incentives, a project could lose out on the most valuable incentives if it is delayed even by a quarter.
  3. Incur liquidated damages: Offtake agreements, particularly those with sophisticated corporate counterparties, typically have liquidated damages payable to the offtaker for delays.
  4. Take a project to its cliff: Site control agreements, offtake agreements, and interconnection agreements often have cliff dates after which the counterparty may terminate. If permitting delays trigger any of these, the best-case scenario is that more development capital will need to be spent in consideration of extending a cliff. The worst-case scenario is that the project dies.
  5. Lose time value of money: The pipeline remains illiquid longer and monetization is delayed.

Ultimately, permitting is critical to project finance success. It is varies greatly by jurisdiction and generally requires a team of outside consultants. No one ever said commercial solar is easy. 

This concludes the How to Value a Solar Development Pipeline series. We hope you have enjoyed our look at the four pillars of project finance success: revenue streams, interconnection, site control and permitting. Whether you are an investor, developer, offtaker or represent any other link in the solar value chain, may 2019 bring you success.

The content of this article is intended to provide a general guide to the subject matter. Specialist advice should be sought about your specific circumstances.

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