Not all inverters are created equal, or equally cost-efficient, when designing residential and commercial solar projects. We see contractors choosing between microinverters and various string inverters, but not always knowing when you might end up paying a price premium. Sometimes a sizable one.
We recently worked on some system designs that led us to take a closer look at breakeven points for seven well known inverters.
SMA SunnyBoy 7.7
SMA TriPower 12000TL
SMA TriPower CORE1 62
One commercial project used 50 Enphase IQ7+ microinverters. There’s no question the contractor could have found string inverters at a lower cost. Could the additional cost be offset by a lower-cost installation? Or more energy over the life of the system? That depends in part on how far the project has gone past the inverter breakeven point.
Tradeoffs are part of solar design. But it would help to know based on current market prices where one inverter system becomes more expensive than another.
It’s time to run some numbers. Let’s find out what size system, and how many modules, it takes for contractors to favor SMA, SolarEdge or Enphase based on cost alone. I chose the LG LG350N1C-V5 (350 Watt) module as the control for all inverter options. Why? Its popularity and feasibility for residential and commercial projects.
Here are the key takeaways. Read on for more details.
For systems with 11 modules or more, the SMA 7.7 has lower cost than the Enphase IQ7+.
With 14 modules or more, SMA’s 7.7 with TS4-R-F Rapid Shutdown Devices (RSD) devices becomes less expensive than the Enphase IQ7+.
19 modules or more? The SMA 12000TL without optimizers or RSD devices becomes cheaper than Enphase’s IQ7+.
With 42 modules or more, SMA’s TriPower CORE1 62 has lower cost than the Enphase IQ7+.
For systems with 52 modules or more, SMA’s TriPower CORE1 62 becomes less expensive than the Enphase IQ7+.
With 54 modules or more, SolarEdge’s SE-66.6K becomes cheaper than the Enphase IQ7+.
The Enphase IQ7+ has lower cost than the SolarEdge SE7600 with optimizers and SolarEdge’s SE11400H.
How I crunched the numbers
I found all prices on thepowerstore.com except the combiner panel for the Enphase IQ7+. That one I priced at homedepot.com.
Enphase uses one IQ7+ microinverter per module and one AC Combiner Box. SolarEdge uses as many string inverters as needed based on the combined DC output of the module array, plus one power optimizer per module. SMA uses as many string inverters as needed based on the combined DC output of the modules.
The SMA SunnyBoy and TriPower CORE1 series inverters have SMA’s proprietary ShadeFix technology. ShadeFix, based on the OptiTrack software released in 2010, allows current to bypass shaded areas of solar modules. This keeps current high for non-shaded areas.
SMA ShadeFix is built into the inverter. Optimization gains are comparable to SolarEdge optimizers and Enphase microinverters in zero-to-moderate shading with no additional components, keeping costs lower. However, in heavy shading, SolarEdge and Enphase have slightly better optimization gains. Consider cost, ease of installation, shading, and other factors when choosing an inverter for any system.
SMA inverters used to require rapid shutdown devices under each module, plus a CCA datalogger, safety control unit, and communication gateway. This added cost. SMA ShadeFix has simplified and reduced the cost of systems with optimization.
Also worth mentioning, SMA no longer manufactures the TriPower 12000TL. It’s only available from suppliers who still have units in stock. SMA’s TriPower 12000TL does not have ShadeFix. Nor the option to add optimization. I added it primarily as a direct comparison to the SolarEdge SE 11400H.
Plotting equipment costs and module count in a line graph, you can see Enphase has the lowest cost in systems with 10 or fewer modules. It has one of the highest costs with 55 modules or more.
100A AC Combiner panel
SunnyBoy 7.7 (41)
TriPower CORE1 62
TS4-R-F RSD Devices
The takeaway: size matters. The larger the project, the less cost-effective microinverters become. Cost, however, is not the only factor.
Data for informed decisions
Contractors might prefer how modules preinstalled with microinverters can speed up and simplify installation. Other benefits include monitoring, panel-level optimization, safety, and warranties up to 25 years.
Contractors might dislike microinverters because they limit the number of modules on a string. They also have worse voltage drop than a string inverter system of similar size.
At the same time, the industry leaders, including these three, are all moving toward integrated systems with storage and energy management. Looking ahead, how might decisions today affect future upgrades and system performance?
The point is not to suggest one inverter system is better than another for any one system design. Consider many variables.
First, set the top priorities for a project—cost, performance, ease of installation, resilience. Then figure out what kind of inverter will best support short- and long-term goals.
Different projects will pencil out differently. But comparing inverter costs can help you and your customers make good decisions for your projects.
Solar Renewable Energy Credits can generate thousands of dollars in revenue. But for many investors, the idea of actually trading SRECs for cash has often been a little too good to be true.
Here’s how you can get paid for Solar Renewable Energy Credits.
First plan a solar project in a state with a Renewable Portfolio Standard, a state policy requiring that some percentage of electricity comes from renewable resources.
After that, be sure your state has a solar carveout, requiring that some of the electricity comes from solar.
Then learn a sometimes complex process for adding your project to the SREC marketplace and offering SRECs for sale.
Lastly, keep your fingers crossed that SREC values don’t crash due to oversupply or an abrupt change in state policy.
All in all, SRECs have been an important catalyst and a continuing revenue source for some investors. But SRECs have also proven relatively ineffective at pushing markets past the early stage of development.
Here’s a roundup of recent SREC market developments.
In 2020, Delaware’s solar requirement calls for 2.25 percent of electricity generation to come from solar. The requirement has been increasing by a quarter percent per year since 2015.
Net generation in Delaware is 6,240,644 megawatt-hours. Since producers get 1 SREC for each 1 megawatt-hour of output, Delaware has a market for about 140,400 SRECs, representing the output of roughly 100 MW of solar.
The 2019 auction yielded relatively low prices of $10 to $50 per SREC. Producers sold a total of 15,171 SRECs through the 2019 procurement.
Information on the 2019 SREC solicitation was released in May. Bidding started in late June and closed in early July.
In Illinois, the solar requirement amounts to roughly one-half a percent of net generation.
According to a local news report, solar power producers in Illinois receive 15 years of SREC payments upfront, when the system is installed. But SREC values go down as more systems are installed.
In 2019, the Maryland Clean Energy Jobs Act increased the state’s Renewable Portfolio Standard to 50 percent by 2030 with a solar carve out of 14.5 percent. The solar carveout is 6 percent in 2020. Then it increases to 7.5 percent in 2021. And an additional 1 percent each year until 2028.
While producers oversupplied the SREC Market in 2019, SRECTrade, a marketplace administrator, forecasts marginal undersupply in 2020 and a growing undersupply over the next three years.
Unlike SRECs sold in long-term contracts, Maryland SREC values change with market conditions. Two years ago, they were trading at about $10. Now, they’re trading at about $75.
SREC values are hard-capped by the value of alternative compliance payments that utilities must pay if they fall short of solar procurement goals set in renewable portfolio standards. As alternative compliance payments go down, so do SREC values. In 2020, the alternative compliance payment in Maryland is $100. Through 2028, it will drop gradually to $25.
By 2019, Massachusetts had closed its SREC program to new projects and replaced it with the SMART program. The SMART program offers a performance-based incentive issued in the form of utility bill credits for each kilowatt-hour of energy produced.
In 2019, New Jersey moved to phase out its SREC program. But in 2020, the state government opted to preserve funding for SRECs until a new incentive program is in place.
In 2019, Ohio approved legislation that eliminates the state’s renewable portfolio standard in 2026 and wipes away the solar carveout this year. As a result, solar projects that previously generated SRECs no longer generate SRECs. The change applies to projects in Ohio and five other states that could sell SRECs into the Ohio market: Indiana, Kentucky, Michigan, Pennsylvania and West Virginia.
The future of the SREC market in Pennsylvania depends on SB 600, a legislative bill that would require 30 percent of the state’s electricity to come from renewables by 2030, including 10 percent from in-state solar. Current policy includes a half-percent solar carveout through 2021. But there’s no solar carveout for subsequent years.
California contractors, tell us truthfully: when is the last time you sat down and read the interconnection procedures for generation and energy storage systems enshrined in Rule 21?
We get it. People who go to work in the solar and storage industries usually are driven to put more renewable energy on the grid. You didn’t sign up for reams of bureaucratic paperwork. The Cliff’s Notes will do just fine, right?
We’ve got you covered. As you’ll see in today’s video conversation with Senior Design Engineer Taylor Bohlen, we’re genuinely excited about Rule 21. We’ve reviewed the source material and broken it down to a 12-minute summary.
Follow along to learn about some of the biggest mistakes we see people make in the Rule 21 process, and how net energy metering for energy storage systems furthers the essential goal of Rule 21, improving power management on the grid.
Josh Weiner: Hello, everyone. My name is Joshua Weiner. I’m here with Taylor from SepiSolar. We’re here to talk about Rule 21. Why it’s important. Why should you care. What’s involved. Common pain points. Lessons learned. I’m really excited to be meeting with Taylor because Taylor has been an engineer with us for how long?
Taylor Bohlen: Just about three years. A little over.
Josh: Awesome. And in that time, you’ve been doing design and engineering on various systems, right?
Taylor: Absolutely. Came in and started doing residential and quickly moved into the commercial world. And have been there ever since.
Josh: Awesome. And only just a couple of weeks ago, you gave this awesome presentation internally at SepiSolar about Rule 21 and how it’s important. I just loved what you presented. And I want us to be able to share it with our audience here because I feel like Rule 21 is this rule that governs almost all of our lives in some form or fashion as being solar guys or storage guys or microgrids. We’re interconnecting these systems into the utility grid on a regular basis. And I don’t know that many people have actually read it.
Before this, had you read Rule 21?
Taylor: No, I hadn’t actually dug through it with a fine-tooth comb. It’s about a little over 250 page document. So it’s definitely a significant read. But it’s one of those documents that pretty much governs every single system we’re putting into place here in California. So it obviously has a large impact on everything we do on a day-to-day basis.
Josh: I got to ask, how long did it take you to get through the 250 pages of Rule 21?
Taylor: You know, taking notes and getting everything together took about a week of solid reading and organizing and making sure I understood all the legalese that is the governing style of the document.
Josh: Yeah. I remember your summary of the 250 pages was itself like a 50-slide PowerPoint deck. Does that sound about right?
Taylor: Yeah. It was definitely a significant PowerPoint.
Josh: So let me just ask: Why should we care about Rule 21? Or who should care and why should they care?
Taylor: You know, I think pretty much everyone who touches the solar industry really has a vested stake in what Rule 21 has to say. Whether or not you’re a financer or a contractor trying to construct one of these systems. At the end of the day, your goal is to get permission to operate from the utilities so that you can cycle your system and start making value for your clients. And if you’re the person that’s installing the system, you obviously want to get it ready to go as soon as possible so you can start realizing the value that is available to you through solar energy.
Josh: And Rule 21, just for definition’s sake, governs pretty much any generator that needs to interact or interoperate with the utility grid, right? So Rule 21 doesn’t just cover solar, it covers tidal and hydro and fuel cells. Things like that, right?
Taylor: Absolutely. Pretty much any generating technology that’s available on the market. Rule 21 itself is all about interconnections to the grid under the context of generation.
Josh: Got it. What prompted you to even go down this path and explore Rule 21 to begin with? Was there something specific that happened either internally with SepiSolar. Or from something you experienced outside that prompted you to go and research this and report it?
Taylor: I think that engineering has such an integral piece to play with regards to both the interconnection process, but also creating the systems as a whole. And it felt like a good time to be able to pull together our engineering expertise and use that to leverage the ability of our clients to be able to get interconnection completed in as expeditious a manner as possible while making sure that everything is correct and complete and ready to go so that systems can operate as quickly as possible.
Josh: To that point, as quickly as possible. My experience of hearing you speak about Rule 21 was that it didn’t feel like a very quick process at all. It’s 250 pages for a reason. There is a lot of processes and sub processes. And I feel like you need this tree-branch chart that, you know, “if A then B.”
Can you talk a little about, is Rule 21 simple or complex? And if complex, how and why is it so complicated?
Taylor: Absolutely. I would say it’s very complex and there’s a lot of different, as you were alluding to, a lot of different avenues that projects can take depending on sizes, engineering constraints, and things on the utility side that can affect the systems. So it’s very important to delve into it and understand how the choices that you’re making with your projects can influence the system.
Especially given the context of moving quickly, it’s really important to essentially start this process and get yourself into the engineering queue for the utility as quickly as possible so that you can parallel as many of the processes that you have to do at the same time in order to get a system interconnected and make sure that you’re working as efficiently as possible, both for your own internal business as well as for your downstream clients.
Josh: So is that the bottleneck? Just getting submitted, like getting into the process so you can start going down this cascade of various steps and reviews that you have to go through to get any kind of interconnection approved?
Taylor: Absolutely. There’s something called the queue that the utility maintains, which is a really important piece of the puzzle that people often overlook and have been known to miss. A lot of people think that submitting an application is starting the process. When in fact, if you’re not submitting an application that’s complete and valid, you can add up to 20 to 25 days onto the entire process of getting interconnection.
Josh: OK. I know we get this a lot at SepiSolar. People are like, here are my utility bills. Here’s the information you need. Get it submitted right away. Quick, fast, fast, fast! That makes a lot of sense. We’re always in a hurry to get things going as quickly as possible. But what’s the problem with that? What could go wrong if you go too quickly?
Taylor: Absolutely. The utility explicitly within Rule 21 puts a premium on making sure that your information is complete and accurate the first time. So if you’re submitting an application, the utility’s got ten days to review the information. And if they deem that you’ve submitted everything correctly and your application is complete, then you get put into the queue at the day that you submitted.
If you don’t have everything complete and valid, they get that whole ten-day period to respond. Then you have to furnish the additional information. Then there’s another ten-day period for them to review. And then at that point, when they decide that you’re all set to go, you get placed in the queue when they make that decision. So there’s at least 20 days of flex time. And generally more if you need to gather information.
Josh: You just hit on a really interesting point. By submitting the information correctly the first time, you actually get a retroactive submission date, the date you originally submitted. But if you have an error or a mistake or a gap and you now have to begin a back and forth with the utility, you don’t get that date you submitted. You get some future date, whatever the utility decides.
Taylor: Exactly. And especially in areas that have a high crowding of solar technologies, that 20-day, 25-day period, there could be a lot of projects that get submitted in the same area, which could trigger downstream upgrades. So if you’re unlucky enough to be on the wrong end of that, you could be the system that ends up having to trigger the upgrades and you could have to wait a month, two months, six months, depending on how long it takes the utility to actually install the upgrade. So it’s really important that you lock down that queue position by making sure that you submit completely the first time you submit.
Josh: And if I were to ask, what do you think are the biggest mistakes you’ve seen our clients or contractors and EPCs, developers make throughout the Rule 21 process, whether it’s initial submission or something along the journey? What would you say is the biggest issue, mistake, problem, pain point that you’ve seen arise in the whole process?
Taylor: Going back to what I said a little bit earlier, I think the big pain point is that submitting isn’t starting despite kind of the common knowledge in the industry. And it’s really important that you make sure you’re submitting everything completely and cleanly on the first submittal. Otherwise you can lose lots of time and potentially open yourself up to significant risks that could increase downstream timelines quite considerably.
Josh: Tell me if I got this right. I feel like Rule 21 is—like you said, it applies to any generator that interconnects or interoperates in parallel with the utility grid, which to me sounds like the utility company is, reasonably so, trying to manage the power coming onto their grid. I mean, that’s what generators do. They inject power over time. And Rule 21 strives to define that and characterize it and run it through a bunch of engineering and administrative checks to make sure that the utility companies can indeed continue to operate their grid even after you’ve interconnected with it for everybody’s enjoyment. So it feels like a big power management exercise.
Do you think that’s a fair way to characterize the purpose of Rule 21? To put it really simply, it’s about managing all the power, which could be coming from top-down, big, huge generators on one end of the grid or bottom-up from a single residential homeowner on the completely opposite side of the grid.
Taylor: Absolutely. It’s all about power management at the end of the day. And there are two big factors that really come into that. First, obviously making sure that it’s safe. And that there’s not going to be any issues that could cause people to get hurt at any point.
Josh: Like UL ratings and stuff like that?
Taylor: Exactly. UL listings, but also things on the engineering side just to make sure that people won’t be working on energized lines or other considerations that could cause issues for line workers or people operating electrical equipment on the grid. The other, as you said, power management.
The utility is governed by a lot of different rules. Rule 21 is just one of them. And Rule 3 for new services. There’s a lot of requirements for the level and arrangement of the power that the utility gives you. The voltage that they have to remain within, and things of that nature. So they need to make sure that they’re still able to meet all of their legal obligations. Even with the addition of solar or any other generator that you’re trying to interconnect to the grid.
Josh: Got it. I get really excited about this in the context of storage, which at SepiSolar we obviously do a lot of. Because if the purpose of Rule 21 and the challenge we’re all having is managing power on the grid, then storage to me feels like this incredible engine, this incredible tool, to help mitigate the power impact on the grid while still being able to provide all the energy needs that the host facility or the end-use customer actually needs.
And we actually go and define this through a white paper that we have up on our website. It’s about NEM for storage where, in January of 2019, we actually pioneered the first policy that allocates NEM credits for energy discharge from a storage system precisely because it helps to manage power impact on the grid and for a variety of other reasons.
Well, this has been great. Taylor, thanks so much for your time and for talking to us about this. Rule 21 is super exciting. For those of you out there, please visit us at SepiSolar.com. Subscribe to our LinkedIn feeds and our Twitter feeds, as well as subscribe to our C+I project newsletter. And we’ll look forward to having more conversations like these—be they technical, administrative, and further discussions—as part of this video series.
It’s no secret that energy storage contractors have grown increasingly concerned about the safety risks associated with lithium batteries. While storage pairs nicely with solar technology and the industry seems poised for growth, a single incident could quickly change the narrative, as it already has in Arizona and South Korea.
SepiSolar CEO Josh Weiner invited Chief Electrical Engineer Richard Dobbins to the latest Quick Talk for ideas on designing safe and effective battery systems. See why Richard believes firefighters have an important role to play in permitting and inspections as installers continue to gain experience connecting storage to the grid.
Josh Weiner: Hello and welcome. My name is Joshua Weiner of SepiSolar. I’m here with Richard Dobbins of SepiSolar. And we’re here today to talk a bit about lithium battery safety.
The way I actually see an engineering company like ours is—some people come to us asking for plan sets, some people ask us for technical advice and consul, or utility interconnection processing and PE stamps and whatnot.
I feel like all the services and deliverables that SepiSolar offers are all just a lot of different ways of calling ourselves risk managers. The name of the game for an engineering company like us is to really manage the risk on all the projects we touch.
And these risks, they can be safety related, they can be performance related, they could be upfront risks during the first few months of construction all the way downstream to the next twenty-five years of in-service operation because there’s risks all over the place on these projects.
And so I’m really happy to be here with you, Richard, because you are a licensed electrical professional engineer, right?
Richard Dobbins: Yeah, absolutely.
Josh: Could you just tell us a little bit about yourself? How long have you been at SepiSolar? What do you do for us?
Richard: I’ve been at the company about five years now. I’ve been a registered electrical professional engineer for about two of those.
Richard: Thank you. I’ve been around since just around the inception of that marketable energy storage. My first few months on the job was diving right into battery storage projects and getting a feel for—back then, it was lead acid—type of systems. And so I’ve been kind of seeing the slow progression to where we are now with energy storage and utility scale. Something that really grew from where it was five years ago.
Josh: It’s an interesting point. When people talk about storage in the context of solar, it’s almost a given: we’re talking about lithium storage. It’s so ubiquitous now.
But it’s funny to remember that it’s actually only probably about five years old as a real commercial industry. I mean, for grid scale, for utility interactive applications behind or in front of the meter to do things like manage power, energy, on the grid.
It’s actually a very recent phenomenon. It’s been in laptops and cell phones for decades. But as a utility interconnected resource, it’s actually brand new. Well, great.
As an electrical professional engineer, safety—I assume—is a big part of your life. Is that fair to say?
Richard: I would say, yeah.
Josh: So, when you’re looking at lithium battery systems, what are some of the things you look at or look for or think about when you’re designing the systems for safety?
Richard: Safety is a huge concern with these projects.
I tend to look at safety from a two-pronged approach: passive and active. Passive safety, things like the enclosure that the batteries are contained in, the clearances that the batteries are from other equipment or from buildings and residences, things like that. There are certain distances that are required by code to keep those units away from potential risks, right?
And then you have active safety, things like the battery management system, things like fire suppression systems. In the case that a fire does break out in the unit, you can have a chemical extinguisher that puts it out or that stops the fire from propagating.
So really, between looking at those two sorts of approaches for safety, you can design an effective safe system that you can say with certainty that it will prevent catastrophic damage or loss of life.
Josh: I like your distinct delineation between active and passive. It almost sounds like the difference between quality assurance and quality control.
Quality assurance is something in the process or in the product you design. But then quality control is like a physical person, grabbing something, inspecting it, checking it, going down a checklist, and putting it into service.
And software is really good at that, right? Or BMSs and being able to—or people, human beings going in and checking something actively.
And then there’s the design aspect of it and engineering, what you try to do for it.
Well then how about common pitfalls that you see? Not only do we design engineer lithium systems, we get a lot of clients who ask us to review their lithium systems, either pre-construction or post-construction.
I’m just curious. What have you seen other people do with regard to lithium battery safety? And do you think it’s good? Do you think we got more work to do? Or how’s the industry doing from what you see out there?
Richard: I think as time goes on, the more exposure that people have to these kinds of projects, the more comfortable they’re going to be with the designs that they come up with or the first thoughts they have, right? The first pass of the design. Things like clearances and separation distances and even in the enclosure, like the passive elements that I mentioned before.
Those tend to get overlooked at the beginning, right? Most people who are used to PV systems are used to clearances for ventilation or for working clearances, you know, three feet and all that. With lithium batteries, it has to be a lot greater because of the risk of fire.
Josh: And that’s kind of what happened with APS’s battery fire, I think, too. Actually that was a case where there was a meltdown of a specific pack in a specific rack, and it melted into an aluminum pile (or molten metal pile) but then the saving grace, if you will, or the lesson learned, was because of the spacing in between the different racks.
Yes, there was a fire. We can talk about how it’s inherent to the technology; there may be nothing we can do about it. But, with some good spacing and ventilation requirements, we can at least prevent it from propagating, going from a little problem to a much bigger problem.
Richard: And that’s a big thing I have. Space is always an issue, right? With designers and with contractors. They want to fit as much as they can in the smallest space possible. They don’t want to waste space. So they want to densely populate the area, right? They want to fit as many batteries as they can. But you have to take into account that safety clearance.
Josh: That’s a serious kind of juxtaposition or conflict of interest. One of the promises and one of the promotions of lithium batteries is that they are so energy dense and don’t require a lot of footprint.
But that ends up being one of the risks, when you have that much energy too tightly packed, you end up with these problems like luckily with the APS battery fire was able to avoid in this particular case.
And then there are standards like NFPA 55, UL9540, with and without the A. Do you think these are adequate? Is the industry evolving to a point where all the codes are done and standards are done and everybody’s safe? Just follow the guidelines? Follow the rules?
Richard: I think that’s heading in the right direction. We obviously still have a lot to learn, as evidenced by the issues, the failures, that are breaking out, the ones we read about in the news, the ones we hear about through the grapevine.
There is a lot of work to be done with the safety regulations and just the industry catching up to those regulations. But we are definitely headed in the right direction with requiring those to be followed.
Josh: Do you think there’s a reason why folks underestimate the risks of lithium batteries? I mean, I almost feel like it’s a given. As I mentioned earlier, when we talk about battery storage, we just know we’re talking about lithium battery storage. Why do we just go straight to that? And are we underestimating the risks? And if so, how?
Richard: I think it just comes down to the age of the technology and the general awareness of the population. Like you mentioned at the beginning: It’s everywhere. But it’s only been maybe the last five years that people started plugging into their houses and using it to control their utility energy.
Josh: Do you think they’re so comfortable with it in their cell phones and laptops and now cars that—it’s just: “Yeah. OK, it’s already in everything. Just throw it on the side of the house. Back up my loads when the grid goes down.” It doesn’t even factor into the equation.
Richard: I think so. And to your point about energy density: the amount of lithium in your phone or in your laptop is really small compared to the amount of lithium that you’re going to be installing to back up your house or to create demand charge mitigation. It’s a huge difference. And with that much density comes a much higher risk of fire, of a failure.
Josh: What would you recommend? What should people be thinking about or doing when they design for these, when they build lithium systems, given that the codes need more time to evolve, given that we’re learning and we’re on this trajectory?
And when we talk about storage, we just immediately talk about lithium. What are the things you think we should be doing as an industry or us, SepiSolar, as the licensed engineers that are sealing and complying with codes and following through on these safety precautions?
What should people like us and others be doing?
Richard: I think it’s all about awareness.
Numerous projects I’ve worked in the past, it was very much a learning experience for mostly everyone involved, especially on the part of fire departments. They’re very concerned with lithium batteries being installed.
And it’s their job to mitigate, to ensure fire safety. So they get very involved in the permitting process when it comes to lithium batteries. And so I think getting fire departments involved and educated on the technology and the safeties that are involved is really going to help go a long way with getting everybody as a whole, and really enforcing it as part of the permitting process and the safety inspection process.
Josh: I like the suggestion of collaborating with the officials who know a thing or two about fire.
For example, some of the things that the solar industry is not good at—historically—have been things like software.
The construction industry, it’s a very hardware-driven industry. We’re putting big, heavy machinery and we’re doing very high-risk operations and activities on buildings and structures. So it’s very risky work.
And if we’re not aware of the issues, it’s like the twelve-step program, you know? The first step toward recovery is admitting you have a problem.
First, you’ve got to be aware of it, and then you can address it. And by collaborating with the experts who know a thing or two about all this, we’ll get smarter as a whole.
That seems to make a lot of sense. And again, the essence of risk management: maybe we don’t have all the answers, but by being aware of what the risks are, we can surface sometimes highly nuanced issues and work with our customers to decide what the best plan is for that.
Richard: Yeah, absolutely.
Josh: Makes sense. Well, thanks so much for joining us.
We’re going to have many more conversations like these about not just battery safety, but also we’re going to talk about battery performance and the state and evolution of the market with various technologies and different benefits and costs associated with each of those.
Really excited to talk more about that. Please join us at SepiSolar.com. You can read much more on our blog about information we’ve published along these lines, as well as following us on Twitter and LinkedIn.
Looking forward to talking more about this with you soon.
Want a sales pitch? Pick someone else’s exhibition booth at a trade show near you.
Need additional engineering and design capabilities for solar, storage and microgrid projects anywhere in the US? Come to the SepiSolar booth at Solar & Energy Storage Northeast to meet some of our team, including CEO Josh Weiner and technical sales executive Tony Smith, and find out how to move project engineering seamlessly from planning to execution to close-out.
Those are just a couple reasons to visit us Feb. 19-20 in the Grand Ballroom at the Boston Waterfront Hotel. Also stop by for:
The #1 reason Massachusetts contractors should partner with a California-based engineering and design firm
Hard copies of SepiSolar’s most popular downloadable assets, including our net energy metering for storage white paper
Recommendations for conference sessions at Solar & Energy Storage Northeast
Boston-area travel advice
A notebook with faux leather cover and a matching click-action pen
Cross country engineering and design
You don’t have to go 3,000 miles west for project engineering and design. Why should you? For all the reasons why the northeast has become SepiSolar’s second-largest market outside of California.
Contractors in the northeast often use internal resources to gather on-site information in a cost-effective manner. Then we leverage technology to share this information, driving our process to provide high-quality deliverables and results.
Many companies like the flexibility this provides, where you can use your strengths and available internal resources and leverage SepiSolar to fill gaps.
SepiSolar knows the northeast markets, including common issues related to National Grid and the terrain, and the SMART program for storage. We can share samples of previous work in the region.
If it’s an advantage to be on-site instead of working remotely, we will come to you. Last year, SepiSolar traveled to over 20 sites in less than two weeks across six states on the East Coast on behalf of a large, publicly-traded solar developer and provided valuable site survey and feasibility services.
We continually publish blog posts, videos, white papers and other resources designed to add value for solar, storage and microgrid project professionals, especially those serving the commercial and industrial energy markets.
Come to Booth 118 at Solar & Energy Storage Northeast to fill in an easy signup form. Or save yourself the trouble and pick up printed copies of our published materials. While you’re there, talk to a member of our team about how the topics we frequently cover—risk management, lithium battery safety, net metering for storage, and more—can add value for your business.
While you can always find SepiSolar in the exhibit hall at Solar & Energy Storage Northeast, we have earmarked some of the conference sessions that look to be most informative for contractors. Check these out.
Streamlining Interconnection Procedures in the Northeast(Feb. 19 at 10:30 am) covers the biggest risk and long-lead time item in the entire project. Understanding and appreciating the complexity of this process is valuable. Eversource Energy has a speaker on this panel. SepiSolar has done extensive work in their jurisdiction.
Built to Last: Best Practices for High-Quality Commercial Solar Projects(Feb. 19 at 2:40 pm) talks about what we do every single day. You can learn about maximizing quality and minimizing risk to the host customer based on string vs. central inverters, DC wire management options, monitoring and asset management, designing with higher-voltage strings, and more.
Storage for the New Grid(Feb. 19 at 4 pm) could address novel ways that we have used DC-coupled solar+storage to reduce power impact and increase solar penetration on the grid.
Resilience for All: Solar Plus Storage and Microgrids(Feb. 19 at 4 pm) is where you can learn about getting DC-coupled microgrids on the macrogrid and how microgrids are better than backup. They’re like backup generators that pay for themselves when the grid is on. You can also learn why microgrids are more resilient than any other type of fuel-based generator, and how this helps disadvantaged communities, who often get stuck with dirty, loud, failure-prone diesel generators, if they have any backup power at all.
Boston-area travel advice
At SepiSolar, we’re not afraid of taking a stand on controversial topics. New England clam chowder is better than Manhattan clam chowder. Yeah, we said it. The broth should be white. Not red. Here’s Boston Magazine’s listing of the best bowls of clam chowder in Boston.
Want to order pub food off a menu that looks like the periodic table of elements? Head towards MIT to the Miracle of Science.
If you need a few other quick tips for culinary and cultural stops around Beantown, get inspired by the New York Times’s 36 Hours in Boston.
And if you’re not from the northeast, remember to put a sweater in your suitcase. It’s cold.
Faux leather notebook
We pride ourselves on customer experience and relationships. If you visit our exhibition booth, we’ll want to know how many years you’ve been in business. We’ll want to know about your experience with solar and storage projects, the size of your company, how you originate projects, your financing options, and the equipment and partners you use.
From these details, we’ll know how to structure an agreement and the level of service to provide. We can also surface ways that SepiSolar may add value or alleviate pain points in the engineering and design process.
If you’re a C&I contractor, we’d like to tell you about our process, our experience with products and technologies, and how we go above and beyond industry-standard engineering services with value-adds, such as on project kickoff calls and through Sepi Portal.
We believe our familiarity with how the industry works and the challenges our customers face combined with our unique capabilities in C&I projects and energy storage differentiate SepiSolar.
What You Need to Know About Solar Permitting Services and Costs
Even though solar installation costs have dropped in recent years, solar permitting services have gotten more expensive. Permitting can add thousands to the cost of an average solar project. Faster permits can lower your costs, allowing you to deliver greater customer value.
In this post, we’ll talk about industry efforts to reduce permitting costs and speed up approvals. How much does permitting add to the cost of your projects? Who’s trying to bring down costs and how are they doing it? How far are we from getting the problem under control? We’ll answer these questions to give you an idea how much permitting will cost you, now and in the future.
The Solar Automated Permit Processing Campaign (SolarAPP) is an effort by several solar industry organizations to reduce permitting and interconnection costs. Currently, these costs are higher in the US than in any other country with a mature solar market—often significantly higher. The SolarAPP campaign estimates that the direct and indirect costs of permitting, interconnection, and inspection add up to $1 per watt to the cost of a solar installation. Its goal is to reduce these costs significantly, while maintaining the safety and reliability standards that the processes are meant to ensure.
How states are trying to help
Some states, such as California, have capped permit costs for solar installations. The state recently lowered the cap on residential installations from $500 to $450, but kept the cap for commercial installations the same. The cap for commercial installations includes a sliding scale that allows it to exceed its $1,000 base for larger solar installations. California’s stated aim with the bill is to reduce the cost of solar permitting services, but it still gives localities the flexibility to adjust fees when necessary.
As solar costs continue to drop, the number of installations grows. Lawmakers are hoping that lower installation costs will help increase the growth of solar. And if they’re successful, we can expect to see more states take similar steps to lower their costs.
Obstacles to improvement
Caps on permitting fees are helpful. But costs are still higher than they should be, which is why campaigns such as SolarAPP are so important. Because permitting is done at the local level, large numbers of localities need to be on board to succeed in lowering costs. States can take steps like California. But without local support, these efforts may lack the necessary support to succeed. Or if they’re approved, they may still fail to bring down costs to the extent necessary.
Cost of solar permitting services
One of the major indirect cost increases associated with solar permitting and inspections comes from the loss of business resulting from delays. SolarAPP estimates that every week of delay increases cancellations by an additional 5–10 percent. This means that contractors aren’t just losing time that could be spent on the job. You’re losing entire jobs at an excessive rate.
It’s important to get through the permitting process as quickly as possible. Organizations such as SolarAPP are working to reduce permitting time across the board. Minimize permitting delays by ensuring you have all the requirements in place before submitting your applications. Keep customers in the loop and work with them to ensure that all the requirements are met. This can help reduce delays and cancellations.
Dealing with local regulations
California’s solar permitting guidebook describes the types of problems you might run into while applying for permits. For commercial installers, the biggest problem is localities’ power to decide where large commercial energy facilities can be installed. You’ll need to check with the locality’s planning and zoning commission if you’re dealing with a large project.
Also consider state laws, such as the California Solar Rights Act, which restrict building department review to public health and safety issues. This significantly limits zoning and planning authority on permit processing.
However, this doesn’t stop local municipalities from regularly violating the state statute. Knowing when to comply and when to challenge is a delicate, experience-driven decision that solar professionals sometimes need to make.
Once you’ve addressed zoning considerations, check load characteristics if you’re designing a commercial rooftop project. Also watch out for electrical equipment that is not up to code. This should never be a problem as long as you’re using high-quality materials. However, having all your documentation ready to go when you apply for permits will still help speed up the process.
Ultimately, what matters most in cutting through red tape quickly is simply knowing what to expect. Experience is key. There are so many localities and so many rules that it’s good to always be ready for some new roadblock.
“It’s really trial and error,” SepiSolar CEO Josh Weiner told Solar Builder in a 2018 article that hasn’t lost relevance with time.
Planning is important. It can be a good idea to call up the AHJ before submitting a permit package. Ask tactful questions and use the responses to inform how you proceed. But don’t count on consistency and predictability, or even necessarily accountability.
If you want to contest a parking ticket, you can go to court and appeal to a commissioner or a judge. In some legal matters, you can get a final decision from a jury of your peers.
Not so in solar permitting. Success sometimes has less to do with what’s fair and just, but rather what course of action will get your project approved.
The American Energy Opportunity Act is federal legislation that builds on the SolarAPP initiative by helping local governments simplify, standardize, and automate their clean-energy permitting processes. This is a huge benefit to contractors. You will get a clearer idea of what to expect when seeking permits. Those expectations will be more uniform across localities. The bill also supports instant permitting. It will reduce direct and indirect costs of permitting, inspection, and interconnection.
SolarApp plans this year to introduce a beta version of its simplified online solar permitting Web portal. The portal will allow for online payments, encourage flat fees, and enable instant permitting. It will include support for both residential and commercial PV and storage. The timeline includes a goal of June 2021 for the full version of the portal to be live.
Even with instant permits, things won’t always go smoothly. When San Jose, California introduced instant permits, it ended up creating a whole new set of problems, as Weiner explained in the Solar Builder article.
Installers in the field got ripped apart by the inspectors. Since no plans were required for a permit, this puts all the pressure on installers to get it right the first time. If the installers screwed up or did something the city didn’t like, they’d have to rip off the roof and re-install.
The lack of uniform, straightforward permitting standards and procedures in solar underscores the importance of working with experienced, knowledgeable design professionals.
Find out more about streamlined solar permitting services. SepiSolar has a top-rated design and engineering team that can help save you time and money on every installation. Contact us today to find out how we can help.
Do you have questions about how the impending reduction of the 30 percent federal investment tax credit will affect solar and energy storage contractors? We did. That’s why we invited Rob Brown, energy strategist at Sustainable Energy and Power to talk with us about how the Investment Tax Credit (ITC) step down will affect system design, state incentives, energy storage projects, and more.
In this month’s SepiSolar video, CEO Josh Weiner and Rob cover how California projects can offset the lost value of the federal tax credit with the state’s Self-Generation Incentive Program. They also discuss how to design solar-plus-storage projects for ITC compliance, ways to meet the IRS physical work test and 5 percent safe harbor test for multi-year projects, and why stand-alone flow battery projects may qualify for the ITC, even if not paired with solar.
Josh Weiner:Hello, everyone. I’m Josh Weiner of SepiSolar and I’m here with my good friend Rob Brown of Sustainable Energy and Power. And today we’re going to talk about how to prepare for the ITC step down. I’ve been very interested and very happy with ITC for my whole career. Rob, where do you come from? Tell us about your company.
Rob Brown:I run and own an energy consulting firm. I used to work with energy or rather electrical distribution with Graybar, had a lot of experience with them, kind of consulting with commercial and industrial businesses, that sort of thing. And I left Graybar to do that on my own. Now, I just kind of consult with those businesses, client representative, that sort of thing.
Josh:Great. So I think it’s safe to say ITC has a special place in your heart.
Rob:Absolutely. I think that if it weren’t for the ITC, we wouldn’t even have a job, right? We wouldn’t have an industry. So it’s a very big part of what I do.
Josh:Let’s springboard right off of that. Tell me, why has ITC—I mean, this might be an obvious question for most of us live and breathe solar on a regular basis—but why is ITC so important? There’s other countries outside the U.S. that don’t have ITC that do a lot more solar than even the U.S. So why is ITC so impactful and important for our economy, for our industry?
Rob:Yeah, I agree with you. There are places they don’t have the ITC that have more solar than we do, but they also have a different environment here in the United States. We don’t have the same kind of environmental policies to keep coal and those sorts of energy production facilities expensive right here. I was working with a client not too long ago in North Dakota with coal-fired power power plants and super, super cheap energy. Without the ITC, solar doesn’t have a chance. You have to have this sort of program while solar is more expensive in order to incentivize people to go that direction, make it cheaper. And then over time, the idea is that solar gets its legs underneath it, has its own kind of industry presence and the ITC can kind of slowly go away over time like any hopefully any government incentive.
Josh:Yeah, I’m right there with you. Actually, part of me actually thinks the ITC becomes sort of a crutch, you know, to allow some companies who probably even shouldn’t be there to stay there. So I actually look forward to the ITC stepping down. I’m sure I have a lot of colleagues that disagree with that, as I’m sure you do, too. So then why are people, for the most part, concerned about the ITC stepping down? You heard my opinion just now. Why would that be a problem for someone else?
Rob:Well, in my opinion, I think there’s a, like I said before, there’s this kind of incentives need to step down as the industry comes of age. Right? And the issue for me is timing. If it steps down too soon, then the industry doesn’t have its wings yet, hasn’t kind of grown out of its embryonic stage and it dies. But if you keep it on too long, look at the coal industry or corn. Right? You have incentives that are on way too long in these very established industries that should be going away. Right? Solar, it’s just all about that timing. Some people think it’s too soon. Some people think it might be too late. And it’s all kind of the politics around when is the right time.
Josh:What do you think? I know this ITC steps down to 10 percent ultimately and then it plateaus. Residential goes away. Fuel cells go away, too. What would happen if solar went to zero? C&I, utility, all of it. Like if ITC completely went away down to zero percent. Is it the same answer?
Rob:Again, when? If it happened now, that would be catastrophic to many parts of the country, not other parts of the country. Right? I think you’d be just fine. But again, it kind of depends. One of the things that you mentioned kind of previously, I just wanted it not to get us off track. But you mentioned the storage concept and fuel cells and things like that. I have a couple of clients right now that are discussing having a battery storage system kind of paired with their solar and kind of get in before the end of the year before things start to change and step downs. Can I get your thoughts on this? I mean, you’re the engineer, I’m just a consultant. There are certain things that can qualify a battery to be part of the ITC. Is that right? How does that kind of shake out?
Josh:Actually, as we’re talking about ITC, I feel like we tend to gravitate or knee jerk think about solar and renewables. But actually it doesn’t seem like the actual quantity is going to hurt solar, at least depending on where and when that happens. You know, in California versus other areas for sure. But storage is the one that’s still very early stage and still expensive and it needs its incentives absolutely. What I do notice, however, is at least in the case of California, that the rebate program in California actually takes money away from you, from the state. If you’re applying for federal ITC. So in a way, ITC going away, you actually have two options with California SGIP. You actually get more money from the state, if you’re not getting the federal ITC, it’s kind of funny. I mean it makes sense. You know, California doesn’t want you to get paid, they don’t want you to actually run a greater-than-100 percent IRR. I actually think I’m more worried about the ITC impact on storage than I am solar. And so, that’s actually why I in one of SepiSolar’s white papers, which you can find on our Web site at sepisolar.com, we actually do go into some detail about the implications of DC versus AC coupling, because storage, of course, has the 75 percent cliff. You know, if you’re charging storage from a renewable resource like solar, wind, and less than 75 percent of that energy going into the batteries is coming from a renewable source, then you actually lose the ITC. If more than 75 percent is going into the battery, then you get the ITC pro-rata for storage. So it’s a little annoying, a little complicated, but it works.
Rob:But that’s AC coupled.
Josh:Actually either AC or DC coupling, you have the 75 percent cliff. It just so happens an easier way to verify or an easier way to ensure that compliance is with DC coupling than with AC because with with AC coupling you end up having two separate inverters connecting on the AC side. You have to M and V everything, which is a fancy way of saying, measure and verify and count every electron going from the solar into the battery. OK, check. There’s one. There’s two. I mean literally you’re counting electrons or kWh and making sure more than 75 percent leaves from this original from the source and heads to the destination whereas with DC coupling, you can actually, as our white paper suggests on our website, you can actually ensure no M and V by design. The battery actually physically cannot charge from the grid and therefore by deduction all energy going into the battery. If there’s two sources, one’s the grid and one solar, and you can’t charge the battery from the grid by process of elimination, it’s only coming from a renewable source. And then you get that ITC eligibility, that’s really clean.
Rob:So it sounds like by designing it that way, not just DC coupled, but also kind of the what you’re talking about in the white paper and what SepiSolar does, it sounds like by doing that it saves a lot of headache from measured verification, extra equipment, submitting reports to the utility, all that stuff goes away because it’s just designed, right?
Josh:Ironically, two birds get killed by the same stone because the rules for ITC are the same rules for NEM. So when we comply with NEM with a solar-plus-storage system, when we don’t charge that system from the grid, it turns out the utility lets us export that energy from the battery into the grid and get NEM credits for it. I mean, literally it’s a battery exporting those electrons and NEM is a credit reserved for renewable technology. So for a battery to discharge into the grid and get credit for it, it’s kind of groundbreaking. And that was good work that SepiSolar did earlier this year. But then likewise for ITC compliance. Again, if you’re DC coupling and you’re only charging from the renewable source, then you’re also compliant with ITC. So, the same stone kills two birds.
Rob:So back to this client I was talking about, I’m helping them with storage and solar and everything, trying to get in before the end of the year. We come to you. We get this thing designed, right? We have a DC couple. They’re going to put batteries in with the solar. Everything’s great, just like we talked about. What do they have to do to make sure they get this year’s tax credit before it steps down next year?
Josh:So the way we understand it from the IRS, and they released in the middle of 2018 timeframe a clarification, an announcement. It wasn’t a ruling, but it was just a clarification on how this works. There’s two tests that you can meet. One is called the physical work test and the other is called the 5 percent safe harbor test. So the physical work test is, they’re both kind of straightforward in their own way, but the physical work test is if you’re in construction, continue through construction and place the system in service, have a continuous effort of that construction work. You’ve passed the physical work test. So that’s a case where if you started construction in December 2020, but you PTO or you place in service in 2021, you get ITC from 2020. And the same thing with a 5 percent safe harbor. It’s kind of the same vein. You don’t have to necessarily start construction, but if you’re progressing through the work continuously and you’ve expensed, you’ve already put up 5 percent of your money, you’ve spent 5 percent of the total project costs. That also qualifies you for that year’s ITC when you started the work.
Rob:OK. So call it a down payment, maybe 5 percent in December of this year grants me this year’s tax treatment even if it’s completed next year.
Josh:That’s right. and I wouldn’t call it a down deposit. It could even be continuously paid throughout the process. You know, it doesn’t have to be all in like one lump sum upfront fee.
Rob:But that amount has to be paid before the end of the year.
Rob:OK. So, kind of a curveball for you. So let’s say a $100,000 project. Yeah, my client puts down $5,000 to get their safe harbor. But something happens down the road and there’s a change order. And now it’s a $150,000 project in total. What happens?
Josh:That is a great question. And actually the IRS ruling or, sorry, clarification actually goes through specific examples where that is an example. What happens if there’s a change order? What happens if the project costs go up or down? It does put the ITC at risk. It does. But there are provisions that allow you to keep it depending on the definition of continuous effort. And when the money actually strikes. So, that’s a really good point.
Rob:That’s something to watch out for. I mean, the client that I’m consulting with right now, they have a little bit of cash on hand. They’re just gonna put down 10 percent just to make sure that they get the full 30 percent no matter what happens in the project. But, I just wanted to kind of figure out what the ramifications would be.
Josh:I think that’s a great strategy. Based on my interpretation, my reading of the IRS clarification, they should do that 10 percent and keep continuous work flowing.
Rob:If they just hold off and just wait for it, they lose out on all of that.
Josh:That’s right. The IRS is smart. They’re not going to.
Rob:I’m telling my client things are going to wait. Things are going to pause. The utility is going to take some time. Requests and interconnections are going to take time. But as long as the waiting period is not on my client on the end user customer, then we’re OK. As long as they don’t wait on anything, we should be fine. Would that be accurate?
Josh:Yep. And then there is a final very hard deadline to get to like January 1st, 2022, if the systems are not placed in service by that deadline then you’re really screwed. You lose everything. You lose all ITC.
Rob:Wonderful. Cool. Well, thanks for answering a couple of my questions.
Josh:And then actually one last point that I think is actually really important with ITC are fuel cells. We know we don’t deal a lot of it at least in the solar and storage field. But it turns out flow batteries actually might qualify for fuel cell ITC on a standalone basis. You know, most storage has to be coupled with a renewable source in order to be eligible for that ITC. Because really for all intents and purposes, storage is piggybacking on a solar ITC. But it turns out with flow batteries, since they comprise a fuel cell, and if anybody goes the IRS.gov and you read the definition of a fuel cell, you’ll find that actually flow batteries kind of meet the definition of a fuel cell and on a standalone basis a standalone, no solar, no renewable, just a standalone flow battery storage system might actually qualify for the fuel cell ITC. And that, flow batteries are like this promising technology. They’ve been out. There’s a lot of uptime, a lot of systems installed. It’s great, doing wonderful things, but it’s got this little problem that lithium is super costed out. The supply chain and the technology and the products, they’re ubiquitous now. They’re in our laptops. We’ve got 20 lithium batteries sitting on this desk right here. So flow batteries still need to catch up a little on the CapEx side of projects. And this fuel cell ITC actually really helps make a big difference in that upfront first costs. You know a thing or two about batteries. Do you think the fuel cell ITC, that stepping down like the solar ITC is gonna make implications for storage?
Rob:Oh, yeah. Storage is very much in its infancy and I think it needs as many rebates as it can until it gets on its feet. I think that we are with storage now as we were with solar in 2011, that it’s right in its infancy. We really need to infuse it with some help so that it can get on its feet and then we can do without rebates at that point. But we’re just not there yet.
Josh:So last question. In your crystal ball, when do you think storage comes out of its infancy, if you had to wave a magic wand and just take a wild guess….
Rob:So many factors. I couldn’t answer that. From the different things that I’ve seen, I’m just going to throw a wild guess out there. I’d probably give it 7 to 10 years before it’s really taken on. It’s going to be fast, but it’s going to take some time.
Josh:Awesome. Well, thanks so much for joining us. Please check us out at sepisolar.com. Subscribe to our C&I project newsletter, and follow us on LinkedIn and Twitter. We’re gonna have many more conversations like these with Rob and with others about really important issues that impact all of us. Thanks again for joining us.
Two important qualities for business owners are foresight and leadership. Installing a microgrid at your solar sales office helps showcase both. These are just a couple reasons why your office is the ideal demonstration site for a microgrid.
Without a microgrid, you depend on the electric grid for power. And you might have no backup plan in the event of a prolonged power outage. The problem: prolonged outages are occurring with greater frequency in places like California. To make matters worse, Pacific Gas & Electric Co., the state’s largest utility, has begun preemptively switching off power when wildfire risks are high. Annual wildfire alerts appear to be the new normal in California.
The time is right for microgrids across the country, not just in California. Communities in other states sometimes contend with extreme weather that can threaten electricity access, such as hurricanes. Other states are also adapting to regulatory reforms that are likely to make microgrids more valuable for the end customer.
Lastly, the business case for microgrids is strong. These projects provide a hedge against the consequences of a power outage where you might continue to incur expenses with no ability to generate revenue. For some businesses, costs associated with a single power outage may exceed the microgrid installation cost. Meanwhile, you can use the microgrid as a revenue-generating asset while sourcing electricity from the grid.
Reduce operational risk and increase financial rewards by starting a microgrid project at your sales office.
If you build it, they will come.
Ideal microgrid demonstration site
A microgrid has four components: energy generation, storage, load, and control. If you’ve installed solar and batteries, you’re already well on your way to installing a microgrid.
One way to highlight microgrid installation experience and expertise is to sell a project and take interested parties on tours at a customer’s site. Here’s why it’s better to run tours at your own site:
First, you have complete access to the facility. Scheduling tours will be a cinch. Just pick a time that’s convenient for the customer. No need to work through an intermediary.
In addition, you can discuss project development issues. Talk about decisions related to engineering, procurement and construction from the customer’s point of view. Tell customers about the goals of the project. Explain your process for selecting energy generation, storage, and management technologies. Walk through the tradeoffs between cost, reliability, and code compliance.
You might have no other choice. After all, the microgrid market is still taking root. If you have the capabilities to complete a project but have yet to close on a customer contract, consider developing a project at your sales office first.
Hosting microgrid demonstrations can turn your company’s location into a regional destination for anyone interested in microgrids. Announce the project before you commence construction. Provide ongoing updates right through the first year of operations. Early adopters of rooftop solar and energy storage enjoyed the first mover’s advantage. You can do the same by building a microgrid.
Microgrids protect against blackout risks
In the past decade, wildfires have consistently ravaged the state of California. In October 2019, wildfires in the state forced the evacuation of over 200,000 people from their homes. One study showed that 4.5 million homes are at extreme risk for a wildfire. Consequently, almost every building in California is at risk of losing electricity service.
This year, PG&E debuted a program called the Public Safety Power Shutoff (PSPS). When an area’s weather forecast calls for “heightened fire risk” PG&E shuts off electricity across large sections of the transmission and distribution grid.
Even with this measure in place, the grid may have contributed to at least one wildfire outbreak in 2019: the Maria Fire in Southern California. According to one report from USA Today, Southern California Edison “re-energized a 16,000-volt power line minutes before the Maria Fire erupted nearby… [and] quickly swelled to 14 square miles.”
PG&E says it is developing temporary microgrids to offset the impact of its PSPS program. You may question, as we have, whether the PG&E system design, a diesel generator plugged into a local utility substation, really meets the definition of a microgrid. But you cannot dispute the need for alternative solutions to preserve reliable electricity service at your place of business. Microgrids deliver one of these solutions.
Everyone needs microgrids
As power needs evolve not just in California but throughout the country, the strain on the electric grid is increasing. This reality is creating development opportunities for microgrids.
One of the trends pointing to growth in the microgrid market is the falling cost and increasing deployment of solar and energy storage. Solar and storage are big contributors to microgrid deployment costs. Therefore, once a facility has solar and storage, the additional cost to deploy a microgrid goes down.
Another industry trend is the evolution of the utility business model. Until recently, utilities were vertically integrated businesses that owned generation assets and sought to maximize the sale of energy. But utility ownership of generation assets has declined considerably, and regulatory agencies across the country are incentivizing utilities to shift from maximizing energy sales to maximizing the value of energy. Distributed energy resources—including solar, storage, electric vehicles, and microgrids—add value for the customer and the grid.
In 2018, the US Department of Energy’s National Renewable Energy Laboratory detailed a feasible framework for increased microgrid adoption. NREL discussed a plan for how state policymakers could assist in the development of microgrids as critical infrastructure. There is no disagreement about the value that microgrids have to offer. There’s no question that the future is bright for microgrids. The only question is, who will be the early leaders in microgrid installations?
The microgrid business case
When businesses invest in energy storage, they usually want to identify revenue streams and model an expected return on investment. But the microgrid business case is somewhat different. Think about what happens when the power goes out, and the opportunity costs for your business. You’re paying wages but generating no output. You lose out on existing business and you cannot develop new business.
A microgrid helps put you back in control. Decide how much generation and storage you’ll need to continue business operations during a blackout. Customize the system to balance costs and system size. Extend the system gradually as your energy needs change. You are in the driver’s seat, now.
A microgrid’s ability to provide value isn’t limited to emergencies, either. With energy storage and energy management capabilities, the system can continuously perform demand-charge management, maximize solar self-consumption and carry out other functions that provide value for commercial electricity customers. Think of microgrids as emergency back-up systems that pay for themselves with grid services, so long as the grid is “on.” This means the microgrid works for you whether the grid is “on” (in the form of grid services) or “off” (in the form of back-up “energy insurance”).
Start your next project now
To sum up, there’s never been a better time for solar construction companies to install a microgrid at their sales office. It will help protect your business from lost business in the event of a power outage and expand your business to serve customers seeking microgrids for their own business facilities. Visit the SepiSolar website for microgrid design and engineering resources or to contact our microgrid company for a consultation.
While at the website, check out our white paper on net energy metering (NEM) in California, located in the resources section. The NEM white paper explains how solar-plus-storage projects, including solar microgrids, can qualify for NEM credits.
A recent Greentech Media article brought to light new details about a lithium battery fire at the Arizona Public Service (APS) McMicken Energy Storage facility that occurred in April.
According to GTM, the fire involved a thermal event affecting one battery rack but not a thermal runaway event affecting multiple battery racks. This is very good news, as we’ll explain below. The article also suggests that venting energy storage enclosures to release combustible gases may be a solution. We respectfully disagree.
We still don’t know the root cause of the fire. However, we know enough to conclude that more ventilation is not the best approach to battery fire prevention. We also know that storage projects need a failure plan, and they need to comply with higher standards.
Read on for our recommendations to help energy storage contractors prevent lithium battery fires.
No thermal runaway
After the Arizona fire, an investigation from APS and battery provider Fluence found that only one battery rack containing 14 modules had “melted.” Evidently the fire did not spread to adjacent racks, setting up a more hazardous thermal runaway scenario, which could have added to the fire’s propagation many times over.
This is encouraging. It’s not the failure of a single cell, but rather the propagation of that failed cell that causes all the damage we see in lithium fires. We should understand why the propagation stopped at the rack level. Here are a few possibilities.
(A) The spacing between racks in the system design was wide enough to stop the fire’s propagation in other racks.
(B) The original equipment manufacturer’s design of the battery pack itself helped prevent rack-to-rack propagation.
As the investigation proceeds, we hope to understand not only the root cause of the APS fire but also the design criteria that helped prevent rack-to-rack thermal runaway. APS is reporting investigation updateshere. Independent research and third-party lab testing can also produce findings that improve design and engineering for battery safety.
Venting is not the answer
APS director of technology innovation and integration Scott Bordenkircher told GTM that the McMicken facility fire will prompt engineering and design changes, balancing fire suppression with the removal of explosive gases.
A better answer might be to make sure fire response professionals do not open containers designed to enclose and isolate what’s inside. Do we know enough today to arm firefighters with the correct training to protect themselves and suppress fire? A system designed to fully contain explosive gases may be part of the solution rather than the problem. While investigating ways to improve lithium battery safety, it’s also a good idea to explore best practices for first responders.
Root cause unknown
While it is encouraging that rack-to-rack propagation did not occur, the root cause of the APS fire is still unknown. A root cause analysis will help engineers modify future designs to improve lithium battery safety. Following the chain of events backwards to the point of origin (modules within the rack, cells within the module, and down to the cell level) can yield key insights.
If the root cause of the fire was truly “spontaneous,” which is a real possibility when large quantities of lithium cells are manufactured, no design or manufacturing changes can eliminate the possibility of another freak accident occurring. We may have to accept that spontaneous lithium failures are inherent in lithium technology and manufacturing processes. If this is the case, the best we can do is focus on controllable areas of fire suppression, isolation, and safety at the component- and system-level, rather than at the cell- or module-level.
With that in mind, what can energy storage companies do to eliminate or mitigate lithium battery fires? Here are two recommendations.
Plan for failure
In the event of a lithium battery fire, projects need clear and well-documented protocols to assist in fire suppression, cleanup, and investigation. These prevention and remediation plans ought to be provided as part of the project-specific safety plan or permitting process. This would ensure the information is provided to local authorities and site personnel. System design should also be informed by the possibility of system-level or component-level failures. Fire, building, chemical, and electrical safety codes and standards may be consulted and referenced.
For instance, in the APS fire, the bad rack was positioned in the middle of several batteries that maintained a 90% state of charge. As a result, the APS/Fluence team spent 9 weeks removing and de-energizing all of those batteries.
“There was absolutely no playbook,” Bordenkircher told GTM.
If this experience leads to the creation of a proactive project failure plan, that would be a positive outcome. It could help guide future safety code iterations and standards development.
In addition, it is interesting that APS used LG Chem batteries. According to SepiSolar research, LG Chem batteries have among the widest temperature range needed to initiate thermal runaway. LG Chem batteries also have a fire incident history that reportedly led the battery maker to shut down some of its own storage systems in South Korea.
Raise project standards
The risk of a lithium battery fire is lower in residential and commercial applications than in utility installations. The reason: such projects must comply with the UL 9540 and NFPA 855 safety standards. Utility projects, on the other hand, are basically self-regulating.
UL 9540 addresses construction, performance, and testing of energy storage systems, including how the system handles combustible concentrations and fire detection and suppression.
If we hold utility projects to higher safety standards, battery fire risks will go down.
Improve risk management
It’s more important than ever to understand and manage the risks associated with energy storage projects. That’s why SepiSolar is writing about the APS battery fire and why we will continue to write about it.
Our experience balancing cost, speed, and safety in energy storage projects contributed to the development of the new C&I Project Risk Management Guide. Download a free copy today.
Raise your hand if you’re suffering from too much time and not enough email. Need a second to think about it? Nah, didn’t think so.
This question came up several times as we started developing a newsletter for the people we work with who lead solar, storage and microgrid projects in the commercial and industrial market. We’re pretty sure you didn’t wake up this morning wondering how to fill your time and hoping for a little more email to click on.
We’re all busy. To stay informed, you might read a few articles in the industry press or attend a few conferences and events throughout the year. But the process is inefficient. You might sift through dozens of headlines to find the ones that matter. It can also be expensive. Traveling to a conference can easily cost $1,000 per person or more.
Wouldn’t it be nice to get a concise email once a month that’s filled exclusively with information about C&I projects?
We think so too. That’s why we’re launching SepiSolar’s monthly C&I project newsletter.
The first edition will be published in November. Become one of our first free subscribers. Sign up now.
C&I Project Newsletter
News providers used to try and be everything to everyone. The New York Times still claims to publish “all the news that’s fit to print.” You can buy a plain sweatshirt with the slogan printed in a small box for $85.Any size you like.
A lot of company newsletters fall short for another reason, because they’re too self-promotional. Five years ago, a service that helps people unsubscribe from email lists called Unroll.me published a list of the email newsletters with the highest opt-out rates. The flower delivery service 1800 Flowerstopped the charts with a 52.5 percent unsubscribe rate. More than half of subscribers wanted out.
We value your time. So let’s be clear from the start. If you are not a project manager, the head of operations, or an executive who leads solar, storage, or microgrid projects for C&I customers, the C&I project newsletter probably isn’t for you.
However, if you’d like to hear about new ideas in permitting, interconnection, project design and engineering, and more, we think you’ve come to the right place.
In SepiSolar’s C&I project newsletter, you’ll find original content created through a collaboration between our professional engineering and technical sales, who assure that you’re getting high-quality, authentic information, and our communications team, who head up content planning, writing and editing.
We want your ideas
In the months ahead, we have a lot of ideas that we’re excited to cover.
How to discharge batteries from the customer side of the meter into the grid and collect net energy metering credits.
How to resolve the eternal debate over DC coupling versus AC coupling once and for all.
What lessons have we learned from the 2019 APS battery fire.
We welcome your ideas! Please contact us to share topics that you’d like us to cover in the C&I project newsletter. Let us know if you’re interested in contributing an article yourself. And once you’ve seen the newsletter, please share feedback.
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