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Ducking The Curves Of The Solar Industry Roller Coaster

Posted by Raj Prabhu

· October 2, 2017

The global solar industry has had quite a ride the last 10 years, but as with any industry, it is the peaks and valleys that make the journey an interesting one. We saw large sums of venture capital (VC) invested into thin-film, CSP, CPV and other would-be usurpers to crystalline silicon’s throne. China asserted itself as a dominant force on the global solar stage and drove the industry toward the next major innovation – finance. No-money-down financing giving rise to third-party lease companies saw billions of dollars flow into solar, but nothing compared to the dramatic rise and precipitous fall of SunEdison and the yieldco model. Mercom Capital Group has been following the money in the sector since 2007, and we’re proud to share our view of the voyage this past decade, with an eye toward where solar is headed.

Raj Prabhu

PV technology wars

The evolution of solar over the past decade began with the raw material cost-reduction phase between 2007 and 2011, with a large amount of venture/private equity funding going into developing alternative technologies to crystalline silicon due to polysilicon prices reaching up to $300-$400/ton at the time. Thin-film, CSP and CPV technologies received a deluge of funding, but most failed when China began to massively expand manufacturing with generous help from Chinese banks, which caused a huge oversupply and eventual price crash that brought polysilicon prices back down from $300-$400/ton to $15/ton and c-Si module prices down from $4/W to $0.65/W by the end of 2012. The next phase saw a flurry of trade disputes that were kicked off as a result of the Chinese oversupply situation, which led to hundreds of bankruptcies.

One thing that remained consistent through all of this turmoil in the global solar industry was demand growth, with a compound annual growth rate of 56% between 2007 and 2013, and it has continued to grow every year since.

Chinese aggression

China saw massive potential in solar and played to its strength by setting up a low-cost manufacturing base with a strong supply chain. But what turned the tables was the decision by the Chinese government to let government-owned banks lend more than $50 billion to domestic manufacturers at subsidized rates. With unlimited capital available at a time when the U.S. was in a recession, Chinese manufacturers were able to bring the costs of components down rapidly, effectively killing other technology start-ups focused on CIGS, amorphous silicon, CSP and CPV, among others.

With air pollution becoming a serious threat in the second quarter of 2014 (Q2’14), China upped the ante and set a very aggressive goal of installing 70,000 MW of solar energy by 2017. That was great news for a global industry that had seen markets rise and fall and is always looking for the next growth hot spot. After taking over from Germany as the largest installer of solar in the world, China looked to stay on top for the next four to five years. China, alone, accounted for 30% of all global solar installations in 2015!

China’s strong policy support encouraged domestic solar demand and an emphasis on distributed generation. The Chinese government’s decision to let Shanghai Chaori Solar Energy Science & Technology default on its bond issue showed that the government was serious about not bailing out companies that didn’t fit the strict manufacturing criteria. That was another big positive for the sector, which was used to seeing billions in credit go from Chinese state banks to Chinese manufacturers – a trend that eventually led to massive overcapacity, price crashes and bankruptcies around the world. In a strategic shift, Chinese state-owned banks started providing more credit to downstream project development in 2014.

Rise up with zero down

Meanwhile, in the U.S., residential and commercial solar funds raised money at a torrid pace with over $700 million in VC funding in 2014 as the third-party-owned model became the main driver of residential solar installations in the U.S. before spreading to other markets.

In Q1’14, SolarCity announced its second securitization deal of $70 million in solar asset-backed notes carrying an interest rate of just 4.59% – at the time, one of the lowest out there – then followed that up in Q2’14 with another for $70.2 million at the same rate. Things really ramped up in Q3 when SolarCity announced its third securitization deal of the year, this time for $201.5 million priced at 4.32% interest. 2015 was a record year for dollars raised in residential and commercial solar project funds, and from 2009 to Q1’16, third-party financing firms (led by SolarCity) raised more than $18 billion.

In 2016, policy uncertainty surrounding net metering hurt most rooftop installers, especially public rooftop companies that had fallen out of favor with investors. The stocks of SolarCity, Sunrun and Vivint Solar were all down more than 50%. Tesla then stepped in and purchased SolarCity to take advantage of the lower SolarCity stock price and possibly save the solar company from debt and other problems. On the positive side, solar installations continued to grow unabated, especially in Asia and the U.S. Solar became the fastest-growing new energy source, along with wind, in many markets around the world.

2017’s final story is yet to be told, but the year started with residential and commercial solar fund announcements dropping significantly, down to Q4’15 levels. The rooftop market has been moving from leases to loans because loans are getting cheaper and more flexible. There is a significant transformation going on in the U.S. rooftop segment, which means fund announcements will likely decline further. SolarCity (now part of Tesla) has been the largest recipient of residential and commercial funds, and it is unclear whether it will report any further fundraising.

Smaller installers that did not have access to tax equity funds are now able to partner with loan providers just like mortgage providers or car dealerships. Larger installers like SolarCity, Sungevity and others have been struggling as their customer-acquisition costs have been much higher compared to smaller local installers and roofers. Any gains in economies of scale by these large firms have been nullified by higher customer-acquisition costs. Most are in trouble, and many are in restructuring mode. Suniva announced significant layoffs and Sungevity declared bankruptcy in Q1’17, but only recently, the U.S. International Trade Commission voted 4-0 to proceed with the Suniva/SolarWorld Section 201 trade case, with a final remedy recommendation due by Nov. 13. If Suniva gets its initially requested minimum import price of $0.78/W on crystalline silicon modules, the impact on demand will be significant.

The yieldco play

Yieldcos, which are publicly traded companies that are created to own operating projects with predictable cashflow, became a hot investment area in 2014.

In Q1’14, third-party finance companies began leading in the development of innovative financial solutions that helped bring the cost of capital down. SunEdison announced initial capitalization of its yieldco with a $250 million facility. The following quarter, Abengoa Yield raised about $829 million in its initial public offering (IPO) that signaled a slew of yieldco announcements (four of the eight IPOs that year). Yieldcos need to expand their portfolio of generating assets in order to increase dividend growth. So, as more yieldcos went public in 2015, the expectation was for solar project acquisition activity to increase exponentially and create huge demand for quality solar projects worldwide.

Solar stocks made a complete U-turn in 2015. As oil prices slid, investors incorrectly drew correlation between the drop in oil prices and solar. Yieldcos were particularly hard hit, with some stocks losing more than 50% of their market value in just three months. After SunEdison’s planned acquisition of Vivint Solar, markets began to question its pace of acquisitions, whether Vivint was a strategic fit, and the over-leveraged situation SunEdison was in.

Yieldcos were formed to access capital at lower costs and were supposed to have a low-risk profile with predictable and growing cashflows. But SunEdison began operating like a high-growth company and made investors skeptical of all solar yieldcos. By Q1’16, SunEdison’s collapse and Abengoa’s bankruptcy had a negative effect on the overall solar market. In July 2015, SunEdison had a market capitalization of about $10 billion. It had plummeted to ~$50 million by April 2016. SunEdison overplayed its hand by accumulating more than $10 billion in debt in a relatively short time and creating not one, but two, yieldcos. SunEdison’s bankruptcy in April 2016 added to the overall investor skepticism of yieldcos and solar public companies, in general. In Q1’17, SunEdison’s two yieldcos finally entered deals to break away from their sponsor and be acquired by Brookfield Asset Management (TerraForm Global for about $1.2 billion and TerraForm Power – a 51% stake – for $622 million).

As the yieldco model collapsed, solar securitization deals have picked up steam, with over $1 billion to-date. Once interest rates start trending north, we will see other financial innovations crop up.

ITC extension

Though it ended up being extended, the pending expiration of the 30% federal investment tax credit (ITC) at the end of 2016 initiated a rush by companies to raise funds and install projects to take advantage of this incentive in the U.S. The pace picked up in the first half of 2015, with $3.8 billion raised globally compared to $4 billion in all of 2014.

After the extension of the ITC, the industry overall was able to look forward to a five-year period of stability, and the U.S. became the second-largest solar market in the world, ahead of Japan. The extension was touted as a cure-all and was expected to propel the sector to new heights, but in Q2’16, total corporate funding into the global solar sector actually fell by about 41% to $1.7 billion from $2.8 billion in Q1’16. Year-over-year, the fall was even steeper, down 71% from the $5.9 billion raised in Q2’15.

Donald Trump’s win in the U.S. general election had clean energy markets speculating what the implications would be for the sector. The president has already committed to pulling the U.S. out of the Paris Climate Agreement (nonbinding). Most nations will go ahead with or without the U.S. based on the implications of climate change in their own countries. The threat of a Trump presidency to the ITC is likely to be minimal, though. A substantial number of large-scale projects were postponed from 2016 to 2017 due to the absence of an impending ITC deadline. Residential installations slowed down due to net metering fights in several states, and larger installers found it difficult to reach profitability as customer-acquisition costs remained stubbornly high.

Conclusion

The financial markets are looking for solar companies to stop chasing market share and finally make profits and lower debt. That could help solar companies get healthy and start tapping the capital markets again, but in the end, profitability will be the key.

Raj Prabhu is co-founder and CEO of Mercom Capital Group, a global clean energy communications and consulting firm.

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The Emergence And Growth Of Community Solar

Posted by Paul Spencer

· October 2, 2017

From an industry lifecycle perspective, we expected the evolution of community solar to be relatively fast. From introducing a new model of distributed generation designed to serve an expanding market vastly larger than rooftop solar could address, to attaining effective scale through ubiquitous utility and consumer participation, we projected a steep curve and an apex extending into the next few decades and beyond.

Community solar has indeed come a long way in a very short period, serving as a source of both excitement and challenge for the myriad participants that have taken a stake in its surging growth. Ten years ago, community solar was barely an idea, far from a robust business model. A few local community groups and rural utilities experimented with small-scale shared energy, but nothing worthy of exporting across markets, utility types and regulatory structures. Jump to today, and community solar is one of the fastest-growing segments of the U.S. solar industry, with more than 100 programs in 26 states and more than one-third of the country (18 states) with legislation enabling shared solar. It has gained a significant foothold in the U.S. solar market, and all signs indicate the momentum will continue accelerating.

Yet, community solar’s rise and maturation has also proven slower, or at least more gradual, than what Clean Energy Collective (CEC), at the time a solar start-up in western Colorado, envisioned in 2009 while designing what was considered one of the nation’s first community-owned solar models. The process has proven complex, the number of players limited, and enabling legislative and regulatory development slow and cautious.

But time and tenacity, as they do, have illuminated the path forward. We have reached a point where we know what works with regard to financial structures, project size, customer participation, legislative parameters, and finance. The focus has shifted to implementing each of them in a way that will allow the market to address the 100 million customers that can benefit from community solar.

Proving the concept

Innovation and bold action launched the U.S. community solar industry and have served as hallmarks throughout its expansion. Colorado initiated the movement by being first to enact legislation spawning utility and consumer participation in off-site renewable projects. The first community-owned solar facility was launched with Holy Cross Energy, a rural cooperative in western Colorado (interconnected June 2010). It was only 328 panels, purchased by 19 individuals and sold by word-of-mouth.

Since then, the term “community solar” has been applied to many variations on the concept. In general terms, community solar allows consumers to offset part or all of their electricity bills by securing bill credits, through panel ownership or subscription, corresponding to the electricity produced in a 500 kW to 10 MW solar project hosted in their utility territory. Economies of scale allow programs to be offered to customers at lower costs than individual systems and (in most cases) their retail electricity rate. This tangible consumer benefit, a predictable and meaningful financial payback for a broad base of utility ratepayers, distinguishes community solar from other “green” programs like group purchasing, green power programs, crowdfunding, or group investing schemes that have emerged.

As Colorado proved that the concept was viable, there was a buildup of pilot examples and unintended experiments with shared net energy metering (NEM). Other states like Minnesota, Massachusetts and California set out to demonstrate that the market could work at scale. Policymakers defined program participants, capacity and NEM policies, customer eligibility, off-take sizes, subscription terms and limits, and ownership. While some of these programs have been successful, some have not. Policymakers were discovering best practices and tailoring policies and programs to meet the specific needs of customers, utilities and developers.

A shift in perspective

From the beginning, we knew utility participation and cooperation were vital to growing community solar programs, whether this growth was driven and owned by the utilities themselves, the growth happened through a utility/third-party partnership, or it was completely third-party driven. Utility culture has generally been characterized as resistant to outside influences and slow to embrace innovation, and as such, the utilities were on high alert to the potential threats and challenges that community solar programs presented.

Developer pitches focused on the “bright idea” of community shared solar and how it could cost-effectively serve customer demand for renewables and support renewable energy mandates. Not surprisingly, early utility adopters were enthusiastic cooperatives eager to satiate enviro-minded members and public utilities supporting city-wide greening initiatives.

The rapid onset of distributed energy resources (DER) and broadening accessibility to affordable renewables provoked a shift in both perspective and strategy for many utilities, which approached the oncoming wave more as a source of opportunity rather than an obligation. Under greater pressure to evolve, get cleaner, and offer more options to customers, utilities were now motivated to understand how to best integrate distributed generation into the grid and create sustainable business models around their imminent growth. Community solar provided utilities with a solution-set that consumers actually desired.

Utilities now look at community solar programs as a strategic middle-ground solution, blending the broad appeal of behind-the-meter residential solar programs and the economies of utility-scale projects while minimizing complications, resources, and expense. More than 150 U.S. utilities are operating or developing a voluntary community solar program today. While rural electric co-ops and public power utilities will continue growing their community solar programs, many of the U.S.’ largest investor-owned utilities (Duke Energy, Con Edison, Xcel Energy and SCE&G) have integrated community solar as part of their renewables strategy, which in turn, is driving program scale to newer heights, leveraging greater cost efficiencies, and serving exponentially more customers.

Follow the money

Market development is fueled by capital. Like any industry, it is the oxygen most vital to a market’s health or demise. The expectation was that traditional solar financing – construction financing, debt for leveraged transactions, tax equity investments, and working lines of credit – would adapt to the community solar market. Yet, securing capital partners is complicated by the variables underlying community solar programing, such as multiple customer profiles, unique technology requirements and maintaining full subscribership. In community solar’s early days, CEC relied mostly on small, regional banks that had knowledge of, and comfort with, lending to members of the community.

As the market began to scale, state-level policies expanded; the federal investment tax credit (ITC) was extended; and technology emerged that delivered efficiencies in customer acquisition and fulfillment, billing integration, and project management. Non-residential entities with investment-grade credit were jumping in, and actionable data regarding program performance and risk became more available.

Consequently, there has been a slow-but-measured migration from boutique investors to the mainstream financial community. Bigger financial players have become more familiar and comfortable with community solar as its own asset class. They are willing and capable of a deeper, multidimensional dialogue addressing the specific mechanisms for market development and deployment. Particularly in the last year, we have seen large institutions positioning community solar as the next place to put low-risk capital, given that utility-scale development fueled by previous uncertainty over extension of the 30% federal ITC has now slowed and rooftop solar has stalled amid customer-acquisition challenges and a focus on profit over expansion. They are interested in long, optimized assets and predictable cashflows, and they want to know how to best get gigawatts into the ground.

More capital coming into the market as a whole will accelerate growth. Community banks are still good partners because they have good costs of capital, but legal lending limits prevent major participation. For example, a $30 million project fund equates to 10 MW to 15 MW of capacity, while CEC’s short-term development pipeline alone is several times that.

The balancing act

Paralleling development of the investment infrastructure has been a progression of product strategies and customer mix. In the first programs, participants purchased individual panels and owned the asset in perpetuity. Such models deliver the best financial benefit for customers and best chance of financing for developers, but requiring upfront payment narrows the target audience. Pay-as-you-go and subscription programs were introduced as alternatives to broaden the customer base. Myriad versions of these themes are in play today, varying by state, utility and program provider.

These offers illustrate the careful balancing act that community solar innovators grapple with daily: The desire to expand financing options is at odds with the desire to create more flexible offers for customers. Financiers generally need a program to offer more stability and less risk, thus resulting in less flexibility and increasing contract rigidity for customers, which is a harder product for developers to sell.

Achieving scale rests on finding the right balance.

In the last year or two, we’ve seen commercial and industrial companies and institutional organizations like schools and municipalities employ community solar as an efficient, cost-effective way for supporting renewable energy, lowering energy operating costs, engaging employees, differentiating their brand and demonstrating leadership in their communities. Leveraging these creditworthy customers as anchor tenants reduces transactional complexity and lowers risk for the overall customer base.

A growing voice

Market development is also fueled by data. The community solar industry and nearly every stakeholder has benefited from a rich body of research by the U.S. Department of Energy, the National Renewable Energy Laboratory, the Rocky Mountain Institute, GTM Research, Advanced Energy Economy, The Solar Foundation, and others. Trade groups like the Solar Energy Industries Association, Smart Electric Power Alliance, National Rural Electric Cooperative Association, and American Public Power Association have been instrumental in the industry’s development. Community solar is also now regularly addressed by the National Association of Regulatory Utilities Commissioners, as well as by numerous consulting and advisory companies.

One of the most significant milestones for the industry was the creation of its own trade association, the Coalition for Community Solar Access (CCSA). There was a need for a unique voice for the industry, and with a very modest investment, its members, representing project developers, PV manufacturers, energy generators, and service providers, gained a front-row seat in discussions on policy and regulatory efforts impacting the industry and their businesses. CCSA is the right vehicle to magnify our collective efforts, and the next step is getting more support, larger investments and a louder voice.

What next?

Business innovation, in its most classic sense, is responsible for community solar’s evolution, creating new opportunity and value in a rapidly changing climate. We approach the industry’s growth phase with a lot more knowledge of what works and what is needed, and we’re getting savvier at doing those things well.

We’re also gaining a greater understanding of strategically siting community solar projects to fill load pockets, leveraging a project’s ability to increase grid stability and bundling community solar with other offerings to increase customer participation and value. Enterprise-level software has opened the gates to greater efficiencies, lower costs and less risk. And steps toward more standardization in processes, policy, and technology will accelerate integration of multi-megawatt projects and gigawatt portfolios.

We no longer need pilot programs to understand the mechanics of successful programs. Achieving greater regulatory certainty will do much for a constantly changing energy landscape. Sooner than later, deliberation regarding NEM and value of solar will conclude in a simple compensation structure that is agreeable to enough people.

As project developers and community solar solution providers, we can no longer assume utilities’ motives, needs, processes and priorities, or that they are the same as the utility next door. We must determine their individual needs and provide the appropriate products and services to meet them. Conversely, utilities must pursue new business models – whether partnering with vendors or owning the resources outright – to fully integrate new DER innovations and satisfy customers.

In the short term, diverse market forces will continue to shape the industry, drive new renewable capacity and create real value in the form of consumer savings and greenhouse-gas reductions. In the medium term, community shared renewables will likely include more generation from sources other than solar PV. In the de-regulated markets, we may see community renewables blur the lines with retail power providers, becoming a true (direct) power source instead of a virtual one.

The future is about building upon the successes we worked so hard to achieve. The community solar industry is young, but it has a sturdy foundation and is just beginning to hit its stride.

Paul Spencer is founder and CEO of community solar developer Clean Energy Collective.

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A Decade Of Evolution In U.S. Project Financing

Posted by David Burton, Nadav Klugman & Jeffrey Davis

· October 2, 2017

The solar industry has undergone a tremendous evolution in the course of the last decade. Below we outline some of the more notable developments, with a focus on project financing in the U.S.

In 2007, the largest solar photovoltaic project in the world was an 11 MW project in Portugal, called Serpa, that cost EUR 58 million to build. Today, the largest solar PV project in the world is Tengger Desert Solar Park in China and is 1,500 MW, or more than 100 times the capacity of Serpa, and the cost of building a solar project is a fraction of what it was a decade ago.

In 2007, manufacturers of thin-film solar and manufacturers of crystalline silicon solar were battling to see which would be the predominant technology. Today, there are more manufacturers of crystalline modules than thin film and more projects using crystalline modules than thin film; however, First Solar appears to have found success with rigid thin-film modules.

In 2007, terms like “resi,” “C&I,” “DG” and “community solar,” which are now ubiquitous in our industry, were unknown to most energy financiers.

Furthermore, the U.S. tax equity market for solar in 2007 was nascent at best. The leading structure was the sale-leaseback. Investors were starting to experiment with early forms of a flip partnership that lagged in sophistication behind the structuring being used for wind project tax equity. If a solar company called an investment bank looking for financing, the call was directed to the venture capital desk.

Today, the partnership flip has far surpassed the sale-leaseback in use in the U.S. solar industry. In addition, there are now two distinct partnership flip structures for solar: internal rate of return-based flips that resemble those used by the wind industry and time-based flips. In addition, there are niche structures like pass-through leases and inverted leases, and in 2007, those had not yet migrated on a meaningful level to solar from the historic tax credit industry.

The investment tax credit (ITC) for which solar projects qualify has also changed in the last decade. In 2007, the ITC was still an alternative minimum tax “preference.” That meant companies subject to the “AMT” had to carry the credit forward until the company generated enough taxable income relative to its tax attributes to exit AMT. The AMT problem was fixed by the Emergency Economic Stabilization Act of 2008. This legislation made solar more attractive to tax equity investors with other significant tax attributes on their tax returns.

Further, in 2007, if you proposed that Congress should allow solar project owners to trade a project’s ITC for an equal cash payment from the U.S. Department of the Treasury, your knowledge of the political landscape of Washington would have been seriously questioned. In response to the financial crisis, that is what Congress did with the Section 1603 cash grant program enacted in the American Recovery & Reinvestment Tax Act of 2009.

As the solar industry evolved, residential solar exploded. Residential solar started with companies offering homeowners leases of rooftop solar. Power purchase agreements (PPAs) were added to the mix to provide homeowners with a more flexible financing option. The basic PPA structure was then supplemented with a prepaid PPA structure for homeowners flush with cash.

In 2017, loans and cash sales are becoming more popular in the residential market segment, and state programs like the Green Bank in Connecticut or Property Assessed Clean Energy (PACE) programs in states like California and Florida offer homeowners financing at low rates. Debt to finance pools of residential loans, PPAs and leases has been provided in many forms.

Furthermore, in some jurisdictions, due to the advent of community solar, consumers do not even need to own a home or business location to adopt solar. The leading states for community solar are Massachusetts, Minnesota, New York and Vermont, with South Carolina trying to lead the South. Community solar arrangements vary significantly based on the local regulatory regime.

Community solar requires remote net metering rules to be in place. That is, a consumer must be able to earn a credit toward her electric bill for her residence or business, whether such residence or business location is rented or owned, based on electric generation at a utility-scale solar project that may be miles away. For the billing arrangements to work, the utility-scale project must be in the same utility district as the consumer’s residence or business location.

Community solar, depending on the regulatory regime, offers consumers similar financing options as traditional residential rooftop solar: (i) purchase of an undivided interest in the project, with the homeowner claiming a 30% tax credit under Section 25D of the Internal Revenue Code as described in Internal Revenue Service (IRS) Private Letter Ruling 201536017; (ii) a fixed-price lease of an undivided interest, in which the consumer makes a fixed monthly payment in exchange for all of the production from her portion of the project; and (iii) a net metering credit purchase agreement under which the consumer pays for each kilowatt-hour produced by her portion of the project in a particular month. Despite the variation and complexity, developers of community have obtained both tax equity and term debt financing from a variety of sources.

As community solar projects further the goal of democratization of solar, our industry is still left with the criticism that solar is an intermittent resource that is unavailable at night or during periods of cloud cover. To address this challenge, our industry is pursuing energy storage solutions.

Storage is a market segment with tremendous potential for at least three reasons. First, as we saw with respect to solar modules this past decade, efficiency of storage appears to be improving, while costs are declining.

Second, many utilities are recognizing the reliability benefits provided by storage. For instance, Southern California Edison has entered into resource adequacy purchase agreements with 15-year terms for storage under which it pays independent power providers for “capacity attributes,” which are resource adequacy attributes (e.g., the ability to provide power to the grid at key times) identified by the California Public Utilities Commission or California Independent System Operator. Large consumers of energy are incorporating storage to reduce their peak demand charges, sharing the cost savings with storage developers. Still, others are using storage to provide frequency response services.

Third, the IRS ruled, most recently in Private Letter Ruling 201444025, that storage owned by the same taxpayer as a solar project qualifies for the ITC to the extent the storage is at least 75% charged by the solar project – although less than 100% solar charging does result in a proportionate reduction for the ITC for the solar equipment. For instance, 80% solar charging would mean 24% (i.e., 80% multiplied by 30%) of the eligible basis of the storage project would qualify for the ITC.

The IRS announced in Notice 2015-70 that it is going to overhaul the regulations that define ITC eligibility, which were last updated in the 1980s. That overhaul could affect the rules for storage, but we hope any departures in the new regulations from the storage private letter rulings are to remove administratively burdensome requirements, such as the solar charging percentage having to be tested each year during the five-year recapture period, without altering the principle that storage charged with solar qualifies for the ITC.

Some of the fate of the U.S. solar industry over the next six years is dependent on pending IRS guidance as to what it means to “begin construction” of a solar project. This guidance will be important, as it determines what level of the ITC a solar project will qualify for after 2019 as a result of the ratcheting down of the ITC enacted in the Consolidated Appropriations Act of 2016. The IRS is working on that guidance but is taking its time, as it is only relevant starting in 2019 because projects must begin construction by the end of 2019 to qualify for a full 30% ITC. Then, projects that begin construction in 2020 are eligible for a 24% ITC; projects that begin construction in 2021 are eligible for a 22% ITC; and after 2021, current law provides for a permanent 10% ITC. However, regardless of when a project began construction, it must be placed in service (i.e., be operational) by the end of 2023 to qualify for more than a 10% ITC. The IRS issued relatively generous guidance to define beginning construction for wind projects. Our industry is optimistic that the guidance for solar will be no less generous.

The solar industry evolved to overcome the obstacles it faced a decade ago. Given our industry’s ingenuity and drive, it appears likely that it will continue to evolve to successfully address the challenges of today and the coming years.

David Burton, Nadav Klugman and Jeffrey Davis are partners at law firm Mayer Brown.

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What The Watt: Ten Years Of Solar Growing And Growing Up

Posted by Katherine Gensler & Justin Baca

· October 2, 2017

Way back when the organization had a website that looked like it was created by a high-schooler with a copy of Dreamweaver, 2008, we both started working at the Solar Energy Industries Association (SEIA): Katherine in February and Justin in July.

Justin Baca

Katherine Gensler

The U.S. industry was still small but starting to pick up steam, as entrepreneurs took notice of the 30% federal investment tax credit (ITC) enacted as part of the Energy Policy Act of 2005, the California Solar Initiative, and the first compliance years for key states’ renewable portfolio standards.

The future looked bright for solar; SEIA soon upgraded to a new, professional website… and then the economy tanked. While this caused a bit of a dark cloud over the industry, a silver lining remained. The Emergency Economic Stabilization Act extended the ITC for eight years, and thus, by October 2008, we had completed our first run on the “solar coaster.”

Just to be clear, SEIA started 43 years ago, and we are sure those who preceded us had their own runs on the older clackety-clack solar coasters of their time, but in recognition of the 10-year run of the print edition of Solar Industry magazine, we wanted to take a trip back in time over the last decade.

Many in the industry lament the frequent ups and downs of the solar market, but each dip, turn and climb has been a learning and growing experience for our industry and for the policymakers who regulate it.

In 2008, many in the industry came from backgrounds in technology, finance and construction (and that’s still the case today), but relatively few were steeped in the arcane details of highly regulated electricity markets. And the industry was growing so quickly that, mathematically, it was impossible for most people to have more than one or two years of solar experience.

Solar was new to policymakers, too. Most places just hadn’t seen much of it yet. The U.S. added 350 MW-DC of solar capacity in 2008 and supplied less than one-tenth of 1% of U.S. electricity.

This combination of new professionals, new technology and rapidly increasing volume made for an exciting, albeit sometimes rocky, start to our solar careers.

Yet here we are in 2017, the year after adding 15,000 MW-DC of PV, with solar being the single-largest source of new generating capacity in the country. Solar energy now supplies more than 10% of California’s electric consumption and about 1.5% of our nation’s electricity. By 2020, that percentage is expected to soar to 3.5%. To put that in context, that’s an increase of more than 3,000% in just a decade.

So, how did we get here? Well, to start, this industry is fiercely competitive. While solar companies clearly compete among each other, increasingly, the industry realizes that its future lies in the larger electricity market and competing with incumbent electricity technologies. And, there, the competition is even tougher. We’ve seen the carnage as solar companies test different business models or technologies, but the companies that thrive define the industry. As solar costs continue to decline, those incumbent electricity technologies are taking increasing notice of this once-scrappy, now-formidable competitor: solar energy.

At each stage of competition, the industry has found areas of common interest, ways to promote a rising tide that lifts all boats. The work SEIA has done has helped advance the entire industry, and we are proud of that.

It’s impossible to rattle off every accomplishment in one article, but some of the highlights over this last decade include the following:

• Multiple extensions of the solar ITC and the establishment of a commence-construction provision;

• The wide expansion of state-level policies, such as net metering and renewable portfolio standards, that promote increased solar deployment;

• The establishment of a consumer-protection education campaign;

• The creation of a national PV recycling program;

• The launch of a Women’s Empowerment Committee and the creation of a diversity initiative focused on making sure our industry and our customer base are reflective of the communities we serve; and

• Numerous events, including Solar Power International, which have grown to become the gold standard for solar networking.

Although that’s an impressive – albeit not comprehensive – list, we’re not unrolling our sleeves just yet. As everyone reading this magazine knows, SEIA is currently the lead opponent in the Section 201 trade case. While we were disappointed in the U.S. International Trade Commission’s vote on injury on Sept. 22, as an organization, we remain undeterred.

We’re fighting on behalf of tens of thousands of American solar workers whose jobs are at risk if this petition prevails. Tariffs could have far-reaching and devastating impacts on our industry, and we remain steadfast in our campaign to continue the growth of solar and solar jobs here in America.

When we first started at SEIA, the solar industry employed about 36,000 workers. Now, we’re at more than 260,000, with one of every 50 new jobs created here in America in 2016 a solar job. As the head of SEIA’s research team, Justin has tracked the market closely over the last decade and seen personally how solar growth translates into real-life impacts. When a state’s solar market grows, so do the jobs and so do the investment dollars.

Meanwhile, from her job working in government affairs, Katherine has seen solar’s popularity soar. Poll after poll shows strong public support for the expansion of solar energy – and the best part is that’s across party lines. Solar is not a partisan technology.

That has become exceptionally clear with this trade case, in which a coalition of workers and groups, including utilities, the Heritage Foundation and ALEC, has joined our side in fighting this fight, and we’re not surprised. We believe that bestowing trade relief upon two foreign-owned companies to the detriment of the rest of the industry is not only unwise, it’s unwarranted. Furthermore, although we hope we’re successful in reducing the harm these companies are threatening to cause the solar industry, we know this unified front is the best counterattack.

History has shown us that working together strengthens the industry as a whole, in addition to individual companies and employees. The success of SEIA, a member-based organization, is measured on the collective success of the companies we represent. In our time at SEIA, it has become clear that those who engage in industry development have the best insight into the mechanics of the industry; they learn the risks and see the opportunities before the rest.

The both of us find it hard to believe it has been almost 10 years. We’ve had a front-row seat to one of the fastest-growing industries in America, and we can say with certainty that the view lives up to the hype. So, here’s to another decade, one we hope will be filled with continued growth, prosperity, and fewer solar coaster dips and turns.

Katherine Gensler is SEIA’s director of government affairs, and Justin Baca is SEIA’s vice president of markets and research.

Categories :

A Look At California’s Modern Solar History

Posted by Bernadette Del Chiaro

· October 2, 2017

As Solar Industry changes from print to online-only, I think about other changes to our industry over the years.

Not long ago, most of this did not exist. And, if we aren’t careful, if we don’t aggressively and collectively invest in public policy to support the continued growth of local solar and storage, much of it could be taken away. Yes, even in California.

Back in 2002, when I first started working on solar policy in Sacramento, most of the big names in the industry today were not even a glimmer in the entrepreneurial eye. There were some important players, of course – SunPower, AstroPower and PowerLight, to name a few, as well as many of the founding members of the California Solar Energy Industries Association (CALSEIA) that make up the backbone of the local solar industry.

The pioneers of the PV industry, who will gather one last time for the Third and Final Solar Pioneer Party in Mendocino County in November, started tinkering with PV and inventing the industry in the backwoods of northern California in the late ’70s. And for this, we are all forever grateful. But the engines of commerce that put solar into the hands of everyday California consumers did not get started in earnest until 2002.

In 2002, everything changed. In fact, that year marked the dawn of the modern era of the California solar industry. What happened in 2002 was that policymakers were spurred into action by the Enron-made electricity crisis of 2000/2001. Due solely to the criminal actions of manipulative and monopolistic energy companies, California businesses, consumers and cities lost billions of dollars, suffered great social and political upheaval (for example, Gov. Gray Davis lost his job), and voters were simultaneously angry and fearful that it could happen again – two powerful motivators of political action.

During this time, not only were voters and politicians motivated to make change, but also the utilities had yet to invent the concept of “cost shifting” – the notion that all local solar is an inherent burden on other ratepayers. Instead, the best arguments they had at the time were that solar was too expensive and unreliable.

What’s more, during this time, most policymakers understood that electricity, an increasingly critical commodity, was best generated and controlled locally (as opposed to in corporate board rooms of profit-minded companies) and that empowering citizens to own their own energy, creating competition in the marketplace, would help prevent future Enrons from repeating the sins of the past.

And so, California policymakers began a new era of embracing self-generation and alternative energy. Individuals, local governments, and businesses that invested in their own solar systems were heroes and warriors, “sticking it to the Enron-man,” and helping everyone avoid another blackout. These early adopters were not burdens on society, as utilities today like to characterize it. The California Public Utilities Commission (CPUC) even published a paper showing that for every dollar invested in local solar, three ratepayer dollars were saved in fuel costs alone. That’s a pretty good return on investment for the ratepayer. Environmental groups, including my organization at the time, Environment California, saw opportunity to make California a solar leader, pushing for big, concrete policy ideas.

Thus, in the four years that followed the electricity crisis, California passed several landmark bills, including the first renewable portfolio standard (S.B.1078), set at 20% by 2017, and the first comprehensive local solar policy (S.B.1), also known as the Million Solar Roofs Initiative, expanding net metering and solidifying a 10-year, $3 billion incentive program. (The first legislation authorizing Community Choice Aggregation was also passed during this post-Enron era via A.B.117 by Assemblymember Carole Migden, and in 2007 – riding the heels of this momentum – we were able to pass A.B.1470 by now-U.S. Rep. Jared Huffman to give continued life to the solar heating and cooling industry.)

It is hard to imagine today, but at the time of the electricity crisis, there were only 20 MW of local solar electric systems on roughly 6,000 rooftops, as well as only one or two experimental solar thermal plants in the desert. Daniel Sullivan of Sullivan Solar Power was a journeyman electrician down in San Diego pitching solar to his employers at the time, but they didn’t want to touch it, and Elon Musk had only just become a U.S. citizen. So much has changed.

Motivated by economics and energy independence, consumers doubled their consumption of local solar year over year, and by 2006, when S.B.1 passed, there was roughly 300 MW installed. By the beginning of 2008, when Solar Industry published its first print edition, local solar had become a 500 MW market with a healthy growth trajectory, thanks to the certainty provided by state and federal policy, including the investment tax credit, as well as a promising international market.

Did everyone in the solar industry like the idea of creating a 10-year-long incentive program via S.B.1? No! There was, in fact, dissent among industry players. Some wanted to simply let the market grow slowly so as to not invite too much competition. Some thought growth-oriented international markets would lower hardware and installation costs here in California without any further intervention at the local level. Some simply didn’t like government involvement at all.

And then there were the real opponents to the idea and to solar and storage, in general: the utilities and their local International Brotherhood of Electrical Workers (IBEW) union. Packing the same one-two punch that this duo wields today, this unified force single-handedly killed S.B.1’s predecessor two years in a row. These powerful defeats were not due to clever arguments against solar, but rather sheer political might.

At midnight on the last day of the 2005 legislative session, frustrated and exhausted from nine months of campaigning, I was quoted in the media as saying, “Not air pollution, nor blackouts, nor soaring energy costs were enough to elevate the Million Solar Roofs bill above the politics of the day.” Sound familiar? Just replace “air pollution” with “climate change” and “blackouts” with “Aliso Canyon,” and you have a ready-made quote for the energy storage bills that failed to, in the case of S.B.700, even get a hearing in the state assembly this year.

In fact, back in 2005, there was such stalemate in Sacramento that then-Gov. Arnold Schwarzenegger had to circumvent those intractable politics and direct the CPUC to create the multibillion-dollar incentive program on its own.

After this move, legislation was still needed to expand net metering, mandate similar programs at the publicly owned utilities, and jump-start solar on new home construction, but the most controversial part of the bill – the money – was defanged by the CPUC pre-emptive action, and S.B.1 sailed to the governor’s desk relatively easily in 2006, the same year A.B.32, the well-known climate change law, passed.

Interestingly, despite all of the excitement over solar energy, it took another six years for the utility-scale solar market to catch up and surpass the local solar market. In 2013 – two years after the state passed its third iteration of the renewable portfolio standard, upping the mandate to 33% by 2020 – California saw utility-procured solar go from 500 MW to 3,000 MW nearly overnight.

Today, California policymakers still hold the key to the solar industry’s future. A few short years from now, thanks to changing time-of-use (TOU) rate structures and net metering successor programs, it will be nearly impossible to install a solar electric system without an accompanying energy storage device. Yet, the number of storage devices sold in California today matches that of the solar market circa 2004. We have a long way to go on storage to marry it with solar cost-effectively for a mainstream market.

This fact bears repeating: Local energy storage today is where solar was in 2004. We have a long way to go.

A critical question we must ask ourselves now is whether the solar and storage industry, in just a few short years, will be able to lower prices, achieve economies of scale in both production and installation, and realize the same hand-over-fist growth that solar enjoyed during the previous decade without something akin to S.B.1 for storage. History would suggest certainty and market rules are needed. And, besides, that’s a lot to gamble.

Let’s be honest with ourselves. It isn’t hard to envision growth when the storage market is a mere 100 MW per year. But expecting continued and sustainable growth, free of damaging fits and starts and commensurate with what California has come to expect of its solar market? That seems like a heavier lift than a market based on “preppers,” “techies,” and C&I demand charge arbitrageurs can sustain.

The fact is that California’s solar market grew from 500 MW to 5,000 MW in 10 years. It was built on a consumer base (650,000 strong) much deeper and broader than blackout- and demand-charge-triage seekers. My favorite fact and a testament to the maturity of the market is that there are twice as many people with a solar system in oil-rich and conservative Bakersfield than in liberal, tech- and eco-friendly San Francisco. And, although we are not yet at a million solar roofs (let’s hurry up and get there, already!), we are on pace to surpass three-quarters of a million consumers with their own solar systems, totaling nearly 7 GW, in the next 12 months. None of this would have happened without clear, intentional, long-term public policy initiatives.

And what about our opponents? Well, some things never change. The utilities and their affiliated IBEW locals are once again leading the anti-local storage charge, claiming that they can do a better job building California’s modern electricity infrastructure and should, in fact, own and install everything through legislative fiat. Earlier this year, they killed S.B.700 and A.B.1030 – bills that would have guaranteed California could build a mainstream local storage market, thereby addressing the duck curve and giving consumers TOU rate relief.

As I write this article, CALSEIA is preparing to celebrate 40 years of service to this industry. What the next 40 years have in store is anyone’s guess, but this brief era of consumer-driven local solar is but a blip in our collective energy history. Nothing should ever be taken for granted, especially in the dog-eat-dog world of energy markets and the special-interest-driven world of politics.

We’ve come a long way since 2002, and we have a long way to go to reach true market saturation. Congratulations to
Solar Industry for helping cover this journey over the past 10 years. Here’s to another decade of coverage of this industry, with all of its ups and downs, twists and turns. There is one thing that is certain: None of us would be doing this if the future didn’t look bright for solar and energy storage.

Bernadette Del Chiaro is the executive director of CALSEIA, the largest solar and storage business group in California. Prior to joining CALSEIA in 2013, she served for over 10 years as the energy program director for Environment California, the sponsoring organization of the landmark California laws S.B.1 and A.B.1470.

Categories :

Five Major Trends Of The Global PV Module Market

Posted by Edurne Zoco

· October 2, 2017

I started working as a solar industry analyst 10 years ago, and over the last decade, I have been a direct witness of the industry’s development and expansion. The growth has been extraordinary and surpassed the most optimistic forecasts, including my own!

Edurne Zoco

Back in 2007, less than 5 GW was installed globally; last year, it was almost 78 GW. At IHS Markit, we are currently forecasting that 90 GW of solar energy will be installed in 2017, and we could even reach the magic 100 GW threshold by next year, thus representing 20x growth within one decade.

Because the solar industry is remarkably dynamic, it would be impossible to summarize in 2,000 or so words everything that has happened in the last 10 years – in fact, we would likely need the entire October edition just to cover what has happened since the beginning of this year. Therefore, this article is intended to be a succinct overview of what, in my view, have been the five major trends shaping the global PV module market since 2007 to bring it to its current state.

1. China runs the solar show.

In the last 10 years, global PV manufacturing has moved from Western countries and Japan to China: Chinese manufacturers have become the indisputable leaders of most nodes of the supply chain. Of the top 10 module producers in 2016, seven were Chinese. For cell production, five of the top 10 were Chinese; for wafers, all 10 were Chinese. For polysilicon, there were five. Historically, the Chinese presence in polysilicon production had been less. However, the Chinese share has been rapidly growing since 2014 and is expected to reach 53% of total polysilicon capacity by the end of 2017.

This dominance at the upstream level has been accompanied by an astonishing growth of installations in China, making it the largest solar PV market. To illustrate, in 2007, PV installations in China practically did not exist, with the exception of some isolated systems mostly in Western Chinese provinces. This year, IHS Markit predicts that installations in China will exceed 45 GW, to be at least 50% of global installations.

2. Scale and cost reduction have made solar the most affordable source of energy in some regions.

The growth of solar demand during the last decade has allowed economies of scale to help reduce the production costs of solar modules, with lower prices generating additional demand. In quantitative terms, the annual module manufacturing capacity has multiplied by a factor of 20 since 2007 to respond to the explosion of demand.

C-Si module manufacturing capacity grew from 28.7 GW in 2010 to 116.4 GW in 2017.

During this period, the manufacturing costs for all players have declined significantly. This is mainly due to efficiencies of production, product and material innovations, and economies of scale. Automation of process technologies has increased the throughput of the lines within the factory, allowing more panels to be produced per year. On the material side, both the silicon and consumables have been reduced or lower-cost materials have been substituted to cut the material cost. Incremental technology improvements have been applied to the contact points on the cells or the lamination patterns on the modules to increase their performance. The average efficiency of commercial silicon modules has improved in the last 10 years by about 0.3 percentage points per year. All in all, in this very competitive environment, module production costs have declined by more than 70% in just the last six years.

3. Policy changes, trade disputes and legal barriers continue shaping the PV module industry.

The solar power industry has required, since its beginning, different forms of government support (such as feed-in tariffs or investment tax credits) to compete increasingly against conventional energy sources. To date, solar industry development is still greatly influenced by policy and economic regulations. 2017 is a very clear example of how much policy changes, trade disputes and legal barriers continue to affect the development of the global solar industry.

Trade disputes and legal barriers have had a great impact on the module manufacturing industry in the last two years after the U.S. followed Europe in imposing import duties to cells and modules manufactured in China and, since 2015, extended these import duties to Taiwan. Of the top 10 module manufacturers by shipment, eight are Chinese; to serve the U.S. and Europe, they needed to have access to cell capacity and production outside of China. It can be affirmed that the major trigger on building more than 13 GW of cell capacity by the end of 2016 in Southeast Asian countries was the presence of continuing trade disputes.

Not only module and cell manufacturers have been affected by these regulations. The polysilicon market has been equally affected by existing duties on polysilicon imports to the Chinese market, which has created a distorted and dual polysilicon market with different demand levels, product availability, and pricing inside and outside China.

4. Business models: from vertical integration to increased specialization.

Although Chinese suppliers are expected to continue to dominate solar module production, the industrial landscape is not set in stone. The business model of vertical integration, from wafer, to cells, to modules, was of great value in the early stages of the solar industry to balance fluctuating demand and supply and to reduce costs quickly through fully controlled in-house production.

Asian companies that followed this business model (e.g., JinkoSolar, Trina Solar, Canadian Solar and Hanwha Q CELLS) are now among the largest module makers. Yet, as the industry matures, a split-up into specialized areas is more likely to leverage scale and spend less capital; there have been movements in this area toward more outsourcing of the nodes that are most upstream (polysilicon, ingots, wafers) and a greater focus on internal expansion of both cell and module production capacity.

Moreover, the solar market offers long-term growth, which makes it interesting for investment. Despite the intense competition, new investors and business models might appear, and the list of top 10 module suppliers can continue to change as it has done so for the last 10 years.

5. The continuous search for high-efficiency modules.

At the technology level, c-Si modules have been confirmed as the main technology. While thin-film accounted for almost 10% of the total production market in 2007, it is forecast to reach only 6% in 2017. The major reason for this decline was the reduction of c-Si production costs in the last decade at the same time as cell and module efficiencies were quickly ramped up, which made c-Si the technology choice for most installation segments.

Within c-Si technology, Al-BSF cells have dominated the PV cell market for the last decade. IHS Markit forecasts that this technology will retain its leadership until 2020 because of its track record and lower production cost. However, it is facing increasing competition from other higher-efficiency cell technologies (e.g., PERC, HJT or IBC) because the module industry is changing to meet the increasing demand for products of higher efficiency. Thus, most expansion of cell production capacity is for high-efficiency products. IHS Markit forecasts that more than 50% of new capacity installed in 2017 will be high-efficiency (PERC and n-type) technology. PERC cell production capacity, which was only 5 GW in 2015, more than doubled in 2016 to reach 11 GW, and it is projected to increase to 46% of global cell capacity in 2020.

Another important trend is the rise of monocrystalline technology as suppliers seek higher efficiencies in order to differentiate themselves. IHS Markit forecasts that monocrystalline technology will account for almost 40% of manufacturing capacity by 2020, from 30% in 2010.

Future outlook: What is next?

Uncertainty continues to be the norm. After many years, one of the constants of the solar industry is that regardless of how mature it becomes, the level of instability and the lack of visibility remain high because of policy changes and big trade disputes that are not anticipated. They still have a very big impact on supply and demand.

In 2017, the market continues with antidumping and countervailing duties for Chinese and Taiwanese cell and module imports in Europe and the U.S., with a minimum import price, and duties in China for polysilicon imports. Furthermore, there is a new and ongoing trade case in the U.S., which could end up with additional import duties being implemented in the U.S. market.

On Sept. 22, the U.S. International Trade Commission ruled that a surge of imports did, indeed, cause injury to the domestic module manufacturing industry. Now, the commission is moving forward to the remedy stage of the investigation and will ultimately make its recommendation to President Donald Trump in November. In the worst-case scenario of a full implementation of the measures initially proposed by co-petitioner Suniva, IHS Markit estimates that PV demand in the U.S. could shrink up to 60% for the 2018-2021 period in comparison to its current forecast.

As of press time, India, the third-largest solar market, is also slated to decide whether to include additional taxes for imported solar components; there, modules manufactured in China account for more than 70% of the total installations.

Supply chain consolidation will be limited. Although thin-film supply has been consolidated in a few large players, c-Si supply (despite some important bankruptcies and companies exiting the industry) has remained largely unconsolidated. Because a large majority of manufacturing is based in China and the current high level of installation is projected to continue in the coming years, it is difficult to foresee any massive consolidation. As long as the Chinese market continues at this level of installation (at least 45 GW forecast in 2017), consolidation of the Chinese manufacturing industry will be rather limited.

Module and other system component costs will continue to decline, making solar more attractive in new markets. Module manufacturers continue to look for innovative ways to reduce their costs and are increasingly focused on improving their cell-to-module conversion rate. Most companies are now starting production of half-cell monocrystalline modules (both p-type and PERC) and modules with more busbars, which can increase module output by 10-15 W without incurring higher production costs on a per-watt basis.

Total module costs for industry leaders are forecast to continue to decline in 2018 after a very exceptional second half of 2017, when current high polysilicon prices are slowing down the original plans of module manufacturers to reduce costs to around $0.30/W for best-in-class p-type modules by year-end.

IHS Markit is currently forecasting at least 112 GW of annual installations by 2020. However, it should not come as a big shock if solar demand growth continues to surprise manufacturers, developers and analysts – all of whom have consistently underestimated demand, which will continue double-digit annual growth over the next 10 years. As long as the 80% of solar installations remains in a handful of countries – China, the U.S., India and Japan – sudden policy changes and the creation or elimination of commercial barriers will continue to make producing precise long-term PV forecasts one of the most challenging (but most interesting) jobs!

Edurne Zoco is research director of solar and energy storage at IHS Markit.

Categories :

Aggregation, Shared Access And The Future Of Solar-Plus-Storage

Posted by K Kaufmann

· September 6, 2017

The New York Times got it wrong.
In a recent story about how Green Mountain Power (GMP) is rolling out solar-plus-storage systems in Vermont, the paper suggested the effort is noteworthy because it lets customers power their homes “entirely disconnected from the grid.”

Which is true, kind of. The 5 kW Tesla Powerwall units the utility is making available to its customers allow them to operate off-grid for several hours in times of emergency or if needed to balance supply and demand on the grid.

However, the real game-changer in the GMP program is that it requires customers to agree to shared access – that is, letting the utility monitor and, at times, control the storage units, which are installed behind their meters. GMP can then aggregate power stored in the batteries and use it, for example, to lower its need to buy electricity during times of peak demand, which in turn provides savings that can benefit all of its customers.

The program is still in its early stages, says Kristin Carlson, GMP’s vice president of strategic and external affairs, but 900 customers have already called in to express interest.

“This is the energy future we see, where every [new customer] gets a meter, and they get a battery,” she says.

Shared access has long been a sensitive issue in the utility industry – another point the Times article missed. Customers have tended to balk at allowing utility control of any device in their homes – hence the difficulty some utilities have had in getting residential customers to sign up for summertime air conditioning cycling programs.

Making shared access the default option – as GMP has done, with apparently little customer pushback – signals a paradigm shift with potentially far-reaching impacts.

Grid defection is no longer the main narrative on residential solar-plus-storage. Rather, utilities, customers and technology developers are recognizing that the way to unlock the cost savings, energy reliability and resilience that solar-plus-storage can provide is through aggregation and collaboration. “Energy independence” is still an industry buzz term, but its meaning has shifted toward a focus on customer control and choice.

“People want to control their own destiny, whether 100 percent off grid or still connected but with more control,” says Bryan Christiansen, chief operating officer at Vivint Solar, a national installer now rolling out a residential storage offering in partnership with Mercedes-Benz. “[You can bring] more distributed energy resources into the marketplace and coordinate resources with utilities.”

“I think that is absolutely the smartest solution,” agrees Leia Guccione, a principal at the nonprofit Rocky Mountain Institute (RMI), which has published a number of reports on the role of storage as a tool for energy sector transformation.

“That creates the opportunity for customers and some third parties to be part of aggregated resources that will create a positive dynamic,” she says. “Solar, smart inverters, batteries [and] smarter appliances can be part of a virtual power plant. That is where the industry should be going; that will move the market fastest and help us reform the grid for everyone’s benefit.”

This holistic view of the market also turns up in discussions on whether utilities or third parties should be the actual aggregators, owning and accessing behind-the-meter equipment and data. Guccione sees it as an open question, with arguments to be made for both sides.

“I don’t think, at this point in time, one is better than the other,” she says. “Both are a change from what we have today. We think it is important to innovate around these ideas to get more information on what we should incentivize.”

Pacific Gas and Electric (PG&E) led the nation in new residential storage installations last year, according to the Smart Electric Power Alliance’s (SEPA) 2017 Utility Market Survey. The Northern California utility is now rolling out a pilot project – in partnership with Tesla Energy – to test the grid-support services that aggregated behind-the-meter storage can provide.

In this case, Tesla is being the third-party aggregator for the solar and storage systems it is installing on 30 homes in San Jose, says Alex Portilla, PG&E’s principal project manager for distributed energy management systems. But the utility is looking at other options, he says.

“There will be some cases where we have a more active role,” Portilla says. “We’re working out where it makes sense for us. Who is in the best position to create value or transactions in the wholesale market or use [storage] assets for distribution? Where do you need control, and who controls? Who is the conductor?”

A fundamentally different conversation

Creating value – and multiple revenue streams – is what the developing solar-plus-storage market is all about, across the residential, commercial and utility-scale segments.

Simply put, the pairing of solar and storage offers a range of cost-saving and grid-support benefits for customers, utilities and the grid. Consequently, for all their wariness and resistance to solar, utilities appear to be on a much faster learning and acceptance curve with storage, according to Matt Roberts, vice president of the Energy Storage Association.

“The conversation we’re having on energy storage is fundamentally different [from solar],” says Roberts. “This is a new era of the grid. Storage is a lot more similar to what the utility has always done. It helps you move energy across time. There are so many possibilities to extract the full value; it’s going to take customers and utilities working together to make it successful.”

The residential sector has, thus far, been the smallest and slowest part of the storage market, but some industry watchers see a number of factors that could accelerate growth.

SEPA’s 2017 Utility Market Survey found that 33 utilities put a total of 557 residential storage units on the grid last year, bringing the national total to 1,762 residential interconnections.

“When we looked at the raw data from the energy storage survey, it reminded us of our first solar market survey in 2007, when only a handful of utilities had any deployment to report,” says Nick Esch, the SEPA researcher who led the survey. “More than 40 percent of the 97 utilities who responded to this year’s survey didn’t have any energy storage online at the end of 2016.”

Even PG&E, the industry leader in SEPA’s findings on the residential sector, is seeing only a trickle. The utility interconnects about 5,000 rooftop solar systems per month, Portilla says, but this past June, it had only 25 storage interconnections, and several of those were part of the San Jose pilot project.

What will change that trickle to a steadier stream is, of course, economics coupled with consumer demand. The growing electric vehicle market is expected to provide the economies of scale that will keep battery prices spiraling down.

Guccione notes that both storage and solar prices are falling faster than RMI projected in a 2014 study that estimated going off grid with solar-plus-storage would be economically feasible in a growing number of states in 10 to 30 years.

Rate increases or restructuring will also likely be a factor as residential rates go up or time-of-use rates or demand charges are rolled out, as some utilities are now proposing.

“We can say with pretty high confidence, if anything, the full [grid] defection and partial defection scenarios are going to be economically viable sooner than forecast,” Guccione says.

But, just because going off grid is economically feasible, it doesn’t mean utilities will face massive grid defections, she says. Echoing Vivint’s Christiansen, Olaf Lohr, director of business development for sonnen Inc., says that customers understand energy or utility “independence” as a measure of choice or control.

sonnen, a Germany-based storage company focused wholly on the residential market, has also partnered with GMP, providing the storage units paired with rooftop solar at a low-income mobile home park in Waltham, Vt.

“You are trying to keep as much energy in the microcosm of your home, drawing as little from the grid, exporting as little to the grid,” he says, noting that sonnen’s customers can hit levels up to 70% or even 90% of their energy use. Customer demand is building, Christiansen says. Vivint made its decision to move ahead with storage based on market research showing that 52% of current residential solar customers are interested in battery storage, he says. Similarly, 51% of those looking to go solar within the next five years said they would be interested in including storage in any new installation.

Such figures are drawing utility interest, as well. SEPA’s utility storage market survey found that while only 9% of responding utilities currently offer a residential storage program, 72% are researching, planning or considering one.

“Storage may not yet be a mainstream utility resource, as solar is rapidly becoming, but clearly, many in the industry can see the point on the horizon where that starts happening,” says Tanuj Deora, SEPA’s executive vice president and chief content officer. “They understand storage will be deeply disruptive and transformative in the value it brings to the grid – even more so than solar – and they need to start preparing for those changes now.”

Visibility, cybersecurity and ease of use

The caveats in all of this are the technical and strategic issues that still need to be addressed, says Beth Chacon, utility Xcel Energy’s director of grid storage and emerging technologies.

“The market is new, and I think everyone is trying to figure it out,” she says. “What is it you want to accomplish with your batteries? We do need visibility; we do need cybersecurity; we have to work through all these things.”

Xcel is moving forward with a pilot program in Colorado that, like PG&E’s, will test the grid-support capabilities of storage, Chacon says. However, in this case, the storage will be installed both behind the meter and on distribution feeders. As at GMP, customer interest is high, she says.

But whether interest translates into technology adoption, program participation and, ultimately, market growth may depend on ease of use. Many of the solar-plus-storage systems now being launched have “set it and forget it” energy management systems that provide both the shared access utilities need for aggregation and the control and emergency backup power important to customers.

“We’re finding our customers don’t want to be told to do laundry at 2 a.m.,” says GMP’s Carlson. “They don’t want to be inconvenienced. What’s critical is to use these innovations to make people’s lives easier and make the pricing such that it makes sense for people.”

GMP’s storage program is set up so that customers pay $15 per month for the Powerwall units in their homes, she says. Guccione agrees financing must be simple, but she argues, value may also be a key factor in customer acceptance.

“Keep in mind, smartphones are a lot more complicated than landline phones because they have so much value,” she says. “Customers had very few barriers to learning how to use them. We need to take that kind of dynamic into consideration. If we provide enough value, complexity is not that big a barrier for customers.”

sonnen is going to put that concept to the test later this year when it brings its sonnenCommunity program to the U.S., Lohr says. Basically, the system is a community-level platform that allows residential customers with solar and storage to buy and sell power among themselves. In Germany, thousands have signed up to participate.

The U.S. version will be connected to the grid, he says, so it can also offer grid-support services, and participants will get credits on their bills for excess energy they make available to others on the platform, he says.

While Lohr would not divulge the location or other details on the rollout, he did say sonnen has partners and is investing its own resources to get the program off the ground in the U.S.

He believes getting residential storage into the energy mainstream will not be linked to absolute penetration levels, but to specific applications reaching a critical mass in different areas, based on the value and benefits they deliver. Rather like what’s happening at GMP.

“We are on the edge of this innovation and this technology that is happening in storage,” Carlson says. “There will be innovation that comes out next year; there will be something we can’t imagine. We want to be nimble enough for our customers to take advantage.”

Of course, the growth of residential solar-plus-storage with shared access is part of the much larger changes going on in the energy industry as more distributed energy resources, on both sides of the meter, come onto the grid. Keeping pace with technological change – and the unpredictability it brings – will require a commitment to cross-industry collaboration and finding solutions that optimize benefits for customers, technology providers, utilities and the grid.

K Kaufmann is communications manager for the Smart Electric Power Alliance. She can be reached at kkaufmann@sepapower.org.

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Homeowners Benefit From Installer Choice

Posted by Eric O’Shaughnessy & Robert Margolis

· September 6, 2017

As the solar photovoltaic (PV) industry in the U.S. continues to evolve, there are a growing number of local companies that install residential PV systems and a number of emerging online platforms that make it easier for customers to obtain installation quotes. However, in 2015, 10% of the highest-volume installers – in terms of number of systems installed – accounted for about 90% of installed residential systems. New research from the U.S. Department of Energy’s National Renewable Energy Laboratory (NREL) shows that homeowners can benefit by seeking quotes from a range of suppliers.

We find that high-volume installers tend to quote higher prices than others when delivering quotes to the same customer. Some customers may prefer working with high-volume PV installers and be willing to pay premium prices for a variety of reasons. Nonetheless, our research shows that all customers can benefit from obtaining more quotes before making a decision and that all customers could benefit from increased access to more offers.

Our research uses actual quote data from EnergySage, a PV quote provider in the U.S., to explore how an installer’s company size affects its pricing. The study analyzes the market position and pricing behavior of “high-volume” installers – any company that installed more than 1,000 residential PV systems from 2013 to 2015 – and “low-volume installers,” which refers to all other companies.

EnergySage’s online platform provides multiple PV quotes, helping prospective PV customers comparison shop for solar and determine their savings by adopting solar. The company provided NREL with more than 1,550 quotes for customer-owned systems made to 351 customers in 27 states and the District of Columbia from February 2014 to October 2016. In addition to the quotes from EnergySage-affiliated installers, the study also included quotes from other installers that EnergySage customers voluntarily submitted. The study limited the quotes to customer-owned systems in order to compare prices according to a single metric: dollars per watt ($/W).

The data included 176 high-volume installer quotes with an average quote price of about $3.99/W compared to 1,412 low-volume installer quotes at an average of about $3.62/W (see Figure 1).

The primary benefit of using quote data over installed system price data is the ability to compare the prices of different offers quoted to the same customer (Figure 2). Comparing prices quoted to the same customer allows self-consistent control for home characteristics that affect installation costs, such as roof pitch and construction materials. In the analyzed database, 142 customers received at least one quote from both a high- and low-volume installer.

We use a paired differences test to study price differences between high-volume and low-volume installer quotes made to these customers. For instance, if a high-volume installer quoted $3.90/W and a low-volume installer quoted $3.80/W to the same customer, the paired difference equals $0.10/W for that customer. The average paired difference in our study was $0.33/W. In other words, high-volume installers quoted $0.33/W higher, about 10% higher, than low-volume installers on average when quoting to the exact same customer. High-volume installers quoted higher than low-volume installers in about 70% of quote pairs we analyzed. The difference in high-volume installer quote prices is robust after controlling for system size, quote date, module efficiency, inverter type, and whether the quote was provided via EnergySage’s online platform or directly to the customer.

Our findings suggest that high-volume installers quote higher, on average, than low-volume installers. The quote price differences can be significant – a difference of $0.33/W translates to $1,650 for a typical 5 kW residential system. These results prompt two questions: Why would high-volume installers quote higher than low-volume installers, and why would customers accept higher prices? Using economic theory and insights from similar markets, our analysis discusses possible answers to these questions.

Why would high-volume installers quote higher prices than low-volume installers?

One possibility is that competitive advantages allow for charging higher prices. Most customers only obtain a few quotes; thus, high-volume installers may face few rivals when providing a quote to a customer. By contrast, low-volume installers may perceive greater competitive pressures to undercut the prices of high-volume installers in their territory. Further, low-volume installers are generally less able to offer third-party ownership (TPO) products than high-volume installers. As a result, they are not as active in TPO markets, and high-volume installers face less competition when bidding to customers interested in TPO products.

Most prospective customers are first-time buyers and largely unfamiliar with PV installation. In markets for similarly novel and complex products, like consumer electronics, customers often use reference points such as brand names and advertising to select between product options. High-volume installers may be better positioned to use their scale, brand awareness and marketing to attract these first-time buyers and charge higher prices.

Additionally, higher quote prices by high-volume installers may reflect some diseconomies of scale in residential PV installation. In particular, they may incur higher customer acquisition costs than other low-volume installers. High-volume installers have invested in broad-ranging customer acquisition strategies such as mass marketing and door-to-door canvassing. These customer acquisition efforts have allowed some installers to scale in size but have also proven to be costlier than methods more commonly used by low-volume installers, such as customer referrals. As a result, customer acquisition costs in the U.S. solar industry have increased in recent years, especially among high-volume installers.

Why would customers accept higher prices from high-volume installers, if lower prices are available from other low-volume installers?

Some customers may prefer working with high-volume companies for a variety of reasons, such as the ability to honor contractual terms and warranties.

Furthermore, some customers may use an installer’s volume as a proxy for quality. That is, some customers may assume that high-quality installers attract more business, and as a result, an installer’s volume is an outcome of its quality. These perceptions could lead some customers to pay higher prices for high-volume services.

Our results indicate that customers benefit by shopping around, even if those customers prefer high-volume companies. However, collecting PV quotes can be a daunting process. To obtain multiple quotes, prospective customers must identify and contact installation companies, have conversations with these installers, host site visits, provide home information, and make other investments of time and effort.

Our research shows that policies and consumer products that facilitate the quote collection process can significantly benefit PV customers and potentially increase their likelihood of adoption. Third-party quote platforms can help customers collect more quotes from a variety of high- and low-volume installers and also allow those customers to more easily compare them. Furthermore, easier quote collection could increase inter-installer competition and reduce quote prices overall.

A corollary result of our study was that quote prices were significantly lower, on average, on EnergySage’s quote platform than when received directly from installers. Lower prices on the quote platform could reflect competitive pressures on installers that expect to compete with many other companies and may result in increased adoption of PV.

Prospective PV customers face a variety of choices during solar adoption, including the choice of an installation company. Our research suggests that installer choice matters. We find that high-volume installers tend to quote higher prices, on average, than low-volume installers. At the same time, high-volume installers may offer additional value propositions such as TPO products that may be more attractive. All customers can benefit from obtaining more solar quotes before buying.

Eric O’Shaughnessy is a market research analyst and Robert Margolis is a senior analyst at the National Renewable Energy Laboratory. This article is adapted from an NREL report co-authored by them, titled, “Using Residential Solar PV Quote Data to Analyze the Relationship between Installer Pricing and Firm Size.”

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Solar’s Effect On Seemingly Unrelated Industries

Posted by Ruth Fein Revell

· September 6, 2017

The sirens are cut as the truck rolls up to an involved structure fire. If you’re a firefighter first on the scene, you don’t have time to pause before you put everything you know into action.

Once it’s established the house is empty, you advance toward the billowing smoke. Then the entire squad stops dead in their tracks. There are solar panels on the roof that you couldn’t see from the front. You rely on your recent training; no time is wasted as power to the home and the solar equipment is safely shut down (to the extent possible). Now you can confidently approach the roof.

Without effective solar education and training, this scenario might not play out the same way in another neighborhood, where first responders didn’t have the knowledge and confidence to respond without skipping a beat.

In many areas of the country, firefighters are becoming better prepared for emergencies where solar technology is present. They’re alleviating their safety concerns. They’re able to swiftly identify and shut down even less-visible solar systems. They know where they can operate safely with a solar-energized system in play, as well as when they can or can’t create a rooftop escape route for heat and smoke. New in-person and interactive online training courses are helping firefighters and other first responders become solar smarter. And with increased knowledge and a plan, they can approach and act automatically, as they do for other structural emergencies.

“PV systems are becoming more prevalent in our communities, and firefighters need to understand how to safely work around them,” says Derek Alkonis of the Los Angeles County Fire Department.

Precisely. Homeowners across the U.S. are increasingly adopting solar, so more firefighters are coming into contact with solar installations every day. “The primary message here is clear,” says Laure-Jeanne Davignon, director of workforce development for the Interstate Renewable Energy Council (IREC), who is working in partnership with the International Association of Fire Fighters (IAFF) to develop and offer training. “Nobody wants first responders to wait for an emergency to learn the answers to important questions about solar technologies.”

Professionals involved in the solar industry are in a unique position to help. “Pass the word along,” says Davignon. “Be sure first responders in your area know they can take an online PV safety course specifically for firefighters, and it’s free, so municipal and volunteer fire companies of all sizes and budgets have the opportunity to learn how to more confidently, safely and effectively operate around solar-equipped structures.”

This training isn’t a commercial venture, she explains. It was designed by experts from the solar industry and the fire service, taught by active career firefighters, supported by the IAFF and the National Association of State Fire Marshals, and funded by the U.S. Department of Energy’s (DOE) SunShot Initiative. Most importantly, video-simulated environments allow first responders to practice the skills they’ve learned before they pull up to a PV-powered structure.

Other professionals are increasingly affected by the U.S. solar boom, as well. Within the construction industry alone are builders and developers, electricians and plumbers, and roofers and architects (and the local code officials who inspect all of their work). And the list is growing to include a host of seemingly unrelated industries, such as realtors, appraisers, financial loan officers, and commercial and residential building maintenance managers.

Typically, what they need to understand goes beyond the basic benefits of solar technologies, including the value solar brings to a property, residents and a community. Knowledge of on-site shared solar options and the often-complex rate design and interconnection policies that differ by state and utility may be important to their work, in addition to complementary technologies, such as energy storage.

While some professional associations are beginning to tackle this knowledge need by integrating solar into their professional education, help is often a product of nationally funded education and training initiatives for so-called “allied” solar professions. The DOE’s Solar Training and Education for Professionals (STEP) project, for example, provides help.

Real estate offers a good illustration. Research on single-family residences shows that customer-owned PV systems provide similar benefits to home sales as other upgrades – think new kitchen. Yet, most real estate education classes still don’t even touch on solar energy.

According to the Lawrence Berkeley National Laboratory, solar-powered homes result in a higher sales price, reflective of the value of the solar array, and they spend less time up for sale on the market. Real estate agents and appraisers need to understand how to accurately value solar in the marketplace so they can leverage it in marketing for resale or for refinancing.

Through the STEP project, solar education is reaching an increasing number of allied professionals through industry-specific educational forums and Web-based continuing education courses, and the conversation is beginning to trend in industry blogs and through other social media channels.

Similar inroads are being made with code officials, architects, engineers and other building design professionals so that they’re better equipped to facilitate effective solar-ready buildings.

Furthermore, managers of multi-tenant residential and commercial buildings, building maintenance managers and, frequently, homeowners association managers are also faced with decisions about investing in solar.

“Raising awareness among multifamily residential housing stakeholders about the opportunity and value of solar is critical to expanding consumer access to solar energy, particularly to removing barriers for this underserved market,” says IREC Regulatory Director Sara Baldwin Auck.

Organizations like the Center for Sustainable Energy, IREC and the California Solar Energy Industries Association are jumping in. They’re working to enable multifamily property owners and managers in California with information and assistance they need to make smarter solar decisions. Through a project supported by the DOE’s Energy Solar Market Pathways Initiative, the goal is to take advantage of California’s existing virtual net metering tariff, which allows for a multi-metered, multi-tenant property to install a single solar electric system that can be shared by multiple on-site tenants and common load utility accounts, resulting in direct, on-bill savings.

To help more multifamily solar projects come to life, the team is partnered with EnergySage on the development of an online multifamily portal to connect multifamily building owners and residents with interested solar contractors. And new online resources include these toolkits for apartment and condo owners and managers, as well as for contractors.

The National Apartment Association (NAA), recognizing increased interest from its members (more than 73,000 members, operating 9 million apartment units globally), is very visibly supporting solar as part of an industry trend toward sustainability.

“Our members are moving forward with growing interest in solar, especially with more access available through financing and contracting opportunities in the last few years,” says Holly Charlesworth, NAA manager of government affairs. “With growing use of solar in our members’ communities, it’s starting to make financial sense for these building owners, with the cost of on-site and community solar going down.”

Solar has been on the NAA radar for some time. Now the organization is actively highlighting the success stories of its members and developing new resources to educate them, such as an upcoming guide that will identify various paths for apartment buildings to go solar. The NAA Education Institute helps the industry workforce keep up with the latest industry trends (including renewable energy and energy efficiency) through online and classroom training and credentialing.

The development of micro-credentials is one cutting-edge path IREC is leading that may soon play a key role in the training and validation of solar skills within other professions. A good example is the NAA Education Institute, which is working with IREC to develop an energy-efficiency
micro-credential for apartment maintenance professionals.

“Today, we see emerging as a pressing priority quality third-party validation of specialty skills both for clean energy allied professionals whose jobs ‘touch’ solar in some way and for add-on skills for full-scope credentials that currently exist within the clean energy professions,” according to Anna Sullivan, associate director of IREC’s credentialing program.

No matter if it’s a single-family dwelling or a large shared multi-tenant project, at the core of any solar installation are the permits and approvals necessary to complete the array, flip the switch and start generating clean energy. As permitting authorities encounter higher volumes of solar permit applications, keeping the process moving efficiently is as important for them as it is for the solar industry.

“With so many jurisdictions involved, consistency and standardization are among the keys to driving down the installed cost of solar and other renewable energy,” says IREC’s Auck.

With no standardized permitting process in the country, and some 25,000 jurisdictions, the inspection and permitting process is a huge challenge to improve. Although PV systems can be as straightforward as many of the electrical systems code officials review or inspect, the technology is advancing at lightning speed, new electrical codes are pertinent, and best practices are constantly evolving. Keeping up is critical, as is improving the plan review process to help authorities having jurisdiction (AHJs) complete a solar plan review as effectively and efficiently as other plans. This is particularly important because many local inspectors wear multiple inspection hats.

“One of the things most valuable for a contractor is building confidence with an inspector so they feel you know and follow the applicable codes and standards,” says Don Hughes, a 20+ year code official with Santa Clara County, Calif., who was involved with the development of the first PV online training course (PVOT) designed for code officials just five years ago.

“PV online training is an excellent source for PV installers, as well as code officials and inspectors; they can all be participants in speeding up the permitting process while never compromising safety or the effectiveness of an installation,” adds Joe Sarubbi, who directed the development of the original PVOT and its most recent update for IREC and the International Association of Electrical Inspectors (IAEI). “It is now in code compliance with the 2008, 2011 and 2014 versions of the National Electrical Code and includes a new lesson covering the 2012 International Fire Code, with building and fire safety related to residential PV.”

New in-person code courses are also available to build on what code officials already know – with the IAEI, International Code Council and NABCEP all offering continuing education units. The goal is to introduce solar PV concepts in a way that demystifies the technology.

Once solar is installed and operational, the question of value comes back to a final group of professionals, appraisers, and the lenders and underwriters who review their appraisal reports.

“Solar brings new appraiser challenges to learn more about electricity, how it is priced, how much the solar PV costs, how much it produces, how long it lasts, and how to find solar data,” explains Adomatis Appraisal Service’s Sandy Adomatis, SRA, who develops and teaches solar courses for appraisers, for the Appraisal Institute and, most recently, for a new course launching in September that includes emerging technologies such as energy storage.

One of the biggest challenges for appraisers is getting the complete information they need – and in a consistent way – so they can properly compare and evaluate properties with installed solar.

“MLS is the best database residential appraisers have, and rarely does the listing provide sufficient detail of solar to allow an appraiser to find sales that are comparable,” according to Adomatis. To complicate the problem, often homeowners don’t have all of the details about a system, particularly if it is older or was installed before they owned the home.

As the challenges evolve, solutions are surfacing. For example, Berkeley Lab suggests public access to solar data could be through a central data repository, which would help resolve complications to the valuation of a property by identifying solar PV characteristics by address.

In the meantime, the Appraisal Institute just updated its AI Residential Green and Energy Efficient Addendum, which now has a page dedicated to solar PV. “If property owners and solar installers completed this solar page and made it available to the appraiser and lender at loan application, it would make a big difference in the accuracy of the appraised value,” says Adomatis.

Ruth Fein Revell is a freelance writer based in Saratoga Springs, N.Y., who also manages communications for the Interstate Renewable Energy Council, a national independent organization advancing fact-based clean energy regulatory policy and quality workforce development for 35 years.

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How To Create A Complete Commercial PV Design Package

Posted by C.J. Colavito

· September 6, 2017

Right now, the commercial solar segment is one of the hottest in the solar industry. Maybe it’s all the press suggesting it is finally taking off after spending years in solar purgatory. But the influx of new companies into the space has also created a gap between experts and amateurs – and in this space, almost more than any other solar segment, customers need to be dealing with experts.

C.J. Colavito

Unlike utility-scale and residential solar, commercial solar is a complex web of the interwoven needs of the project owner combined with the complicated engineering challenges that frequently come up in commercial projects.

That’s why it’s important to have a clearly defined engineering protocol that everyone on the team – and those essential members of the ownership and construction crews – understands. Having a well-documented process in place before the project begins leads to fewer misunderstandings, miscommunications and change orders, which often delay projects and can cause failed inspections and deficient energy production.

Here is an example of what I believe it takes to create a complete commercial PV design package.

Manage the interconnection process

It doesn’t seem like managing paperwork would fall under the engineer’s purview. But when it comes to connecting the solar project to the grid, the coordination, communication and cost management of that critical integration must be carefully overseen by an informed and technically literate individual. Constant communication with the electric distribution company (EDC) and clear documentation are essential for expedient approval and a cost-efficient interconnection.

As a result, it is incumbent on the engineering team to read and understand what’s expected of them to avoid potential problems at the time of commissioning. That means doing the following:

• Reading and understanding all interconnection and power plant construction rules, policies and regulations for the state, utility or region where the project is being built. These regulations can be found at the U.S. Department of Energy-sponsored DSIRE website, as well as on the local EDC’s and state public utilities commission’s websites; and

• Making sure the team has the latest interconnection documents, which are usually housed on the EDC’s website.

Realistically, engineering teams should budget a minimum of six business weeks from the submission of interconnection application to the formal approval to construct from the EDC. It is best practice to refrain from ordering materials until the approval to construct has been obtained. Otherwise, you might end up with a warehouse full of materials for a project that, for whatever technical reason, might not end up getting built or is significantly altered from the original plans.

Conduct a detailed engineering site visit

You might be surprised, given how hands-on most engineers are by nature, that this is an often underestimated step in the process. But no matter how good the photographs are or how many angles they depict, there is never a substitute for getting out into the field to see first-hand what a site looks like – and what hidden engineering challenges you might uncover. A proper detailed engineering site visit requires no less than two people and two to eight hours on-site, depending on size and complexity.

After all, there are certain important engineering considerations that shouldn’t be determined while sitting behind a desk, such as the following:

• Measuring and locating all shade structures and obstructions or understanding the limitations imposed by site topography;

• Determining the proper type of mounting system to be used, depending on both the type of project and the type of material on which the racking will rest;

• Identifying where the array may most effectively interconnect with the electricity system – something most EDCs require detail on before they give the project the go-ahead;

• Deciding how the project will interconnect – what materials will be necessary, what the code-compliant configuration might look like and what the most effective way to produce the proper outcome might be (another item the utility may insist on before giving a project approval); and

• Figuring out where the inverters and balance-of-systems equipment will be located.

In the end, a site visit allows the engineer’s trained eye to see and identify potential trouble spots before they become obstacles to delivering a project on time and on budget.

Select the proper components

This may sound like a simple process, but one mistake can easily cost tens of thousands of dollars or significant productivity losses – hurting your company’s reputation in the business. So, take care when you’re selecting the two most critical components to make sure they’re exactly right for the project, and remember the following guidelines:

Modules: Keep in mind that a solar module made for utility-scale projects may not be the best fit for a commercial roof-mount project or a carport. Do your due diligence and consider factors like expected module-technology performance in the climate at the site, shade tolerance, energy density and (unfortunately) the ability of the vendor to deliver. If you’ve been paying attention to solar news lately, there is a shortage of modules on the market. You want to make sure when you’re selecting module vendors that they will be able to deliver their products on your schedule, not on theirs.

Oh, and check with your project financier: It’s entirely possible the financier already has a relationship with one specific supplier or has other considerations you’ll need to take into account.

Inverters: Anyone specifying inverters must first find out from the utility what its requirements are before even beginning the procurement process. The last thing an engineer wants to have happen is to discover – too late – that the inverter he or she has specified doesn’t have the required features the utility needs for interconnection.

Research the market and familiarize yourself with the different inverter technologies and products available from quality manufacturers. Review the system design to verify which inverters will function properly in the project’s environment and with the specified modules. Then reach out to inverter manufacturers with the specifications necessary to optimize your project. Though the turmoil roiling the module market is not occurring in the inverter market, even some great inverter manufacturers have come and gone. Consider that the inverter is the heart of the PV system and is by far the most common point of failure. Be sure to select a vendor that will be there with strong support and a solid warranty when you need it.

If you follow similar steps for the other components, the system being engineered will be well integrated, and the construction team will feel the benefits and take notice.

Manage third-party engineering vendors

Despite what engineers might tell you (or themselves), sometimes they can’t do everything on their own. In those situations, it’s important to know what you don’t know and acquire outside assistance to make sure even the parts of the projects you aren’t an expert in are done right.

The first step, of course, is identifying those areas where third-party professional engineering services are necessary, which could include (but are certainly not limited to) electrical, structural, civil, geotechnical, environmental and controls.

Once those areas have been identified, the next step is deciding on the scope of the work any outside firms will be doing so they can craft their bids to specific parts of the projects. Be sure to walk through your proposed scope and coordinate requirements with competing bidders, which ensures that any comparisons will be accurate and fair.

Left to their own devices, many third-party engineering firms would bid on items that may be unnecessary while inadvertently leaving out critical work that can end up as change orders and unexpected budget overruns later. I’ll admit that we have learned the hard way that it is often lower cost to take the time to have a complete scope up front than to have a professional return to the site later to complete additional investigation. If such confusion can be avoided with specifics in the request for proposals, fewer problems will await you down the road.

During the vendor selection and evaluation process, keep the project manager in the loop with respect to the budget and what has been agreed to so that there are no surprises as the project moves forward.

Design in stages

When our team at Standard Solar is working on designing a commercial system, we work through three stages of design work. Breaking it down into three milestones allows for a rigorous quality review every step of the way, which provides more opportunity for mistakes to be corrected before being constructed in the field. Our three design stages are 30%, 60% and 90%. Here’s what you should look for at each stage:

30% – Start by assembling all possible information about the project, including existing structural drawings, existing electrical diagrams, topographic maps – anything that is relevant to ensuring the engineers have all the necessary information before they start their designs.

Then research and obtain local permitting and zoning requirements, and complete the detailed engineering site visit and licensed professional survey, if needed. If the project is a ground mount or carport, a geotechnical analysis should be conducted to enable proper selection of the mounting system and foundation type and to coordinate the array layout.

Once you have all the preliminary information you need, the fine art of system design really begins. At this stage, you select the major PV equipment according to the aforementioned criteria. Next, calculate string size, evaluate the ideal array to inverter sizing, and generate a preliminary shade analysis. From your on-site visit, you’ve already identified all potential shade structures/trees.

Now you’re ready to generate your array layout, determine conceptual electrical design and generate drawings that show the inverter placement, point of interconnections, approximate DC and AC conduit routes, and other major equipment locations. The 30% design typically only includes two to five pages but entails a tremendous amount of homework and background analysis to deliver a good result.

60% – Now that the conceptual design is out of the way and adjustments have been made based on peer and client feedback, it’s time to generate a detailed array layout. This should include drawings of sub-array electrical configuration, including combiner boxes, rapid shut-down devices, and AC accumulation panels, as well as conduit routes from the array to inverters, inverters to accumulation panels and, finally, from panelboards and switchboards to the point of interconnection.

At this stage, you should perform National Electrical Code wire sizing calculations, voltage drop calculations and conduit fill calculations and generate preliminary equipment elevations, including inverter pads, DC disconnect/inverter/combiner-box rack mounting, the AC accumulation panel, interconnection location, fence details, and mounting system elevations.

Once you’ve gotten your peers, project team and manager to review the plans, make the necessary changes and drawing updates based on their input. Now you can generate the first draft of the Bill of Materials, including all the major materials we’ve discussed. It’s also critical that you and your team continue coordination and management with the utility and key product vendors. Once this stage is reached, we at Standard Solar will often obtain any required professional engineer stamps and submit to the authority having jurisdiction (AHJ) for permit.

90% – By now, you’re nearly finished. It’s time to finalize the system layout, including string diagrams, wire management details, electrical-equipment-wiring details and the location of the disconnecting means. As necessary, this will also be the stage where you detail the data acquisition system or control system components, where they will be mounted and how they are integrated with the PV system.

At this point, you will update the energy production model and adjust any calculations accordingly. Appropriate third-party engineers should be continuously involved throughout each stage, and their feedback should be incorporated into the plans, along with any comments or requirements returned from the AHJ’s review.

Submit the plans to your final internal peer review, as well as a final collaboration with the project team and management team – and now you’re ready to put the finishing touches and conduct a detailed page-turn with the construction crews’ leaders and any subcontractors before construction commences. Reviewing and coordinating the design with the construction professionals installing the job is critical. Most mistakes, poor practices or constructability issues can be identified and avoided at this stage.

If commercial solar project engineers move through these steps (and any others they feel are necessary to add), it will greatly improve the odds that the commercial project they’re designing will go smoothly.

C.J. Colavito is director of engineering at Standard Solar, a Maryland-based company specializing in the development and financing of solar electric systems nationwide.

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