The SOL SOURCE Archives

Click here to read the The Sol SOURCE Q3 2019.

The Sol SOURCE is a quarterly journal that our team distributes to our network of clients and solar stakeholders. Our newsletter contains trends and observations gained through quarterly interviews with our team, and it incorporates news from a variety of industry resources.

Below, we have included excerpts from the Q3 2019 edition. To receive future Journals, please subscribe or email SOURCE@solsystems.com.

STATE MARKETS

New Jersey - New Jersey continues to be a question mark for renewable energy developers. Once one of the strongest solar markets in the country, many are now uncertain as to what the state’s solar future holds as stakeholders await a final program design for the transition program and for conversations to begin regarding the successor program’s design.

Per the state’s Clean Energy Act of 2018, the New Jersey Board of Public Utilities (BPU) is tasked with closing the existing SREC market once its 5.1% goal is achieved and developing a new solar incentive program. To date, the BPU has approved an initial draft proposal for how to calculate 5.1% attainment, thus marking the end of current status quo. This draft was met with mixed reviews from solar stakeholders, so it remains unclear what the final rule will look like, although not much is expected to change. Two potential options were put forward for the transition program, but initial drafts received pushback from solar participants, especially regarding low incentive levels set for residential systems. As a result, new incentive level options were released this month.

The dialogue will now begin again to establish the final transition order. Once that conversation is closed, the BPU will move toward the successor program discussion. With so many discussions up in the air, we’ve seen build slow in New Jersey as participants await certainty on the market’s future.

Ohio - Ohio was certainly the biggest shake up in renewable portfolio standard (RPS) policy this year… and in recent history. In House Bill 6 (HB 6), the state legislature diverted money away from renewable and energy efficiency programs and toward nuclear plants. As a result, the state’s 10-year-old RPS was cut from 12.5% to 8.5% and the solar carve out, which provided separate incentives to solar technologies, was eliminated beginning in 2020. This was a blow to Ohio’s renewable market, and if the course is not corrected, Ohio risks thousands of renewables jobs being lost and falling behind its PJM peers that all seem to have ever increasing—not decreasing—renewables goals. At the end of September, the Public Utilities Commission of Ohio (PUCO) took the first steps toward implementing HB 6 by kicking off the processes for creating the mandated non-bypassable rate mechanism to provide cost recovery for legacy generation resources.

New York - In June, we saw the New York legislature pass one of the most progressive renewable energy bills in the country. The bill increases the state’s renewables goal from 50% to 70% by 2030 with a goal of 100% zero-carbon electricity by 2040. In addition to the renewables target, the bill goes further to curb carbon by setting a goal that New York will be totally carbon-neutral by 2050. These goals are certainly aggressive, and New York has its work cut out in reaching these deployment levels. According to the state Department of Environmental Conservation, 23% of New York’s electricity currently comes from renewables, including hydro. This number will need to more than double over the next 10 years and installed solar capacity will need to more than triple to meet New York’s distributed generation goals under the law. The implementation of this law will be critically important to seeing these ambitious goals successfully achieved. On the solar side, fixes may be needed to that state’s Value of Distributed Energy Resources (VDER) tariff to further the industry’s growth and make it possible to achieve those goals. Success will be a heavy lift, but New York will be an exciting market to watch over the next decade as implementation progresses.

SOLAR CHATTER

Ongoing siting and zoning issues in Maryland have led the state’s Court of Appeals to give the Public Service Commission (PSC) final say in approving power plants, allowing them to override decisions handed down by local governments. Although opponents cite the protection of agricultural land as their main argument, new research by Scientific Reports found that if solar was put on just 1% of agricultural land, it could generate enough to power the world. Watch out, ethanol.
The Solar Energy Industry Association (SEIA) has officially launched its Defend the Solar ITC campaign, building support for the extension of solar’s 30% federal Investment Tax Credit (ITC). The ITC has been the footnote on 52% average annual growth for the industry, helping create more than 200,000 jobs and bringing $140 billion in American investment. Join the fight!
Congratulations! Sol Systems customer Amazon reached its goal of hosting 50 solar energy systems by 2020 ahead of schedule. Sol Systems is proud to have worked with Amazon on some of company’s largest rooftop projects, including a 5 MW project in Carteret, New Jersey, the largest rooftop project in the Garden State. Amazon has since announced plans to build another 45 MW project in Virginia.
A report published by the North Carolina Sustainable Energy Association shows just how massive the upside is for municipalities housing large solar projects. Data taken from 50 North Carolina counties showed a 2000% average increase in tax revenue after solar was brought to the area. Sol Customer Solutions, our joint venture with Capital Dynamics, works with municipalities across the country to bring energy savings and tax revenue to local governments through solar power projects.

ABOUT SOL SYSTEMS

Sol Systems, a national solar finance and development firm, delivers sophisticated, customized services for institutional, corporate, and municipal customers. Sol is employee-owned, and has been profitable since inception in 2008.

Over the last ten years, Sol Systems has delivered 800 MW of solar projects for Fortune 100 companies, municipalities, universities, churches, and small businesses. Sol now manages over $650 million in solar energy assets for utilities, banks, and Fortune 500 companies.

Inc. 5000 recognized Sol Systems in its annual list of the nation’s fastest-growing private companies for four consecutive years. For more information, please visit www.solsystems.com

Whether tis nobler in the model to suffer / the cost and hassle of outrageous procurement expense…

As the clock ticks into the third quarter of the year, solar energy developers are increasingly confronted with a question of Shakespearean proportions: in order to preserve 4 percent additional investment tax credits (ITCs) on a project prior to the step-down in 2020, is it worth the cost and friction to take steps to incur 5 percent or more of project costs in 2019? While the mindset of the typical solar professional will be, of course, to maximize all possible benefits, it is worth pausing to consider the complexities involved in safe harboring via equipment purchases and weigh some situations when less is in fact more.

Setting the Stage
At the end of 2015, Congress passed an ITC extension and gradual step-down beginning in 2020, decreasing 4 percent per year before dropping to 10 percent in 2022 for commercial systems (or zero percent for residential). Projects will qualify for the ITC percentage in the year in which the project commences construction, and two paths are provided for meeting this standard.

First, and most logically, a project can qualify by commencing “physical work of a significant nature.” However, solar projects that have not been fully permitted or are not fully financed may not have this option. In that case, a second path is available to meet the “commence construction” standard: incur at least 5 percent of the total depreciable cost of the system in the given year, otherwise called “safe harboring.” The upside to this approach is that a project then has until the year 2024 to place in service and still maintain eligibility for the 30 percent credit. While the second path is technically simpler – it does not require activity on the site and could even be applied to projects that do not have a specific site yet identified – it forces a project developer to confront a series of meaningful assumptions.

Yet There Is Method In’t
First and foremost, expending 5 percent of a system’s total cost before financing is secured requires, well, money. More to the point, it requires access to a large balance sheet, development capital, or early construction financing tolerant of financing risk in order to make the investment. Not all project developers are blessed with large parent companies or understanding lenders. Simply determining if funds can be accessed for the purpose is often the first gating question for safe harboring a project.

The next consideration is an obvious one – 5 percent of a project’s cost must be spent, but on what? Because design work is likely not advanced enough to make procurement decisions for racking or inverters, modules are the obvious choice. While racking and inverter orders will be specific to a project’s final design, and in the case of inverters, may require utility approval, modules can be reliably integrated into a project regardless of where the final design shakes out. Just buy enough modules to exceed 5 percent of total project cost (and make sure to leave some buffer, should project size or costs unexpectedly increase) and you’re done – right? Well, perhaps. A few additional considerations must be made.

First, depending on the facts and circumstances relevant to a project owner’s accounting election, it is likely necessary to take delivery well in advance of equipment deployment and thus incur storage costs for that equipment. Costs for storing equipment (climate controlled and insured, of course) could total $0.03 per watt per year. Safe harboring modules also requires buying equipment in two separate batches months or even years apart, creating a scenario where the same module may not be available.

This second consideration is more difficult to quantify. Buying mismatched modules makes engineering more challenging and could even decrease a project’s value through production constraints. A third consideration is simple economics – module prices are currently quite high due to tariffs but also in large part to a tight market thanks to growing global demand and, ironically, this very rush to safe harbor equipment. Expending 5 percent of project costs on modules equates to around a third of a project’s total module purchase. Falling module prices over the next 12-18 months could erode some or all of the value of the 4 percent ITC preserved by safe harboring, if the developer could have alternatively purchased a large portion of the project’s modules at a lower value.

Finally, and not insignificantly, developers running a lean shop must consider if the burden on operations to analyze, bid out, finance, purchase, and store equipment in order to successfully safe harbor (not to mention the requisite legal opinions) is really worth the potential benefit. Even the most ambitious solar professional must acknowledge that one can only complete so many deals in a year – and the lift to successfully put in place a safe harboring program for a portfolio of assets is easily on par with the brain damage necessary to execute a complex purchase agreement or fund financing. If a company decides to prioritize safe harbor efforts, what other opportunities must be overlooked or compromised?

Ultimately, the question of whether to safe harbor comes down to a cost-benefit analysis. A project owner financing safe harbor procurement can and should look at a full financial model to consider factors around construction spend and timing, tax equity financing terms, and cost of capital to procure equipment early. For a developer planning to sell an asset but desiring to preserve 30 percent ITC value, however, this analysis can be very simple.

There is Nothing Good or Bad, But Thinking Makes It So
Let’s assume a 10MW project that costs $1.05/W to build can be valued for $1.55/W in a 26 percent ITC world. For simplicity’s sake, we will assume that $1.55/W is also the portion of the system that qualifies for five year accelerated depreciation, and thus forms the denominator of the 5 percent safe harbor calculation. If the developer can successfully safe harbor the system at a 30 percent ITC, they unlock an additional cash-on-cash value of $620,000, or 4 percent of $1.55/W, on a simple return on investment basis. Sounds like a no brainer, right? Well, let’s take a closer look.

To Safe Harbor...

This developer is going to assume a buffer of 2 percent on top of the 5 percent safe harbor requirement. After all, there would be nothing worse than putting in the effort to safe harbor the system, only to find out that the project size or depreciable cost increased enough to fail to qualify for the safe harbor, or force the developer to downsize the project. That means the developer must spend $1.085mm, or 7 percent of $1.55/W, to meet the safe harbor threshold. Let’s also assume the equipment must be purchased right about now given delivery timelines and increasingly tight supply as manufacturers sell out their capacity in the rush to safe harbor. And the developer won’t be paid the bulk of their construction costs for a full calendar year. Assuming a rather fair cost of capital of 10 percent, the developer will incur $108,500 of interest expense/carrying cost, plus closing costs, opinions, and fees of, say, $15,000, for a total capital cost of $123,500.

And assuming the equipment arrives year-end 2019 and cannot be deployed until the fall of 2020, the developer will have to price in at least three-quarters of a year of storage, insurance, and additional delivery costs. At $0.03/W, that’s another $225,000 of safe harbor costs. If the developer is not able to procure the same type of module and costs increase due to complexity of design, or if the developer pays a premium to obtain the same module as originally purchased, they may pay an additional cost – let’s say $0.01/W, or $100,000. Finally, we’ll make a consideration for the time and overhead incurred by this developer if professionals from their finance, engineering, and executive teams dedicate hours totaling several weeks on this endeavor – say, $16,000 total.

The argument for safe harboring does not appear quite so strong after a quick accounting of the costs involved. The overall expected benefit of $650,000 must be reduced by costs of just under $465,000, reducing total potential upside to $155,000. Was that really worth the hassle?

Or not to Safe Harbor...

Still, the benefit may be there for a developer, especially one with a robust team and significant pipeline sufficient to justify the effort – save for one factor. Critically, module prices are unusually and unjustifiably high. We know that availability is limited due to a rush to safe harbor, global market dynamics affecting price and availability, and tariffs driving prices up further. It is highly likely prices will fall in the period between the purchase of safe harbor equipment and the point at which that equipment would normally have been purchased for that project. In fact, in this scenario, module prices would only have to drop by 15 percent to completely erode the safe harbor benefits so hard won by the developer’s efforts. Any additional efficiency gains in modules on the market one year from today, either due to pure yield gains or balance-of-systems efficiencies from increases in module power class would further increase this gap.

Erosion in Benefit

To Thine Own Self Be True

In the end, the decision of whether or not to safe harbor will be a highly individualized one specific to each project and developer. Obviously, valuing the project on the basis of internal rate of return that accounts for the time value of money of ITCs received in the first year of an investment will show more benefit than an ROI view. Certain advantages related to cost of capital, procurement or storage terms, and the overall ease and speed at which a developer can put these measures in place may greatly improve the cost-benefit analysis. We simply make the case above to illustrate that safe harboring for a project is by no means a foregone conclusion, or even necessarily a net benefit on an ROI basis. Often the hardest decisions made on a project are those to forego an opportunity to maximize benefit, since the one constraint we can apply to all projects with certainty is the number of hours in a day. The question for solar developers is how to use them.

This is an excerpt from the Q2 2019 edition of The SOL SOURCE, a quarterly electronic newsletter analyzing the latest trends in renewable energy development and investment based on our unique position in the solar industry. To receive future editions of the journal, please subscribe.

ABOUT SOL SYSTEMS

Over the last 11 years, Sol Systems has delivered 800 MW of solar projects for Fortune 100 companies, municipalities, universities, churches, and small businesses. Sol now manages over $650 million in solar energy assets for utilities, banks, and Fortune 500 companies.

Inc. 5000 recognized Sol Systems in its annual list of the nation’s fastest-growing private companies for four consecutive years. For more information, please visit www.solsystems.com

The Sol SOURCE is a monthly journal that our team distributes to our network of clients and solar stakeholders. Our newsletter contains trends and observations gained through monthly interviews with our team, and it incorporates news from a variety of industry resources.

Below, we have included excerpts from the August 2018 edition. To receive future Journals, please subscribe or email SOURCE@solsystems.com.

STATE MARKETS

Illinois – At long last, we have an estimated start due for the Land of Lincoln’s rooftop, community solar, and distributed generation programs, also known as the Adjustable Block Program (ABP). The ABP, first envisioned with the passage of the Future Energy Jobs Act in 2016, will go live on January 15, 2019.

With the date set in stone, customers now have a firm deadline for bringing their projects to the finish line and attempt entrance into the lucrative first block. The ABP is structured so that early adopters get the highest incentive rate, so for customers on the fence about pursuing solar in Illinois, time is money.

While a launch date is confirmed, still up in the air is the fate of participation by municipalities in the ABP, which is being appealed by ComEd. The utility filed an appeal of the ICC’s final plan order which had allowed projects located in municipal utilities or co-ops to participate in the Adjustable Block Program. The result of ComEd’s appeal will be critical for prospective municipal customers.

In legislative news, on August 10, the Illinois legislature passed critical property tax legislation. This bill, SB 486, provides a standardized approach for valuing solar property, instead of leaving it up to each county assessor to provide valuation. Given how critical property taxes are in emerging markets, Illinois joins a select few states who will benefit greatly from passing proactive legislation to clear up any issues in this area before the market takes off. Governor Rauner signed the bill on August 14.

2019 will signal both a new year and a new age for Illinois renewables. Are you ready?

New Jersey – When it comes to clean energy, and solar specifically, the New Jersey Board of Public Utilities (BPU) certainly has a lot on their plate over the next few months, and maybe even years. With the passing of A-3273 by the legislature, the horse has left the gate and the BPU has begun racing to meet key regulatory deadlines set out within the legislation.

Under this bill the BPU is now responsible for strategizing how to close the existing solar renewable energy credit (SREC) program while simultaneously developing a successor program that will go into effect after the current 5.1 solar percent carve-out is projected to be reached in 2021.

On August 6, the BPU took the first step in the rulemaking by sharing a proposal detailing how to close the SREC program. As proposed, no new registrations may be submitted once that goal is hit, and the closing date is set for no later than June 1, 2021.

Within this timeline, the BPU has 24 months from the signing of the bill in May to develop a proposal for the current SREC program’s replacement. The closing of the SREC market is only the appetizer for what is on the BPUs plate when it comes to clean energy. Over the next year and change, the BPU will have to design a community solar pilot program, organize studies on energy savings targets and distribution systems, along with other ongoing rulemakings regarding wind and storage technologies. This dedication is why New Jersey solar energy ranks fifth in the country and employs over 7,000 residents. We wish the BPU the best of luck with these proceedings, and encourage solar stakeholders to get involved in seeing these policies through to implementation.

Connecticut - In May, the Connecticut state legislature passed the hotly contested SB9, a bill that the solar industry was both for and against due to mixed policies within the legislation itself. The legislation calls for an increase to the state’s renewable portfolio standard to 40 percent by 2030 and even follows in the footsteps of other northeastern neighbors in adopting a community solar program. It also extended the low emission renewable energy credit (LREC) and zero emission renewable energy credit (ZREC) programs for an additional year. While this year was supposed to be the seventh and final year, there will now be a procurement for an eighth. By September 1, 2018, the Public Utilities Regulatory Authority (PURA), with help from the Department of Energy and Environmental Protection (DEEP), must initiate a proceeding for a new procurement program aimed at encouraging the continued strides towards renewable expansion in the state after the existing program ends.

However, this same legislation that outlined these provisions also essentially removed net metering guarantees, one of the key drivers of development. This mix of good and bad news has left some uncertain about future development opportunities in Connecticut. Implementation will be key, and advocates must ensure that the new program will fill the gap left by net metering.

SOLAR CHATTER

Hot dam! The Los Angeles Department of Water and Power released a $3 billion plan to essentially make the Hoover dam function as a massive battery for wind and solar. The plan involves building a pipeline from wind and solar projects to a pump station south of the dam on the Colorado River that would pump water to Lake Mead to be stored and turned into electricity by the dam. The project has many obstacles to overcome but represents one of the more creative ideas to store renewable energy to date.
After the last 4 or 5 years, the solar industry needs to crack the code on figuring out another way to say that we’ve “cracked the code” for the commercial and industrial market. Oh wait, did we say that too? (see paragraph 5).
In a recent study by GTM Research (now Wood Mackenzie Power & Renewables) aimed at finding an eventual price floor for solar bids, the firm, “in an optical view,” sees $14.7/MWh as the floor for projects, which they expect could be reached by 2022. We’ve already seen low bids for 2023 projects that will replace two decommissioned coal plants in Colorado, with a median price of $28/MWh. Whether this aggressive prediction will come to pass is unknown, but the idea of $14/MWh solar is certainly a thought to behold.
Billionaires are waging war of words over a Nevada ballot, Question 3, that is proposing a state constitutional amendment to allow consumers to pick their own power provider by 2023. The ballot initiative, backed by casino mogul Sheldon Adelson, is facing harsh opposition by Warren Buffett-backed utility NV Energy, who has threatened to cease operations and leave the state if the proposal becomes law. Given the costs associated with the consequences that NV Energy is threatening, many clean energy groups are uncharacteristically arguing against voting for consumer choice, as it would hurt the progress they’ve made thus far with NV Energy. As would be expected in a battle where both sides are backed by billionaires, $14 million combined has already been spent on the fight.

ABOUT SOL SYSTEMS

Over the last ten years, Sol Systems has delivered 700 MW of solar projects for Fortune 100 companies, municipalities, universities, churches, and small businesses. Sol now manages over $650 million in solar energy assets for utilities, banks, and Fortune 500 companies.

Inc. 5000 recognized Sol Systems in its annual list of the nation’s fastest-growing private companies for four consecutive years. For more information, please visit www.solsystems.com

As anyone following the solar industry understands, the costs of installing solar photovoltaic systems have declined dramatically and consistently over time. Despite massive cost declines over the years, solar PV systems today look a lot like solar PV systems installed a decade ago. This is because iterative improvements to existing technology have historically dictated cost declines in the solar space. Each major component of solar systems becomes cheaper and more efficient, and in turn, modules become cheaper on a dollar-per-watt basis and contain more watts per module.

The increased use of single-axis trackers, which rotate modules to track the sun throughout the day, is one of the most important of recent shifts in solar technology and represent the area where systems do look different than a decade ago. Trackers have helped decrease the levelized cost of energy (LCOE) for ground mount arrays by increasing yield from the same number of modules Another promising technology, bifacial modules, which offer the ability to capture energy from light reflected off the ground through the back side of the module, have struggled to find the same level of adoption. However, a combination with single-axis trackers may signal the most efficient use of the technology in its current form.

The Current State of Bifacial

As we’ve written in the past, bifacial modules can substantially increase a system’s yield, but estimates of the benefit vary widely. One leading manufacturer, LG, claims a 5-30 percent increase in production compared to standard modules. This wide range is due in large part to the widely varying albedos, or reflectivity, of the surfaces above which systems are installed. Highly reflective surfaces such as sand or snow can offer ideal results for bifacial systems, but the system configuration is important as well, as there also needs to be space between array rows for that light to reflect off the ground. The modules also benefit from being higher up from the ground than normal, as more light gets reflected to the back side of the module. While all of these factors impact monofacial system design to some extent, they are much more important to bifacial systems, and may change what would be the optimal system design.

Evaluating Bifacial Trackers

Single-axis tracking systems represent one of the more intriguing opportunities for bifacial modules. The benefits of tracking system design have already been thoroughly proven as the preferred method of providing the lowest LCOE in the utility-scale market for most geographies and site types, as its utility-scale market share now approaches 80 percent. With these strong fundamentals over fixed-tilt systems, it’s only natural to look to improve upon that existing benefit with increased yield from bifacial modules. While tracking systems’ bifacial gains may be slightly reduced compared to fixed-tilt systems due to the fact that they face the sun more directly, they also benefit from a low ground-coverage ratio, typically 30-40 percent (compared to 50 percent for fixed-tilt systems). Simply put, the extra space means more light hits the ground than it does for other system types, and provides more opportunity for light to reflect towards the energy producing back side of bifacial modules.

Leaders in the tracker space that have tested the scenarios have been supportive of the idea. Dan Shugar, CEO of NEXTracker, the largest producer of tracking systems in North America, told PV Magazine “the bifacial tracker is one of most exciting untapped opportunities in the solar industry. There will be a huge drive toward this.” In one test done by NEXTracker using both standard and bifacial modules on trackers reported gains of 14-17 percent for the bifacial units.

Can it Work?

Though trackers have found their market and the price premium for bifacials has dropped to below 5 percent, the lack of data is still hindering bifacial technology. The wide range of new factors affecting energy production and low rate of adoption make it significantly harder to model production for bifacial modules. Without a track record of reliable performance, investors, developers, and customers will naturally show skepticism of the approach. This lack of bankable information makes it difficult to achieve the scale of capacity that could alleviate the concerns. Concerns shared by engineers at Sol Systems include:

The effects of uneven light on modules are poorly understood. Solar systems with bifacial modules will have partial shading on the backside due to the structure of the system. This uneven shading will reduce production, and the magnitude of the effect is currently poorly understood.
The structures used to support modules are highly evolved and trusted by the industry and investors, but have also been designed with minimal thought to the back side of the modules. Racking structures that minimize this back side shading are just starting to be released, and need to gain acceptance by the industry.

Bifacial modules will necessarily have slightly different constructions than standard modules, as all bifacial modules will have either a backsheet made of glass or a transparent polymer. Glass-glass modules show promise for reducing degradation, but also pose different and new risks, and transparent polymers are also a new product that does not have as extensive of field testing as traditional backsheet materials.

Given the inherent problems of needing scale to build trust in the technology and the need for trust to build that scale, it will take some calculated risk taking by developers and customers to build more field data for bifacial modules and those on trackers. However, with the large potential for LCOE reductions that a bifacial tracker system could produce, it’s something surely to excite engineering geeks in the coming years.

This is an excerpt from the June 2018 edition of The SOL SOURCE, a monthly electronic newsletter analyzing the latest trends in renewable energy based on our unique position in the solar industry. To receive future editions of the journal, please subscribe.

ABOUT SOL SYSTEMS

Over the last eight years, Sol Systems has delivered 700 MW of solar projects for Fortune 100 companies, municipalities, universities, churches, and small businesses. Sol now manages over $650 million in solar energy assets for utilities, banks, and Fortune 500 companies.

Inc. 5000 recognized Sol Systems in its annual list of the nation’s fastest-growing private companies for four consecutive years. For more information, please visit www.solsystems.com.

Greenfield development, either through utility-scale solar or smaller commercial solar arrays on properties of vacant farmland, schoolyard fields, and wastewater treatment facilities has grown rapidly, earning solar the nickname of the "new row crop." Solar’s growth has provided new income for landowners, has led to the creation of an industry that now employs over 250,000 people in the U.S., and is critical for reducing our reliance on fossil fuels.

Despite the positive economic, social, and environmental benefits of solar energy, arguments against the use of any ground-mounted solar, that it will harm ecosystems or reduce the amount of available farmland, are still being made. Some are concerned that allowing solar on agricultural land will encourage an overproduction of energy and underproduction of food. Others, including many landowners, see solar as a way to hold on to family-owned land by securing long-term, consistent revenue through a land lease instead of uncertain income based on crop yields. Not to mention, solar supports pollinator-friendly habitats, which show that 95% of the vegetation around a solar farm can be preserved.

Still, concerns over land use and solar are surfacing in new markets like Illinois, where legislation has been introduced to require Agricultural Impact Mitigation Agreements (AIMA) for all solar projects above 500kW. These requirements already exist for wind projects in the state, but wind projects have to be on open land, while solar projects don't need to be and are require less space. We'll see how this one plays out in the coming months.

Pushback against ground-mounted solar is nothing new for the industry. Sol Systems has previously analyzed the various conflicts over land use and solar development, including the rise of Certificate of Public Convenience & Necessity (CPCN) requirements in Maryland and limits to ground-mounted solar in New York. More recently, the SMART program in Massachusetts has discouraged ground-mounted solar through a greenfield subtractor for ground-mounted projects. The program has also encouraged alternative forms of solar projects through adders for rooftop, carport, and even floating solar.

Carports: Turning Existing Space into a Solar Power Plant

While land use will continue to be an issue for the solar industry in ground-mounted projects, advances in solar canopy, or carport, technology has created opportunities to avoid the conversation on land use altogether. Parking lot owners can add a canopy covered with solar panels to their lot, providing shade and snow or rain cover for parking users. Additionally, carports allow a property owner to maximize the value of space that is currently set aside for parking without losing the area's existing functionality.

While an appealing option, especially for those concerned about greenfield development, carports are expensive, as they require additional steel structuring. Still, states can encourage carport incentives to balance land use concerns in the design of their solar programs. One of the best incentive landscapes for carports has been in Massachusetts, where carports have been explicitly incentivized through a $0.06 tariff adder. Though Massachusetts may not be the cheapest place to build carports given the need to withstand significant snow loads, the SMART carport incentive shows the Department of Energy Resources’ (DOER) continued commitment to encouraging the use of carports; they also provided an extra incentive for carports under SREC II, their preceding incentive regime.

Designing a Good-Looking Carport to Fit a Customer’s Needs

Even when you set aside the additional costs of a carport, many potential solar carport customers have raised questions about the aesthetics and operational impact of carports. Fortunately, there are many ways for a solar developer to fit the carport project to the needs of the site and customer. For Class A real estate buildings, aesthetics are always a priority. Aesthetic customization for carports includes decking on the underside of the carport to display a company's logo, custom column colors, and premium finishes like powder-coating on the columns. While these premium carport features come at a higher price, they are a great way for Class A real estate properties to go solar while maintaining their aesthetic standards and offering tenants parking amenities like shade, snow protection, and LED lighting at night.

Carports: Operational Concerns

[caption id="attachment_5723" align="alignright" width="300"] Photo credit: UMass Amherst[/caption]

On the operational side, most property owners have questions about snow removal, re-paving the parking lot, and maintaining the number of parking spaces. In Massachusetts, there are a few ways to handle snow-related challenges, including a snow guard and dual-tilt or "y-shaped" canopies. With a guard, any snow that lands on the carport will remain there until it melts, and the guard prevents it from falling onto the parking lot in a sheet. A dual-tilt canopy allows the snow to collect in the middle of the canopy, where it can melt. Sol Systems has used dual-tilt canopies at our recently-completed project at UMass Amherst (pictured here). For customers who are concerned about water management, the carport can also be equipped with gaskets to divert any snowmelt from the canopies.

What Happens if I Need to Re-pave My Parking Lot?

When customers ask about repaving their lots, they are often concerned that canopies will preclude them from repaving or that the process will be more onerous once canopies are installed. The experience from our engineering and delivery team has been that the parking surface can be replaced once carports are installed because carport clearances can allow large vehicles to pass underneath. Plus, if the lot is resurfaced after the installation, the parking lot will be the most aesthetically-pleasing with brand new carports and a freshly-paved surface.

Finally, though many customers are concerned about losing parking spots to a carport project, carport projects maintain parking capacity, rather than decreasing it. Carports are installed in line with the existing parking rows, and columns are placed similarly to a lamppost, so they don't preclude cars from parking in a spot.

Overall, though carports are sometimes viewed as a hassle, they are a great way to increase utility in an area that property owners may not have previously considered. Have a parking lot you're interested in leasing? Contact us at anna.noucas@solsystems.com.

This is an excerpt from the February 2018 edition of The SOL SOURCE, a monthly electronic newsletter analyzing the latest trends in renewable energy based on our unique position in the solar industry. To receive future editions of the journal, please subscribe.

ABOUT SOL SYSTEMS

Over the last nine years, Sol Systems has delivered 650MW of solar projects for Fortune 100 companies, municipalities, universities, churches, and small businesses. Sol now manages over $650 million in solar energy assets for utilities, banks, and Fortune 500 companies.

Inc. 5000 recognized Sol Systems in its annual list of the nation’s fastest-growing private companies for four consecutive years. For more information, please visit www.solsystems.com.

This is an excerpt from the October 2017 edition of The SOL SOURCE, a monthly electronic newsletter analyzing the latest trends in renewable energy based on our unique position in the solar financing space. To receive future editions of the journal, please subscribe.

In December 2016, Governor Bruce Rauner of Illinois signed the Future Energy Jobs Act (FEJA), one of the most exciting, robust pieces of renewable energy legislation that the industry has seen in the past several years. Thanks to FEJA, Illinois will soon be home to a top 10 solar market under programs such as an Adjustable Block [similar to Massachusetts SMART or New York’s Megawatt Block] for projects under 2MW, community solar, a utility-scale market for projects over 2MW, and Solar for All, a new low income solar and workforce training program.

While FEJA was signed into law in December, the effective date – or the official starting date for implementation – began on June 1. In the spring, the Illinois Power Agency (IPA) held technical sessions on key topics for implementation and issued questions for comment. Then, after careful due diligence, the IPA issued its Draft Long-Term Renewable Resources Procurement Plan at the end of September.

Overview for Today

Given that Sol Systems develops and finances distributed generation and small utility-scale projects, today we will focus on the Adjustable Block Program (ABP), which also includes community solar. For information on Solar for All, brownfield, utility-scale solar, and wind programs, please reference the 169-page document. Residential solar is included in the ABP but not discussed in this piece.

It should also be noted that the Illinois Power Agency does not have jurisdiction over the $250/kW Distributed Generation rebate and the community solar tariffs. Those proceedings are under the jurisdiction of the Illinois Commerce Commission and not included in the Plan.

Adjustable Block Program

The ABP will encompass all projects under 2MW, including community solar. Projects in the ABP will be awarded 15-year fixed price REC contracts, with 20% of the contract amount paid out at interconnection, and all subsequent REC payments paid out over a 4-year period. Claw-back provisions and collateral requirements will be put in place to ensure delivery still occurs in years 6-15 when developers are not receiving any payout.

The ABP, unlike competitively-bid procurements that IPA has typically run in the past, has a fixed price per MW block of volume. After the volume has been hit, projects will be subject to lower pricing in the subsequent block, and so on. The goal of the ABP is to procure 1,000,000 RECs by May 2021, which IPA estimates that will equate to about 666MW by the same time

Drawing on best practices from other states such as Massachusetts, the smaller utilities are designated with smaller capacity per market segment (22MW for each residential, commercial, and community solar), and ComEd, Mid-American, and the municipal utilities are designed 52MW per market segment per block.

We like that the IPA did not choose to “over-carve” each block among the different market segments. For example, instead of allocating specific MW capacity for varying project sizes within the “large” project designation of 10-200kW, they keep the MW allocation under the same bucket, instead allocating varying incentive levels to market segments 10-100kW, 100-200kW, 200-500kW, and 500kW -2MW. Simplicity here is key, especially because given the lackluster performance of projects in the sub-500kW commercial space nationwide, projects of this size would unlikely meet the demand of the program. Instead, market forces – not prescription – will guide what size projects are built in Illinois.

Based on our calculations, the pricing will need some tweaking. For example, in its modeling, the IPA assumes a much higher value of energy than in reality in its CREST model. In the CREST model, IPA is including weighted portions of $/kW charges in its “Value of Net Metering Credits” calculations. The modeling also does not seem to account for potential discounts to energy rates that customers may be getting via competitive suppliers. Still, with some minor tweaks, this program is looking strong, and we applaud the IPA for its careful diligence. The draft pricing is as follows, and is subject to change.

Room for Change

One of the strongest pieces of this plan is IPA’s clear desire to get the program rolling, see how it works, and make changes later if necessary. For example, because this draft plan covers procurements and proposals to be conducted in 2018 and 2019, and that the plan is subject to a biennial review process; the IPA will have room to make changes if pricing for a given market segment is too high, or too low, or if some other aspect of the program doesn’t seem to be working. Given the pending Suniva trade case, the federal investment tax credit stepdown, and the fact that the $250/kW DG rebate will change in value once 5% net metering penetration is hit, the IPA understands that pricing may need to be adjusted accordingly as these factors come into play. Even before the next plan is drafted, IPA will monitor program activity and could make other minor tweaks six months after launch if necessary.

Community Solar & the ABP

It should be noted that community solar projects – which may also be up to 2MW in size – will also fall under the ABP under the same REC contract structure. During the IPA workshops this spring, there was heated debate around two specific points on community solar: colocation and residential vs. commercial subscribers.

Many lessons learned were discussed from other community solar states, namely Minnesota, the closest to the Land of Lincoln. In Minnesota, colocation was prevalent at first, and most of the subscribers of the program were commercial and industrial (C&I) customers, not residential. While some may argue that this is not in the true spirit of community solar, in terms of megawatts installed, Minnesota has been very, very successful, with over 100MW to date, and over 300MW more in progress or under construction per Xcel’s website. And unfortunately, to date, programs with more onerous subscription requirements have underperformed.

Taking into account the best practices – and cautionary tales – from other states, IPA has come up with a strong compromise that will promote robust residential participation, a requirement in the law. They do this by giving a higher REC value – an adder – to projects that have residential subscribers. Like in the block pricing design, IPA tries here not to be too prescriptive and let the market decide the types of projects that will be built.

As for colocation, 2MW may be installed on a given parcel. Projects owned by a single entity on one parcel of land or contiguous parcels of land will be added in the aggregate and be treated as one system under the ABP. However, projects on contiguous parcels of land that amount to over 2MW may be allowed if they are owned by separate entities, and they must have separate interconnection points.

Schedule for Release

Comments on the Long-Term Renewable Resources Procurement Plan are due on November 13, and the Plan is expected to be approved by the Commission by early April 2018. After that, it will take a couple months more to get the program off the ground and hire a Program Administrator. As such, a summer 2018 launch is still possible.

Conclusion

We applaud the IPA for their diligence on best practices and lessons learned from other states, and we are oh-so-excited for this program. With some minor tweaks, the Illinois solar market will be ready for takeoff next summer. Are you ready?

ABOUT SOL SYSTEMS

Over the last eight years, Sol Systems has delivered 650MW of solar projects for Fortune 100 companies, municipalities, universities, churches, and small businesses. Sol now manages over $650 million in solar energy assets for utilities, banks, and Fortune 500 companies.

Inc. 5000 recognized Sol Systems in its annual list of the nation’s fastest-growing private companies for four consecutive years. For more information, please visit www.solsystems.com.

Tag: The SOL SOURCE

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