This post was written by Josh Weiner, Solar Expert Witness & Solar Engineering Expert. Mr. Weiner has been at the forefront of the solar industry for over 20 years and is an industry leader on solar-plus-storage engineering & design. Josh’s expertise spans both in-front of and behind-the-meter initiatives including residential, commercial, utility, grid-scale, and ev charging solar and storage applications.

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.

Industry efforts

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.

Experience matters

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.

Federal legislation

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.

Feature image by tom coe on Unsplash

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.

Video Transcript

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.

Josh: That’s right.

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.

Stack of coins is licensed under CC0 BY 1.0

This post was written by Josh Weiner, Solar Expert Witness & Solar Engineering Expert. Mr. Weiner has been at the forefront of the solar industry for over 20 years and is an industry leader on solar-plus-storage engineering & design. Josh’s expertise spans both in-front of and behind-the-meter initiatives including residential, commercial, utility, grid-scale, and ev charging solar and storage applications.

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.

“Installing solar panels” by Oregon Department of Transportation is licensed under CC BY 2.0

This post was written by Josh Weiner, Solar Expert Witness & Solar Engineering Expert and leads a discussion about safety in energy storage projects. Mr. Weiner has been at the forefront of the solar industry for over 20 years and is an industry leader on solar-plus-storage engineering & design. Josh’s expertise spans both in-front of and behind-the-meter initiatives including residential, commercial, utility, grid-scale, and ev charging solar and storage applications.

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.

A few months after the fire, we gave some initial suggestions on how project managers can design risk out of energy storage systems. This post presents our take on the facts as we now understand them.

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 updates here. 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.

Feature photo by Constante Ken Lim.

This post was written by Josh Weiner, Solar Expert Witness & Solar Engineering Expert and announces the new commercial & industrial solar engineering newsletter by SepiSolar. Mr. Weiner has been at the forefront of the solar energy industry for over 20 years and is an industry leader on solar-plus-storage engineering & design. Josh’s expertise spans both in-front of and behind-the-meter initiatives including residential, commercial, utility, grid-scale, and ev charging solar and storage applications.

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.

Why subscribe?

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 Flowers topped 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.

The Solar Energy Industries Association’s latest Solar Means Business report, published in July, identified over 7 GW of solar projects delivering energy to corporate solar users, up from 2.5 GW of projects that were cited in the prior year’s report. The growth of C&I projects might seem mind blowing, but it’s still just the tip of the iceberg.

Get ready for much more to come from solar, storage and microgrids. Subscribe to the C&I project newsletter today.

This post was written by Josh Weiner, Solar Expert Witness & Solar Engineering Expert. Mr. Weiner has been at the forefront of the solar energy industry for over 20 years and is an industry leader on solar-plus-storage engineering & design. Josh’s expertise spans both in-front of and behind-the-meter initiatives including residential, commercial & industrial, utility, grid-scale, and ev charging solar and storage applications.

Every once in a while, we get a familiar request — a contractor asks to “fast track” a new solar project. We say: Be careful what you wish for. You might just get it.

Our response wasn’t always this way. At one point, customers wouldn’t even have to ask to speed up the design and engineering process. They wanted deliverables quickly — yesterday — and at low cost. We delivered. Sort of.

Soon, we learned that while we could deliver on the front-end, we had too little control over the back-end. We were working too quickly. Customer requests for design changes would come weeks, sometimes months, after delivery of the original plan set. This increased project costs and risk in the long run.

At SepiSolar, we have introduced structure, definition, and organization to the project design and engineering process with discrete handoffs, milestones, stages, and defined activities. We control project costs, timeline, scope, quality, liability, customer success and safety, reducing cost and risk to the project.

We used to try explaining to customers one-by-one why no engineer has the power to expedite projects.

Each project dictates its own timeline according to the project data at hand, the complexity of the project, climate, and other variables that we cannot control. If a commercial property has no as-built plans available, someone needs to conduct a site survey and perform discovery on key aspects of the facility. There are faster ways and slower ways to perform discovery, but you cannot fast-track your way through it.

In other words, the job of the engineer is not to tell the project how much time it has. Rather, we listen and then help the EPC get through it.

Since we have these conversations with some frequency, we decided to take some of our core insights and share them in the C&I Solar Risk Management Guide.

What’s in the risk management guide?

The C&I Solar Risk Management Guide covers the key milestones from starting a project plan set to matching the as-built conditions of a completed project. Milestones include:

Project kickoff
Preliminary analysis
50% design
90% design
Permit plan set
Revised permit plan set
As-builts

Managing risk means having a clear and complete idea of the scope of work up front and catching all components and elements of design and engineering that need to be specified, budgeted for, and tracked. When changes occur, it is usually due to lack of specificity in the original scope of work, or something that nobody saw coming. Surprises increase cost. We don’t like surprises in construction.

By thoroughly defining the scope of work up front and identifying potential surprises that could come back to bite us, we proceed with projects in stages, never getting too far ahead of ourselves without all the necessary information.

Subway, the fast-food chain, recognizes the value of risk management. At the lunch counter, the selection of bread drives the development of the meal. You might ask for the pit-smoked brisket and then wonder why your server holds still, waiting for you to choose between six-inch and foot-long subs made of Italian bread, whole wheat, or something else. You’re hungry. Can’t they go a little faster?

If the server rushed ahead with the wrong bread, there would be an even longer delay as he builds your sandwich a second time. Bad move. Now you’re really getting hangry. Subway’s process won’t set any sandwich-making speed records. But it’s dependable, time and time again.

How to use the C&I Solar Risk Management Guide

Our goal with the solar risk management guide is twofold. First, we want to point out how engineering and design can have a big impact on project success, even though it accounts for a small share of project costs. Second, we want project and operations managers to know what you can expect from a structured, highly organized project design process.

Have a look at the guide. Download a copy of the project milestones, and share it with your team.

How does your project design process compare to ours? Are we following similar paths? Where are the differences? If you have questions or comments about the C&I Solar Risk Management Guide, join the conversation with us on LinkedIn.

DOWNLOAD THE GUIDE

This post was written by Josh Weiner, Solar Expert Witness & Solar Engineering Expert. Mr. Weiner has been at the forefront of the solar energy industry for over 20 years and is an industry leader on solar-plus-storage engineering & design. Josh’s expertise spans both in-front of and behind-the-meter initiatives including residential, commercial, utility, grid-scale, and ev charging solar and storage applications.

At SepiSolar, we get a lot of contractor inquiries about the price of a professional engineer’s (PE) stamp, certifying that a solar project or an energy storage project has been designed to applicable codes and professional standards.

We know where they’re coming from. Price pressure is a real concern for anyone in business. Many project designers obtain PE stamps only when required. And let’s face it. Whether it’s wet ink on paper or a digital mark, PE stamps generally look the same.

But all PE stamps are not the same. The stamp is only as valuable as the engineering firm and the liability insurance that stands behind it. If the firm closes down or the insurance offers too little protection, the contractor carries more risk. Getting a PE stamp also creates an opportunity to increase project value or drive down cost.

Here are three tips to help select an engineer for a PE stamp. Know how to recognize the key differences from one firm to the next. Understand the advantages of working with a specialized, focused and experienced firm. And try to mitigate risk whenever possible, even when a PE stamp is not required.

PE stamp evaluation

Selecting a PE stamp provider should be less time consuming than other decisions you make, like which inverters and batteries to install. Even so, take a page from the equipment vendor selection process. Find out how long a company has been in business. Then find out about customer service, too. At some point, you might want a PE to go to the permitting office on your behalf. Can the firm make someone available?

Look for an engineering firm that checks all the boxes below. Extra time with the evaluation will pay for itself, saving you from ongoing PE stamp price comparisons. Or paying to fix costly errors and omissions leading to property damage or personal injury.

Licensing

A license makes an engineer’s work worth the paper it’s printed on. An unlicensed PE might draft all the same lines and shapes on the page. But you get no assurance that this person has followed the duty of care that PEs swear to uphold. Request a Proof of Insurance (POI) certificate to verify the coverage that a PE carries.

Subject-matter expertise

Think any PE can handle a solar or storage project? You’re setting the bar too low. Competent, experienced professionals know how to couple solar modules and power optimizers, among other things. They have done it many times. A generalist might use your project to figure things out for the first time.

Years in operation

Many PEs have been around for a year or two. SepiSolar has been in business for 10 years. Our experience and expertise bring customers peace of mind. No amount of education or licenses can replace the experience of doing this work day after day. That’s the ultimate value a company can provide.

Flexibility

Change is inevitable, in project development as in life. A firm with a service ethos can work with contractors to make design changes as needed and bring in the appropriate experts to facilitate. At SepiSolar, we once fielded a next-day request for a permit-ready C&I solar design. The ability to fulfill a request like this adds tremendous value for contractors.

Customer service

We do our best work in collaboration, not in a vacuum. SepiSolar has invested heavily in an online customer portal, operations management and project management to provide not only great engineering but reliable, cost-effective and flexible services. We engage in extensive client communication. When you talk to a PE firm, ask how it handles urgent requests, how it ensures customer success, and what systems are in place to do so.

Specialized, focused and experienced

There are three types of PE firms: those that rubber stamp project designs without proper consideration, big corporate firms that take on distributed energy projects as part of larger real estate and infrastructure projects, and specialized PE firms that focus on distributed energy projects.

In California, the Board of Professional Engineers, Land Surveyors and Geologists strives to rescind the licenses of PEs who blindly stamp project plans in exchange for fees. Unlike a rubber stamper, an experienced and specializing PE firm works to remove risks for contractors instead of adding risk.

PEs at big corporate firms generally are not distributed energy experts. Their engineers will be less familiar with relevant codes and standards. As a result, they will spend longer researching them. And they tend to charge a premium for their time. By contrast, an energy-specific firm is less likely to burn so much time because its engineers are already well versed on codes and standards.

A PE firm specializing on distributed energy, like SepiSolar, has reasonable insurance, like a larger corporate firm. Our advantages come from direct relevant experience and strong customer service. Instead of taking time to learn the basics, we can review project designs for errors and omissions, then add value by helping to drive down costs and installation time, where possible.

Minimize risk

Project engineering is a risk mitigation service. That is, the level of engineering you purchase should be commensurate with the level of risk you can accept. After all, nobody is perfect. You want a safety net, even if you hope to never need it.

About 10 to 20 percent of SepiSolar customers get PE stamps as a matter of company policy, whether required by the authority having jurisdiction or not. One such customer is Peter Florin, the owner of Lucerne Pacific, an electrical contractor in Garden Grove, Calif., specializing in commercial solar projects.

“The biggest thing for me is that I feel I’m more protected. If anything really goes wrong, it goes on the PE that stamps the plan,” Florin says. “A lot of times, we can sign our own plans as a contractor. But that’s putting the liability on yourself.”

PE stamps nationwide

If you are a solar or energy storage contractor seeking a PE stamp anywhere in the US, contact SepiSolar to discuss your projects. You can also find information about PE stamps and all our commercial and industrial project services and residential project services at the SepiSolar website.

This post was written by Josh Weiner, Solar Expert Witness & Solar Engineering Expert. Mr. Weiner has been at the forefront of the solar energy industry for over 20 years and is an industry leader on solar-plus-storage engineering & design. Josh’s expertise spans both in-front of and behind-the-meter initiatives including residential, commercial, utility-scale, grid-scale, and ev charging solar and storage applications.

If you’ve spent any time in the San Francisco Bay Area, you probably know how terrible traffic congestion is. The 2018 Global Traffic Scorecard found that San Francisco commuters who travel during peak hours lose an extra 116 hours a year. That’s roughly double the time it would take, without congestion, to get to work and back home again.

We’ve been there. SepiSolar’s East Bay office is located close to San Jose and Silicon Valley. But a rush hour trip between destinations can easily take an hour or more. The problem isn’t getting better. Is there anything we can do about it?

One intriguing solution is urban air mobility (UAM), a budding industry that promises to take ridesharing services to the sky, using helicopters and eventually vertical-lift air taxis. In July, Uber plans to begin transporting customers between Lower Manhattan and JFK International Airport. A trip that can take 2 hours in traffic will be reduced to 8 minutes.

In meetings with UAM entrepreneurs and a recent visit to the 2019 Uber Elevate Summit, SepiSolar has committed to the engineering and design of microgrid systems for a new generation of transportation infrastructure. Through our experience getting approvals for solar and energy storage projects, we have solved many of the permitting and interconnection challenges that UAM companies will face.

Bringing together transportation and energy technologies not only helps UAM take flight. As we’ll explain, it also creates a new opportunity for microgrids to scale.

One type of distributed infrastructure meets another

Microgrids and helipads, the takeoff and landing platforms for helicopters and air taxis, have more in common than you might think.

For starters, both are structural systems that need access to the sky. If planned for the roof of a building, a project engineer must show that the roof deck has load capacity to support the weight of either system. In addition, either system must be able to resist maximum wind speeds at the project site.

Microgrids and helipads also have to comply with building and electrical codes and standards. In a young industry, there can be confusion and inconsistency in the way codes are applied from one jurisdiction to the next. Sometimes, even from two inspectors in the same jurisdiction.

Importantly, both systems provide benefits that serve the broad public interest. Microgrids make our electrical systems more efficient, reliable, and environmentally sustainable. Helipads have the same effect on our transportation system. By developing helipads near the most congested transportation nodes—like San Francisco’s financial district, where traffic routinely backs up to the Bay Bridge—the technology can help clear bottlenecks regionwide.

What rooftop aviation can learn from microgrids

Just as fuel costs are an issue for traditional airlines, electricity costs will help determine the success of next-generation helicopters and air taxis. Before asking an electric utility to supply energy for an aircraft fleet, UAM developers should understand how utility fees work.

Large energy users usually pay a monthly demand charge to cover the energy-generating capacity needed to satisfy demand at any time. The demand charge is based on a customer’s maximum energy usage captured during a short period of time.

If you kept the power off most of the day but charged a helicopter with a 100 kilowatt battery just once, the demand charge would be based on the time you spent charging. The demand charge, not including the fee for the electricity itself, could easily cost thousands of dollars per month.

Utility demand charges can make or break a rooftop aviation project.

Instead of sourcing all electricity from the utility, UAM developers can partner with a microgrid company to create a network that generates solar energy, stores energy in batteries, and provides intelligent energy management to achieve the lowest cost of electricity.

The SepiSolar team has industry-leading experience designing energy storage systems for demand charge reduction. CEO Josh Weiner was among the first in the industry to create a financial model showing how to improve return on investment by matching storage system outputs with on-site energy consumption.

Weiner has also applied numerous sections of the National Electrical Code and the UL code for energy storage projects to secure permitting approval in jurisdictions where there were, and in some cases still are, no established protocols for interpreting code.

Scaling urban air mobility and microgrids

UAM today is where distributed energy was almost 20 years ago. It’s a young industry built on promising technology that lacks the uniform standards needed to drive rapid growth. Bring these industries together and you’ll find that the whole is greater than the sum of its parts.

We have already described how microgrids can help UAM scale by providing a cost-effective electricity source. One that uses renewable energy and doesn’t strain the electric grid. But what opportunity does UAM bring to microgrids?

One obstacle to microgrid market growth has been the need to customize systems for each project’s energy consumption needs. Helipads can be standardized. And so can the microgrids that manage their energy supply. Once UAM companies offer a standard helipad and microgrid solution, the industry will truly be ready to scale.

The potential use cases are not limited to moving commuters in and out of the workplace, either. UAM companies can help deploy critical infrastructure. They can deliver food and water in the aftermath of an earthquake, a hurricane, or a flood. Or they can set up evacuation zones to transport people in an emergency.

Together, UAM and microgrids open up new possibilities.

Stay informed

To learn more about urban air mobility, see highlights from the Uber Elevate Summit and the Paris Air Show. During the Paris Air Show, an Airbus-owned company, Voom, which operates an on-demand helicopter service in Brazil and Mexico, said it will soon expand service to the US. The Voom website says the San Francisco Bay Area will be the third service area.

For the latest information on microgrid design, including microgrids for urban air mobility, follow SepiSolar on LinkedIn, Twitter and Facebook.

This post was written by solar storage design expert Josh Weiner, Solar Expert Witness. Mr. Weiner has been at the forefront of the solar energy industry for over 20 years and is an industry leader on solar-plus-storage engineering & design. Josh’s expertise spans both in-front of and behind-the-meter initiatives including residential, commercial, utility, grid-scale, and ev charging solar and storage applications.

A recent fire at a utility-owned energy storage facility near Phoenix, Arizona has implications for everyone who is standardizing around lithium-ion batteries to design storage systems. Since lithium represents about 95 percent of the market, this is a topic of near-universal interest.

Especially for me. My experience with lithium-ion batteries goes beyond the storage system engineering and design work we do here at SepiSolar. Ten years ago, not long after founding SepiSolar, I helped launch Green Charge Networks, an early leader in lithium battery deployments. That’s where I saw technology, product configuration, permitting, performance, and operational risks associated with lithium batteries begin to materialize.

The industry is moving fast to push lithium battery deployment to new heights, but we still cannot easily quantify risks. Nor the costs.

We at SepiSolar are technology agnostic. Our commitment is to openly consider the costs and benefits of all commercially viable design options. Given how many projects appear to be treating lithium as the only commercially viable technology, I encourage developers to reevaluate lithium—particularly after the recent fire in Arizona—and consider flow batteries as an alternative that can be deployed at lower cost, greater speed, and superior safety.

Arizona storage system fire

Reported facts about the fire at the McMicken Energy Storage facility are limited. Based on local media reports, we know that firefighters responded to an incident on April 19. While inspecting the 2 MW / 2 MWh battery system, eight firefighters suffered injuries in an explosion. The cause is unknown. All of the firefighters with the most serious injuries were in stable condition in the days following the blast.

The system owner, Arizona Public Service, switched off other energy storage projects in the aftermath of the fire but, as Greentech Media has reported, APS is not wavering on plans to deploy 850 MW of battery storage by 2025.

The entire industry will be paying close attention when investigators reveal their findings about the root cause of the fire and the ensuing sequence of events. Even now, however, developers can size up the inherent risks that all projects using lithium-ion batteries should address.

Lithium battery risks

Eight years ago, when the US Department of Energy awarded Green Charge Networks a $12 million grant to deploy lithium battery storage systems, I was bullish on the technology. If anyone was a believer in lithium, it was me. Then, one by one, the following risks came to light.

Degradation

Every time you cycle a battery, capacity and efficiency drops bit by bit. Performance on day 30 will not be the same as on day 1. How well does your financial model sold to your client calculate degradation along the performance line?

Thermal runaway

It’s critical to make sure that a battery operates according to its specification. This means when you integrate lithium batteries at a facility, the function of the HVAC system expands from comfort to safety. Now, when an HVAC system requires a little maintenance, it’s not just an O&M concern, but a safety risk. A battery that begins to operate outside of its normal temperature range can experience thermal runaway.

Hazardous materials

Lithium-ion batteries use materials that can introduce safety and environmental hazards if not properly contained. The storage industry needs an effective process for salvaging lithium, nickel, cobalt, or manganese. There’s no need to reinvent the wheel. We can borrow best practices from the solar industry, which has recycling for silicon-based solar modules and collection and recycling of cadmium-telluride thin film modules at the end of their operating lifetime.

Warranty claims

Lithium battery vendors have not yet established a track record showing the warranty claims rate. Or the frequency of warranty claims, which reflects the long-term failure rate for systems operating in the field. Early adopters carry the risk that failures may exceed expectations, straining the supplier’s ability to make good on all claims. In fact, engineers at one large lithium battery supplier have published a peer-reviewed scientific paper saying that lithium batteries are degrading faster than expected and proposing a patent to resolve the issue, suggesting that the risks should be taken seriously.

Human rights

Three years ago, the Washington Post published an expose on cobalt mining practices in Congo, where children help populate the workforce that uses hand tools to dig in underground mines, exposing themselves to health and safety hazards. Cobalt is an ingredient in lithium batteries. The Post has also traced the lithium supply chain from parts of Chile, where indigenous communities have struggled to protect the environment and win local economic benefits from the extraction and sale of the lucrative mineral.

Downstream costs

The low upfront cost of lithium batteries is only part of the total cost of ownership, one that excludes downstream costs associated with operations and maintenance of the batteries, the fire detection / suppression system, or the HVAC system that keeps the batteries within their specified temperature range. A failure to perform proactive operations and maintenance could not only increase long-term costs but void the manufacturer’s warranty.

Parasitic load

As industry analysts have gained a deeper understanding of how much storage capacity is needed to keep storage-integrated HVAC systems running, it appears that round-trip efficiency for lithium battery systems may be lower than originally thought. Citing Lazard’s ongoing levelized cost of storage analysis, Greentech Media has reported that parasitic loads could knock down system efficiency by 17 percent or more.

Advantages of flow batteries

In recent years, I have had many opportunities to compare lithium batteries and vanadium flow batteries side by side, while designing storage systems at SepiSolar and performing battery tests in partnership with Nextracker. The battery test, ongoing since 2017, consists of over two dozen battery types, including 5 lithium batteries, 6 flow batteries and 2 flywheels, plus an ultracapacitor, an advanced lead-acid battery, a copper-zinc battery, and a nickel-iron battery.

Through firsthand experience, one key observation at this point is that the market currently has two leaders in the race to achieve lowest total cost of ownership: lithium batteries and vanadium flow batteries. Vanadium flow batteries have earned a place on the leaderboard based on advantages in cost, performance, installation speed, safety, and design simplicity.

Cost

Please note, first of all, that battery costs vary based on storage system design and use case. The battery cost for a commercial system used principally for demand-charge reduction will be different than the battery cost for a grid-scale storage project designed for transmission and distribution deferral.

That said, Nextracker has shown that vanadium flow batteries can yield a lower total cost of ownership than lithium batteries due to significantly lower O&M costs over 20 years.

Speed

Nextracker has also demonstrated a competitive installation process with vanadium flow batteries. Installation of Nextracker’s NX Flow, a solar-plus-storage solution using Avalon Battery’s vanadium flow battery, requires less installation time and fewer materials than a central storage system due to being shipped “wet.” This means it’s full of electrolyte from the factory. It’s the first battery in the world to demonstrate this feature.

The battery is pre-commissioned and integrated with a 3-port string inverter at the factory. All battery-to-inverter wiring is complete on arrival. Before installation, the construction crew drives piles and installs cross rails to set up a mounting platform. Then the crew places the battery with a forklift and bolts the battery to the platform. Finally, the crew connects DC and AC wiring from the solar array to the inverter. Here is a 3-minute demonstration.

Safety

All plated batteries, including lithium batteries, have inherent safety risks. If you take the positive and negative sides and create a short circuit, the wire can get so hot that it explodes. Firefighters have reported on fires in electric vehicles that get damaged in a car crash, get towed, and catch fire days later.

Vanadium flow batteries have three key safety advantages. First, you can turn a vanadium flow battery off, preventing the device from charging or discharging altogether, and with zero voltage on both the positive and negative terminals. Second, the temperature rise in a flow battery is limited. Even if you short the battery on the chemical side or the fluid side, the temperature rises briefly and then drops, and the battery can be placed back into service immediately with no downtime to speak of. It’s the most boring test you’ll ever see. Finally, there are no flammable, toxic, nor hazardous materials or components. Check out this white paper on energy storage system safety from retired San Jose Fire Captain Matthew Paiss to learn more.

Battery design

Flow batteries are simple by design. They consist of two chemical solutions, one with positively charged ions, another with negatively charged ions. When connected to a generator (actually, a reversible fuel cell) the battery charges by pulling ions from the positive solution and pushing them into the negative solution. When you switch the battery to discharge, the ion flow goes in reverse and generates an electric current. The “secret sauce” of vanadium flow batteries is that the entire electro-chemical reaction happens in a purely aqueous state, which translates to “no degradation,” which translates to “lowest LCOS.”

Trust and visionary thinking

As a licensed engineering firm, SepiSolar’s first obligation is to follow national and jurisdictional codes and standards. The value of our design work depends on our ability to optimize the best products and technologies for the right applications that maximize benefits and minimize costs, all while providing structural and electrical engineering stamps in all 50 states. Beyond that, SepiSolar follows a set of core values that promotes trust and integrity, and encourages visionary thinking.

When customers approach us to design lithium batteries for residential and commercial applications, we do it. When customers ask us to advise them on the tradeoffs between battery technologies, we do that as well, covering all the topics raised here.

Our commitment to promoting trust and visionary thinking compels us to discuss openly the risks (and, therefore, costs) of lithium batteries, especially in the aftermath of the Arizona storage system fire. While we hope the industry can mitigate all the risks, many have not yet been fully addressed. Meanwhile, we owe it to the Arizona firefighters who suffered injury to engage in an open discussion about lithium batteries.

Our customers are remarkably entrepreneurial. We expect that contractors will quickly adapt to market changes by delivering storage solutions that balance cost, speed, and safety.

Please contact us if you want to learn more about engineering and design for storage systems using flow batteries.

This post was written by Josh Weiner, Solar Expert Witness & Solar Engineering Expert. Mr. Weiner has been at the forefront of the solar energy industry for over 20 years and is an industry leader on solar-plus-storage engineering & design. Josh’s expertise spans both in-front of and behind-the-meter initiatives including residential, commercial, utility, grid-scale, and ev charging solar and storage applications.

On January 31, 2019, the CPUC (California Public Utilities Commission) signed into law the most recent changes to the long-standing NEM (Net Energy Metering) tariff. While our white paper describes many of the financial benefits to the decision, we have received a variety of inquiries from industry stakeholders from across the value chain with interesting use cases of this policy change that are worth sharing. Like a fine, red wine, these ground-breaking policies often only get better with age, setting new precedents for future policies to come.

Electric Vehicle Chargers

For example, we reviewed a solar + storage + EV charging commercial project in California that was applying for EV charging credits from the State (contact us at blogs@sepisolar.com to learn more about these lucrative credits that start at ~$0.19/kWh!). In addition to DC-coupling the solar + storage, the developer also wanted to DC-couple the EV chargers.

Upon deeper analysis by SepiSolar, it became clear that the CPUC’s final decision sets a precedent for any DC-coupled device (not just storage) that charges exclusively from renewables (including EV chargers), since these EV charging credits get more valuable (anywhere up to ~$0.25/kWh) the more they charge from renewables. Based on our financial calculations, the difference in monetary ($) values between grid-charged-EV’s and PV-charged-EV’s is over 35%, so charging EV’s from PV in a DC-coupled framework adds a significant bonus to the ROI (Return on Investment) of the project.

SREC’s & AC Limitations on the Utility Grid

Another example comes to us from the east coast, where Pepco is evaluating SREC’s (Solar Renewable Energy Certificates) for energy storage as well as restricting the amount of PV power on their grid, due to infrastructure capacity constraints. Among the questions were: can SREC’s could be granted to exports from batteries that are exclusively charged from PV?

We are still going through the process of getting these approvals on specific projects, and so far, the answer appears to be a resounding “yes”! Not only do similar rules apply for the issuance of NEM and SREC credits, but de-rating the AC nameplate of the inverter (or, alternatively, “super-sizing” the DC nameplate rating of the PV system) appear to allow these projects to interconnect with the utility grid in a far more cost-effective manner. This is inherently because batteries are less expensive to install than infrastructure upgrades by utility companies.

In this particular use case, we are working on getting a 250 kW PV system approved with only a 50 kW AC interconnection limit. The only way to do this (cost-effectively) is by using a DC-coupled, solar-only-charging 400 kWh rated battery. At a $300k price tag for the battery with a 3-month lead-time, this resolves several problems for the customer, including:

Deferring a $500k “surprise” infrastructure cost from the utility (with a 10-month lead-time)
Allowing the customer to retain 100% of the original PV system size needed to offset electricity usage
Enabling demand charge reduction, which increases NPV and IRR
Adding back-up and resiliency capability, so the battery can supply energy to on-site loads when the grid goes down

REAP Grants

Recently, we have come across a number of agricultural businesses (rural businesses and agriculture producers) throughout the US who are now asking SepiSolar to evaluate the implications of this DC-coupled NEM framework in the context of the lucrative REAP (Rural Energy for America Program) grant. For those of you who do not know, REAP is a USDA-administered grant that can offset up to 25% ($500,000) of the total installation costs of a renewable energy system.

The question is this: Does the REAP grant apply to energy storage components? We, at SepiSolar, believe it absolutely does, and we’ve just recently submitted a grant application claiming the storage as part of the renewable facility property. The jury is currently out, but we’ll report back with hard answers to this question as soon as we hear back from the USDA.

When we set out to get solar-only-charging, DC-coupled batteries approved by the CPUC for NEM purposes, one of the first risks we wanted to investigate was whether or not such a policy change would result in a lengthy legal battle, or legislative nightmare, in the event that new (or existing) laws needed to be created (or changed).

We quickly discovered that there was precedent for our request in the RPS Standards (see Renewable Portfolio Standards Eligibility Guidebook), since it described energy storage as an addition, or an “enhancement,” to the renewable facility property, if and only if that storage device only charges from a renewable resource. This was unbelievably fantastic news because it meant that the legal structure, definitions, and policies were already in place, and no laws or bills would be required. Nobody had simply exercised the laws that were evidently already in place…that is, until now.

This discovery implied not only that a solar-only-charging energy storage system could (and should) accrue NEM credits, but also that the very definition of storage as an “enhancement” to the renewable facility, makes it just as exciting as adding a tracker motor, ballast racking system, auxiliary or lightning electrode, fuse, breaker, wire, conduit, combiner box, or perhaps any piece of equipment to the solar energy system. Basically, the more boring the legal repercussions appeared, the more exciting the policy work became.

So, if solar-only-charging batteries are just another type of “combiner box,” and are effectively part of the solar energy system (as an addition or enhancement), why shouldn’t ITC, MACRS, and, of course, the REAP grant apply?

All of these policies and legal precedents serve to reinforce the direction that DC-coupled, solar-only-charging batteries are headed – into the mainstream, and as an integral part of the renewable generating facility itself. Storage, by itself, can of course be treated as a stand-alone system with all the benefits thereof, but by reinterpreting storage as an enhancement to a renewable generating system, we get to leverage all the rules, laws, and policies already in place for renewables. This is a great benefit to storage, since renewables effectively give storage a legal and policy runway for accelerated adoption, without having to go through all the time, pain, and politics that solar and renewables had to go through (and are still going through). It’s 2 technologies for the legal / policy price of 1. That’s a good deal, and we should stop leaving money on the table for our customers.

As always, if you have more questions, please submit them in the comments section or send them to blogs@sepisolar.com. We’ll continue to keep you up to date on our progress in all these efforts and projects, and we look forward to bringing ever more value to our valued clients.

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