Saturday, January 20, 2018

State Policy Actions to Watch For in 2018, Part 2 [GTM Squared]

from GTM Solar

Friday, January 19, 2018

Storage Is Displacing Peakers. Is That Any Cause for Concern? [GTM Squared]

from GTM Solar

In Key Solar Markets, Fires and Hurricanes Caused a 5% Departure in Solar Irradiance in Q3 2017

Across the contiguous United States, extreme weather conditions dominated the third quarter of 2017 and brought departures from long-term average global horizontal irradiance, a proxy for PV plant production.

GTM has partnered with Vaisala, a company that regularly monitors solar performance across the U.S., to give the solar industry a better understanding of how these weather trends are driving solar performance around the country. This allows the industry to reconcile project performance by comparing it with recent solar conditions and putting this in context with long-term average conditions. The maps published below and the data behind them serve as tools for better understanding how weather impacts solar energy. 

The most recent set of U.S. maps evaluate departures from long-term average solar irradiance conditions in the third quarter of 2017. 

While the industry was focused on the potentially disastrous ITC trade ruling this summer, there were actual weather disasters that plant operators dealing with. Since July 2017, six dramatic weather and climate events impacted the solar industry, including the western U.S. wildfires, drought in the Northern Rockies and Plains, and major Hurricanes Harvey, Irma, and Maria.

Nationally, 2017 tied the record year of 2011 for the record number of billion-dollar weather-related disasters during the January-September period.

For July and August in particular, some states with significant solar deployed such as California, Nevada and Texas saw reductions in solar resource of 5 percent or greater due to weather events such as wildfires and hurricanes. The timing of these events during the high production summer months is particularly significant, since the second half of the year may not be able to offset these losses.

For example, Kern County boasts an installed capacity of 4,881 megawatts of solar power. Vaisala estimates that a 1 percent loss in production in Kern County during a typical single month of peak summer production would equate to over $940,000 in lost revenues for operators across the region. Obviously the impact increases when multiple months are impacted or if the loss in production is great, both of which were the case in Q3 2017.

A question we often get when reviewing these scenarios is: how well do solar resource anomalies correlate to production anomalies? To a first order, power generation is proportional to irradiance in the plane of the array. In the U.S., in the absence of plant performance problems, correlations of GHI anomalies and power production anomalies are typically on the order of 0.9 or greater, based on tests run by Vaisala at sample locations.  

In fact, if your plant performance is not tracking with the GHI anomaly maps presented here, that can be a way to identify either a production problem or a poor quality long-term baseline production assessment. 

For more details, read our month-by-month summaries below to learn how specific weather conditions and anomalous patterns throughout July, August and September may have influenced solar production across your portfolio.

July was the best month of the summer for solar production almost uniformly across the contiguous U.S. As noted by NOAA National Centers for Environmental Information, an upper-level ridge dominated the West, bringing warmer- and drier-than-normal weather to the region and contributing to a prolonged and intense wildfire season. Above-average irradiance and below-average precipitation were also observed for parts of the central and southern Great Plains, Southeast, and northern New England.

On the other end of the scale, below-average irradiance was observed in parts of the Southwest, due to an active monsoon season that kicked into high gear mid-month. As a precursor to the active summer hurricane season, Tropical Storm Emily brought cloud cover and heavy precipitation, soaking Florida, at the end of the month.

Above-average precipitation was also observed in parts of the Northeast and Mid-Atlantic with several intense one-day precipitation events causing significant flooding at numerous locations. The storms left lingering cloud cover which negatively impacted solar performance in addition to the project impacts of flooding.

Similar to July, the synoptic pattern of an upper-level ridge over the western half of the contiguous U.S., and an upper-level trough over the eastern half, persisted during August.

The most striking feature on the August anomaly map is the negative irradiance anomaly affecting most of the South after Hurricane Harvey made landfall. Texas received a record-breaking amount of rain, 1016 mm, resulting in extreme flooding in Texas, and in the Lower Mississippi Valley.

Nearly 68,000 megawatts of generation capacity (almost 25 percent of that capacity being solar), was within Harvey’s path. Most of the solar installations fared as well as could be expected in physical damage. However, the August anomaly map shows how these conditions affected systems in this region, with areas experiencing up to 20 percent lower than normal resource. 

Areas of the West also had lower than normal insolation. Except for isolated locations, this was not due to the local monsoon season but rather increased aerosol emissions from wildfires. Lower than normal irradiance values, 5-10 percent below average in some locations, are directly related to proximity to the wildfire areas, or to being downwind of the smoke plumes.

NASA's Goddard Space Flight Center has posted an excellent simulation of the global aerosol circulation pattern for August 2017. In the NASA animation, you can clearly see that the areas affected by the smoke plumes from the Western wildfires are co-located with the areas of negative irradiance anomalies shown on the map.


The dramatic East-West split down the country was not related to politics, but rather an upper-level circulation pattern that underwent a significant shift over the contiguous U.S. at mid-month. This upper-level shift also affected the temperature anomaly pattern across the U.S. during September. The first half of the month saw higher than normal temperatures affecting the Western contiguous U.S. and cooler than normal temperature affecting the Eastern portion. As the upper-level circulation switched, so too did the temperature anomaly.  

Numerous low pressure systems moving in the western trough brought precipitation to much of the West and Plains during the last half of the month. The increased rainfall helped to suppress wildfires, but the increased cloud cover continued the low solar resource trend across the region, resulting in the negative irradiance anomalies shown on the map September map.

September was an extremely active hurricane month for the North Atlantic Basin with five hurricanes -- four of which were major hurricanes. Hurricanes Irma and Maria brought rain and devastation to parts of the U.S. but the cloudy conditions did not linger in the same way they did with Hurricane Harvey, at least in the contiguous U.S. Hurricane Irma devastated parts of Puerto Rico, the U.S. Virgin Islands and Florida. Then Hurricane Maria delivered a second punch, causing unprecedented impacts on Puerto Rico and the U.S. Virgin Islands.

The Solar Foundation is currently accepting donations for solar equipment and expertise to help rebuild the Puerto Rico grid and bring power back to critical services. If you’re interested, please consider donating.

from GTM Solar

Thursday, January 18, 2018

New Business Models Gain Strength With Renewed Interest in Microgrids

Increased confidence in how to generate revenue from microgrids, beyond reliability and resilience, is contributing to the rise of third-party and mixed ownership models.

With third-party and mixed ownership, a new business model emerged: the microgrid-as-a-service (MaaS) or reliability-as-a-service. MaaS can eliminate the historical need for end users to contribute upfront costs on their own, opening up a new market for customers who previously would not have considered a microgrid due to financial barriers.

In 2017, third-party owned microgrids accounted for 46 percent of new microgrid projects, a notable shift away from majority end-user ownership in previous years. End users still comprise a majority of the U.S. microgrid market, owning 83 percent of all operational microgrid projects and 63 percent of capacity. MaaS could be a good option for customers that are more interested in low-cost reliability over potential financial gains from distributed energy resources (DERs).

A desire for increased reliability and resilience can play a major role in the origination of these projects -- and with good reason. Microgrids in Florida, Texas and California proved themselves during multiple hurricanes and wildfires in 2017. Journalists, utilities, regulators and even U.S. Congress members have extolled the possibilities for microgrid projects to dampen or eradicate the negative effects of future natural disasters.

However, there is no clear mechanism to translate public interest in microgrids into new projects. Post-Superstorm Sandy, even with state funding, projects must still overcome regulatory hurdles associated with community microgrids and a lack of capital to cover the additional costs associated with deploying microgrid solutions. Formulating a third-party or multi-stakeholder ownership model for a microgrid project can pave a path through both regulatory and financial barriers, even with the increased legal costs that come with a more complex ownership arrangement.

MaaS models vary. In some, investors cover project costs, including design, permitting, finance, construction and operations and maintenance in exchange for receiving value streams associated with selling services to the grid when the microgrid is not in island mode. In these models, the end user receives reliable backup power at a significantly reduced price or in some cases for free. In other models, the end user also gets the right to purchase power from the on-site DERs through a power-purchase agreement (PPA).

It is the emergence of new business models, such as MaaS, that will really help open the microgrid market to individual businesses and entities that are unable to provide the upfront capital outlays required for a microgrid project.

Other contributing factors can drive growth in the U.S. microgrid market, including:

  • Heightened customer demand resulting from recent severe weather and state incentive programs
  • Continued technological maturity
  • Decreasing price of distributed generation driving project economics forward

We predict the U.S. microgrid market capacity could double to 6.5 gigawatts by 2022. The market will continue to diversify, adding multi-stakeholder community microgrids across more regions, with continued growth in the commercial market given new financing structures.


Colleen Metelitsa is the lead author of GTM Research's recent U.S. Microgrids 2017: Market Drivers, Analysis and Forecast report. Learn more about the report's contents and findings here.

from GTM Solar

Gridco Shuts Down Its Digital Grid Controls Business

Gridco Systems, one of a handful of startups building power electronics devices that can manage electricity fluctuations and disturbances at the distribution grid level, has ceased operations and is selling its assets to satisfy creditors. 

It’s not that its technology didn’t work -- it does, according to multiple pilot projects with utilities including Duke Energy, Hawaiian Electric, California’s Sacramento Municipal Utility District, and Ontario, Canada’s Greater Sudbury Hydro. Gridco’s in-line power regulators (IPRs) have stabilized solar-driven voltage surges, hit their set points for voltage and reactive power, and otherwise demonstrated a previously unattained level of control over the distribution grid. 

But utilities have failed so far to expand their use of distribution grid-level power electronics much beyond the pilot phase, leaving Gridco with little opportunity to grow to the scale necessary to maintain its operations on the strength of its own revenues. 

“Though we were able to successfully prove Gridco’s technology as best-in-class for use in utility-scale volt/VAR optimization programs, the VVO market did not actualize quickly enough for us to achieve critical mass and financial self-sustainability,” said CEO Naimish Patel, in a recent interview. 

Gridco, which raised $54 million from investors including General Catalyst, Lux Capital and North Bridge Venture Partners, sought multiple fundraising and strategic options through the course of 2017, he said. But late in the year, as the remaining options failed to materialize, the company decided to close on Dec. 31. Gridco’s website now shows only this information, and the phone number of Verdolino & Lowey, the firm hired to liquidate Gridco’s assets “to the benefit of our creditors.”

GTM Research had predicted a $320 million U.S. market by 2017 for these kinds of devices. But as Ben Kellison, director of grid research at GTM Research, noted, "the utility-owned distribution power electronics market has been much slower to develop than GTM Research and much of the industry has expected.”  

Gridco has several competitors in this still-nascent field, including Varentec, GridBridge, Apparent Energy, Faraday Grid and others still in stealth mode. Power electronics serving the higher-voltage realms of the grid are already a significant business for ABB and other grid giants, and startup Smart Wires has devices to manage power flows on the transmission grid. 

But throughout 2017, GTM Research has tracked only one big deal involving distribution grid power electronics. Xcel Energy’s $612 million smart meter and smart grid rate case last year included plans to purchase 4,350 Varentec devices between 2017 and 2022 to reduce unnecessary over-voltages on distribution circuits. 

One key reason for the market’s slower-than-expected growth is that the key business case -- helping to integrate higher penetrations of distributed solar into distribution grids -- hasn’t become as big a problem for utilities as many had expected, Kellison noted. “As utilities gained more experience with distributed solar, distribution planners and operators have realized that distribution grids are more robust and tolerant of intermittent generation at the edge than most engineers would have thought five years ago,” he said. 

That’s left conservation voltage reduction (CVR) and VVO as the main business case for deploying these kinds of devices today. But here, Gridco and other distributed power electronics providers must contend with competition from companies like Utilidata and DVI, which use grid-tied sensors and smart meters, respectively, to better inform CVR and VVO schemes and devices in the field. 

The slow pace of adoption has put other contenders in the distribution grid power electronics field under financial pressure. Earlier this year, GridBridge was acquired by Ermco, a Tennessee-based distribution transformer manufacturer, for an undisclosed price. 

“Power electronics-based voltage and reactive power control devices will become important as renewable penetration increases,” Kellison said. Once deployed, they can also enhance control over voltage and power quality, as well as analyze and report on the actual waveform of the energy flowing through the lines they’re connected to.

“However, it remains to be seen if most of these devices will be smart inverters at the site of distributed generation or storage, utility-owned and connected to LV transformers, or pole- or pad-mounted devices supporting the medium-voltage grid,” he said. 

Patel noted that Gridco’s existing customers will continue to be able to use its deployed products in “set-and-forget mode,” automatically managing voltage fluctuations and tripping off-line when appropriate. But Gridco’s cloud-hosted management software service will no longer be available to monitor and manage them.

“Though we are disappointed with the outcome, we remain confident as to the value of Gridco’s technology and IP,” both of which are for sale, Patel added. While he wouldn’t comment on prospective buyers for either category of Gridco’s assets, he said he’s optimistic that it will be put to work in the future by “utilities endeavoring to deliver higher energy efficiency and power quality, particularly as consumer adoption of distributed generation and electric vehicles grows.” 

from GTM Solar

Solar Industry Tries to Stop a New 1,000 MW Gas Plant in Michigan

The clean energy industry, while pushing its own products, has ramped up efforts to stop new gas plant construction.

Solar advocates filed comments Friday opposing a new 1,100 megawatt combined cycle gas plant that utility DTE Energy wants to build in St. Clair County, Michigan by 2023. It would replace generation from retiring coal plants, but solar groups say it's not clean enough.

The framing of DTE's analysis distorted the outcome in favor of the large gas plant, wrote Kevin Lucas, director of rate design at the Solar Energy Industries Association (SEIA).

"DTE erroneously assumes that a resource must be dispatchable to be reliable," he argued in the testimony. "This results in the unjustified discounting of a portfolio of distributed assets comprised of solar, wind, energy efficiency and demand response as 'unreliable' and unable to meet DTE’s resource adequacy needs."

The testimony says that DTE used outdated price forecasts for renewables and chose the least efficient system design for solar energy, producing less favorable modeling of a clean energy portfolio. On the other hand, it argues, the utility under-represented the risks associated with the $1 billion gas plant. Vote Solar claims renewable energy alternatives could save DTE customers $339 million to $1.2 billion.

The showdown comes on the heels of an all-source solicitation by Xcel Energy in Colorado, which produed groundbreakingly cheap bids for several combinations of renewables and energy storage. The results raised a question for utilities trying to build new gas plants: have they investigated whether a suite of clean energy technologies could do the same job, even cheaper?

California regulators last week ordered utility PG&E to solicit storage and other distributed assets to replace the reliability duties of three existing gas plants. The groups in Michigan are asking for something similar, but before the plant gets approved.

Necessary or not?

DTE must prove that the gas plant is the "most reasonable and prudent" means of meeting the identified capacity need, which is to replace 1,822 megawatts of coal generation slated for retirement between 2020 and 2030.

The utility argues that to fulfill its reliability obligations, it must build dispatchable capacity.

Lucas, on behalf of SEIA, Vote Solar, the Union of Concerned Scientists and the Environmental Law and Policy Center, counters that the obligation is to meet the Midcontinent Independent System Operator's resource adequacy requirements, which can be done through assets other than dispatchable power plants.

The testimony suggests an alternative portfolio that it says satisfies the reliability requirements: 1,100 megawatts of new solar capacity, 1,100 megawatts of wind, 253 megawatts of demand response and an increase in energy efficiency. (DTE has 71.5 megawatts DC of solar operating currently, according to GTM Research).

Regulators wanted to see alternatives to the proposed plan, but the utility doesn't appear to have considered such portfolios. Instead, it offered a perfunctory comparison between its gas plant and a "no build" scenario, where it does nothing and buys energy and capacity from the markets when it encounters shortfalls. DTE ruled that option out as infeasible.

"They didn’t actually seek bids for something other than a gas plant," said Becky Stanfield, senior director for Western States at Vote Solar. "To me, that’s the most telling sign."

It's hard to know how cost competitive other options would be without taking a moment to examine them. That insight drove California regulators to call for an expedited procurement for distributed alternatives to the proposed Puente gas plant in Oxnard, which would have added 262 megawatts of capacity.

Michigan regulators will have to decide whether they want to see more options on the table.

Finding the right mix

That's not to say that the package proposed by the solar advocates is necessarily the right fit.

Keen readers may have noticed the list of proposed reliability assets lacks any dispatchable generation. That's an intentional omission.

The solar industry groups insist that intermittent solar and wind, plus consumption reductions from efficiency and demand response, can keep the lights on just as well as a baseload gas plant, at a lower price for ratepayers. DTE, based on years of experience, trusts a big gas plant to fire up when it needs a bunch of capacity. 

Setting aside the question of whether the utility appropriately considered alternatives, there's a real debate here about the nature of reliability in a rapidly changing grid.

The solar folks argue that a distributed fleet lowers the risk that an unplanned outage could knock out a major power plant's capacity at a time of high demand; pursuing the portfolio approach avoids a single point of failure.

Then again, this approach has to contend with things like the sun going down, or winds falling slack. Geographical diversity provides some insurance against low production across the fleet, but it doesn't always work.

In Michigan, most of the existing and proposed wind farms sit in the Thumb region, where wind speeds and capacity factors are highest, said Wade Schauer, research director at Wood Mackenzie's Americas Power & Renewables team.

That concentration produces frequent periods of simultaneous high and simultaneous low wind generation in the Michigan and DTE service territory. That's visible in wind generation patterns from the first 10 days of this year in MISO-Central, which includes Michigan.

Wind generated in Michigan's Thumb is prone to simultaneous peaks and troughs of production. (Graphic courtesy of Wood Mackenzie)

Michigan wind generation is much lower on average during the summer than the winter, Schauer added. MISO calculates a 12.6 percent dependable capacity value for wind in the summer, based on its average reliability.

"In reality, again based upon actual historical hourly generation data, there are many instances when it can be much lower than 12.6 percent during high summer demand periods," Schauer said. "Similarly, on those same hot, humid summer days with low wind, air conditioning loads remain high late into the evening when solar falls off to zero."

It's up to the regulators to determine how much or how little dispatchable capacity they want on hand for such moments.

Note the average drop in wind generation during the summer months, when peak capacity will likely be needed. (Graphic courtesy of Wood Mackenzie)

Notably absent from the solar testimony was energy storage, which has stepped up to deliver local reliability elsewhere, and can do so with stored solar or wind energy.

Lithium-ion batteries turn solar and wind power into firmed plants that can deliver peak power on demand. But they also increase the upfront cost compared to standalone solar or wind, and might have muddied the ratepayer savings argument the solar advocates were making.

Storage can be hard to model, because battery costs have been dropping so rapidly and limited pricing data is publicly available. The most reliable way to gauge the cost to ratepayers of storage-backed renewables for grid reliability is a competitive solicitation. That hasn't happened yet in Michigan's case, but it could.

from GTM Solar

A Growing Roster of Startups and Developers Look to De-Risk Commercial Solar

The non-residential solar sector may be the only segment to experience annual growth within the U.S. industry in 2017. That’s a unique position for a sector that’s lagged noticeably behind for years.

As utility-scale and residential solar markets benefited from dropping equipment prices and favorable policies, commercial solar has struggled to get off the ground -- stunting development for an estimated 20 percent of the potential solar market. 

“Compared to residential and utility, commercial is a little behind,” said Michelle Davis, senior solar analyst at GTM Research. “A lot of the problems that typically plague the commercial market have been solved, to a certain extent, in the residential and utility markets. And that’s mostly because of the commercial market being so diverse and localized.”

Compared to residential and utility-scale projects, commercial development can range widely in size and complexity, and depend heavily on state policies.  

“That has left this industry with a dearth of folks that are focused on it,” said Jesse Grossman, CEO and co-founder at solar independent power provider Soltage.

Although the C&I market will likely see 9 percent average growth through 2022, hurdles remain. According to GTM Research, unique challenges in customer acquisition, development, and investment continue to plague the C&I space, even as a growing roster of startups and developers tries to untangle its complexities. 

The long development pipeline

Commercial projects can change hands several times throughout development.

While one local company might acquire a customer and an installation site through referrals or outreach, another may tackle contracting and other late-stage development steps. And another still -- such as an insurance company or YieldCo -- could buy the project in the end, handling long-term ownership and asset management. 

That leads to a development process more complex than a simple transaction between installer and a homeowner or utility. According to Davis, the outcome of all that ownership swapping is simple, “it takes longer to do deals.” 

In a November GTM Research report on commercial asset ownership, Davis noted that a growing number of owners are investigating early-stage development risk and management of projects from start to finish. That allows owners more control in streamlining the process, but requires regional knowledge and increased costs for staff.  

Soltage self-develops and acquires projects at different stages of development. Grossman said this allows the company to control the development trajectory of some projects from start to finish in states where they have expertise, but also work with projects where the early-stage development has already been taken off the table by an initial developer.

"They really complement each other,” said Grossman.

GTM Research projected the company to have the sector's largest relative market share increase last year.

Like the Soltage example suggests, those self-developing owners may grow market share faster than companies acquiring projects later in the development cycle. Companies such as NRG, Soltage, Greenskies and NextEra all self-develop. Davis expects that group to have collectively tripled their 2015 portfolios by the end of 2017. 

Though there seems to be some concrete payoff, it’s unclear how advantageous early-stage involvement is in the long run. “Since owners who self-develop are also experiencing growth from community solar, it remains unproven whether this strategy actually addresses the major challenges in the commercial solar market,” wrote Davis.

According to Grossman, it's likely that project-swapping will continue to be common among developers working in the commercial space and trying to keep transaction costs low for small projects. "There’s no doubt that this industry is consolidating and there are getting to be more streamlined entities," he said. "That said, it is a fairly common business model now for entities to just do development and transfer those assets over to a buyer." 

SEIA has undertaken the formidable project pipeline as well, drafting standardized power purchase agreements and contracts to speed along development. 

"The one that got away"

According to several startups in the space, one barrier to commercial projects trumps all other development hurdles: money.  

“Every C&I developer has a story about the one that got away,” said Jeff McAulay, co-founder at Energetic Insurance. “A project that should be really good, and they couldn’t get the deal because financing fell apart.”

The traditional financing mechanisms that work for utility-scale projects, like power purchase agreements, and residential customers, like loans or third-party leases, haven’t been entirely standardized for a diverse pool of commercial offtakers and developers. 

In part, that's because risk-averse financial institutions want power offtakers to have a credit score that easily allows the bank to quantify risk. Aside from governments and the Fortune 500, few business entities do, or they’re below investment-grade. 

“The beauty of residential is, if you have a FICO score as a residential customer, there is no additional underwriting expense for the bank,” said Ilyas Frenkel, director of growth at Wunder Capital. “Since businesses have a lot of income streams, there hasn’t been a great way for banks to assess risk. They’re basically left in the dark when it comes to solar financing.”

Davis said the easiest way to avoid challenges of customer acquisition and financing is to target "the safest pipeline" of investment-grade customers. But “owners and developers report that the supply of this pipeline is dwindling.” If commercial developers don’t come up with a fix fast, the market may not reach its potential.

There are several workarounds. Soltage's Grossman said he still sees large financial firms “hewing to their traditional investment guidelines,” but small, regional banks who have watched the space develop on a more local level can provide funding streams for focused developers that build relationships.

Another well-known example is Property Assessed Clean Energy (PACE), which enables project financing through property taxes. According to the Department of Energy, in early 2017, 30 states plus Washington, D.C. had commercial PACE legislation and had financed $400 million in projects. 

For a market potentially worth billions, $400 million is only a start. Wunder Capital alone had about $600 million in financing requests in 2017. Frenkel estimates the company could see up to $1.5 billion in projects this year. That's a fraction of what startups building new financial models for C&I development hope for. 

Frenkel calls Wunder Capital the “white label financing arm” for small and medium-sized projects. Through a roster of partners, the company builds a balance sheet to present to the customer at point-of-sale, instead of developers finding loans themselves. 

The money comes from accredited investors that pay a minimum of $1,000, some private equity investors that offer $1 to 5 million, and larger institutional partners such as multinational banks with more to invest. While banks can take three to six months to fund a project, Wunder-backed projects close on average in 61 days.  

Frenkel said the model has proven effective for community projects, traditional commercial projects, and those in the “MUSH Market,” municipalities, universities, schools and hospitals. 

Energetic Insurance, a Sunshot-funded startup founded in 2017, comes at the investment problem from a different angle. This year the firm plans to launch its first product: a credit wrap insurance policy called EneRate that allows unrated offtakers to remove their own credit risk to the insurer. 

“Ultimately we think this is a mis-pricing of risk -- that the market isn’t really moving just because it’s a young market, not because it’s a bad risk,” said McAulay. So far the company is actively working on underwriting deals, but has yet to announce one.  

These innovations represent promise. But if low-risk projects run out before asset owners can get a handle on expanding the market, it could put the industry in a bind. 

“There’s movement in the solar industry and the banking industry, people are getting more comfortable developing and investing in solar for the small commercial sector. But it’s complicated,” said Mike Mendelsohn, senior director of project finance and capital markets at SEIA. “It’s like you take two steps forward and move one step back.”

A community effort 

If anything has been a step forward for C&I, it’s community solar. That space has become the fastest growing area in commercial solar. 

“A lot of developers and owners I speak with say if they are not in the community solar arena, they would like to be,” said Davis. “It helps avoid many of the hurdles I discussed earlier.” 

Community solar projects can be located offsite and feature numerous customers. That makes the deal look less risky.

So far, though, only a few states have gained traction on community solar. It remains concentrated in specific states because of incentive programs and rebates, according to Davis. A large driver of the spike in projects in 2016 and 2017 resulted from demand related to expiring or changing state incentive programs. 

California dominates 63 percent of the commercial market in small projects under 500 kilowatts, and 51 percent of projects between 500 and 1,000 kilowatts. Above 1,000 kilowatts, Massachusetts accounts for 41 percent of projects and California for 26 percent of projects. Arizona, New Jersey and New York also account for a notable portions. Though Minnesota recently emerged as a leader in community solar installations above 1,000 kilowatts, over 90 percent of all commercial projects are still in the five most dominant states. 

Interest in the sector is strengthening. “We’re seeing more and more states getting into the game,” said Frenkel, adding that an increasing number of local and regional residential installers are eyeing untapped opportunities in the space.

Both Frenkel and Mendelsohn said they expect a “long-tail” to follow the early projects and the developers working on them.  

In the meantime, Davis projects a slight drop in projects in 2018. The short-term slump mirrors a slowdown in the rest of the solar industry, according to GTM Research's base case scenario.

A growing crop of projects, driven by falling prices, and more community solar and solar-plus-storage projects, will bring incremental growth after 2019.

Though Mendelsohn said there's no "silver bullet" for commercial sector woes, watchers remain hopeful that barriers will get broken down.

“It doesn’t feel right that this large of a market should be left out of the solar boom,” said McAulay. “I’m a big optimist. I know there are some headwinds, but long-term there is so much value here.”

from GTM Solar