How to Value a Solar Development Pipeline, Part 2

Recently, in a quiet moment between energy transactions, I
pondered: When does a solar project become a solar project?

It’s a philosophical question perhaps. Thankfully (and not
surprisingly) my colleagues in engineering had a few opinions.
While no two opinions were the same (also not surprising), each
opinion did tie to one concept — interconnection.

In this second installment of How to Value a Solar Development
Pipeline (read
part one here
), we will explore the second pillar of project
success: interconnection. 

It is estimated that there are about 150 gigawatts of solar
projects in interconnection queues across the United States.
Compare that to the
12.1 gigawatts
expected to be installed in this year. Clearly a
queue position is not, by itself, an indicator of project success.
Interconnection provides the physical path to deliver power and
imposes the physical constraints of such delivery. Interconnection
also represents one of the critical fixed costs of a project.

These features naturally lend themselves to old-fashioned
wild-cat speculation. While some developers chase power purchase
agreements in search of demand for their power, other developers
seek out ideal localities (or nodes) from which to supply their
power. Skilled developers can do both.

In order to determine a pull-through rate for a project and to
properly value a pipeline, we will explore strategic considerations
related to interconnection development and evaluate the various
stages of the interconnection process. Finally, we’ll consider
trends that may factor into the interconnection process in the
years ahead. 

Interconnection as a strategy

Because interconnection costs do not have a one-to-one
correlation to system size and are even less tied to revenue,
projects with low interconnection costs provide distinct
advantages. Developers with site control and low-cost
interconnection may speculate on these queue positions and wait for
projects to find them, in a sort of
“if-you-interconnect-it,-they-will-come” strategy.

There are plenty of reasons to be optimistic. Module prices and
build costs continues to fall. Corporate offtakers are buying at
record rates and becoming increasingly more comfortable with
contracts for differences (see
Part 1, Pillar 1
– Revenue Streams). Political will at the
municipal and state level continues its steady push to incentivize
renewable development.

The strategy may be sound.  Nevertheless, site control and
interconnection are but two of four pillars of project success.

The value of assets without offtake and permitting ought to
reflect the outstanding binary risks and associated pull-through
rates. For investors with the patience and appetite to warehouse or
hold assets, this style of development may provide long-term,
outsized returns. For investors looking for a quarterly or annual
returns on capital and/or investors with high carrying costs, on
the other hand, this strategy may be too risky. 

Alternatively, investors looking for a platform that does both
(recycles capital with near-term gains and places a few long-term
strategic bets) may consider pipelines that combine varying levels
of interconnection speculation.

Stages of interconnection

Within a single development pipeline, you may encounter projects
of various stages of interconnection development: 

  • Application Submitted
  • Feasibility Study
  • System Impact Study
  • Facilities Study
  • Interconnection Agreement Executed
  • Commencement of Construction of Interconnection Facilities

Each of these stages vary from utility territory to utility
territory.  Nevertheless, there are some technical and economic
commonalities.  A typical progression for territories in the
Pacific North West, South West, North East, Mid-Atlantic and South
East may look like this:

  1. Application Submitted: With a basic level of design and
    engineering, a developer may submit an application to the utility
    to interconnect a system. At this stage, the project is assigned a
    queue position. For congested feeders, this queue position is
    valuable, but it is just the beginning. It is important to
    recognize that, while utilities are governed by public service
    commissions and while interconnecting to the grid may be a matter
    of right where technically feasible, the utility maintains broad
    discretion to determine what is and is not technically feasible.
    The utility’s primary function as an interconnecting authority is
    to ensure the safety and reliability of the grid. That focus will
    shape its responses (and response times).  Upon its review of the
    application, a utility will either suggest a study or (for lucky
    behind-the-meter projects) move straight to the interconnection
    agreement.    
  2. Feasibility Study: At this stage, the utility will do a
    high-level assessment as to whether the project could interconnect
    to the grid. The utility’s engineering team will analyze the
    impact of the generation on existing grid infrastructure and may
    determine where thermal, voltage, or short circuit contributions
    would shape the manner in which the project is to be
    interconnected. This study will inform the scope and contours of a
    system impact study, if necessary.   
  3. System Impact Study: This study will determine if any
    upgrades to the grid (on the utility’s side of the meter) are
    necessary in order to interconnect the project. If upgrades are
    necessary, the utility will provide a cost and schedule estimate
    for any work related to such upgrades. This provides insight into
    the earliest date by which the system may achieve commercial
    operation. With a schedule and costs now in-hand, developers may
    refer to interconnection at this stage as “de-risked.”
  4. Facilities Study: Certain utilities may perform a
    separate study known as a “facilities study.” This study may be
    required or optional and may be performed concurrently or following
    a system impact study.  The purpose of this study is to devise
    equipment lists, technical specifications, a detailed schedule of
    costs, and a granular construction schedule, which will be
    incorporated into the interconnection agreement.
  5. Interconnection Agreement Executed: The project must
    execute the interconnection agreement within a certain period of
    time from receipt of the system impact study and/or facilities
    study, in order to maintain its queue position.  And, generally,
    execution of the interconnection agreement requires a deposit, or
    down payment, on the necessary upgrades. For many developers, this
    stage provides an inflection point for monetization of the
    asset.
  6. Commencement of Construction of Interconnection
    Facilities
    : If utility upgrades are required, the utility will
    likely commence its work upon receipt of the full estimated
    interconnection costs (plus a characteristically conservative
    contingency). For larger utility scale projects, interconnection
    costs may be paid on milestones agreed to by the utility and
    project.

Time and Money

Money – Before System Impact Study, High
Risk

Before the system impact study is completed a developer may have
a view on interconnection costs and the utility may have a view, as
well. A developer may input its view into the financial model and a
utility may express its view on paper. However, until a utility has
performed a full system impact study, interconnection costs are
unknown. The critical features of the system impact study are that
(a) the project pays for the study, (b) the study’s results are
the work-product of an engineer (typically a third-party engineer),
and (c) the utility sets a dollar value for the anticipated costs.
If the developer’s financial model reflects a value for
interconnection costs before the system impact study has been
completed, consider it a hopeful placeholder. 

Time – Before the Interconnection Agreement is
Executed, High Risk

When reviewing any timelines or Gantt charts of a development
pipeline, it is important to ask from where the dates come. These
dates may have their basis in law or tariff. A utility or the
public service commission may set timelines within which the
utility is to review and/or provide responses. Given this statutory
patina, these dates feel reassuringly firm. They are not; they are
aspirational. A utility may fully comply with the timelines, but
the process is iterative at nearly every stage.

A response from a utility may call for a new submission or
clarification and you will suddenly find that the clock has started
over again. Other times, a utility may miss a deadline by a few
days (or weeks). These slips hardly rise to the level of a public
service commission hearing and there is generally no practical
recourse for these slips that does not have the perverse effect of
delaying the project further.

Therefore, it is critical to understand what development
milestones are tied to utility action. Questions to ask include (a)
whether utility action is a gating item for another development
task on the project schedule (e.g. the execution of interconnection
agreement is a condition precedent to application for an
incentive), (b) whether utility delay could present a binary risk
(e.g. tax equity deadlines), or (c) whether utility delay could
present a cost adder (e.g. liquidated damages in the offtake
agreement).

Once an interconnection agreement is executed, the utility may
be contractually bound to act within set timelines. Most typically,
utilities take these contractual obligations seriously. Therefore,
dates based on an executed interconnection agreement are more truly
firm. Before the executed interconnection agreement is in hand,
however, time may not be on your side. 

Trends: Congestion, Storage, and Additional Revenue
Streams

Congestion is of particular concern for distributed generation
projects. Certain regional markets that have fostered renewable
development for many years have high concentrations of systems net
metered to the grid. In these areas, utilities may impose export
restrictions. Even roof top systems now face such restrictions. In
such cases, a storage solution may preserve project value. If
storage is too expensive, developers need to weigh the economics of
downsizing capacity against building beyond the export restriction,
using a combination of reverse power relays and/or inverters that
are programmed to self-curtail energy. 

Developers who choose the latter path will need to convince the
utility of the effectiveness of such a solution. (This is just one
area in which in-house engineering is a critical value-add.) Even
if a utility greenlights the larger capacity, the utility still may
require that a utility-owned reclosure device be installed to
ensure that the system is curtailed when it reaches the export
limit. It is important to model out such curtailment when financing
such a system. 

The race is on to pair storage with solar at scale. It is
important to consider what information was submitted in the
interconnection application and what systems were studied, if the
project has been studied, to determine if adding any particular
type of storage would require a revised application or study.
Either case may result in a loss of queue position.

Solar assets are expected to produce revenue for decades.  It
would be rather short-sighted to assume that the grids to which
they connect will remain static.  As more renewable assets come
online, grid operators will need generation that can be flexible
and respond in a second (or split second) to signals from the
RTO.  Most grids have already monetized such services. 
Historically, this has been assumed to be where “base load”
(e.g. natural gas or nuclear) steps in.  However, a solar project
(especially where paired with storage), can be incredibly flexible
and responsive to the intermittency of other generators on the
grid.  It’s a clean get cleaner sort of world.  Therefore,
early engineering should contemplate flexibility with respect to
the grid and interconnection applications should build in as much
optionality as is commercially reasonable.

Bonus: Note on Interconnection Agreements

Interconnection agreements, by and large, are form agreements.
Their legal terms are concise at best, lacking at worst.
Nevertheless, with certain exceptions, there is generally no
opportunity to negotiate. For investors looking to cover-over any
and all risks associated with the interconnection agreement, it is
important to note that seeking an executed estoppel from a utility
can be a lengthy and fruitless process. If an estoppel is not
forthcoming, the business team ought to find alternative ways to
confirm that the utility is ready to work with the project
company. 

So, if the legal terms are sparse, there is no room to
negotiate, and an estoppel is out of the question, should your
lawyer skip over the “interconnection” folder in the dataroom?
No. 

Legal diligence is necessary to determine the mechanics and
ramifications of milestone dates and cliff dates, particularly with
regard to deposit payments and placed-in-service dates. Your legal
team should also read the interconnection agreement in the context
of the applicable utility tariff. 

Finally, interconnection agreements are peppered with various
obligations during construction and operations, which should be
considered when drafting the various construction contracts and
operation and maintenance agreements for the project. Keep your
lawyer out of this dataroom at your own peril. 

***

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 and
contract disputes.

Joe Song, vice president of project operations at Sol Systems,
also contributed to this piece. 

Source: FS – GreenTech Media
How to Value a Solar Development Pipeline, Part 2