In a recent analysis of energy storage test results, SepiSolar engineers Taylor Bohlen and Richard Dobbins noted the shortcomings of system availability as a measure of long-term performance.
System availability quantifies the percentage of time that a storage unit has been operating. If a system stays online, charging and discharging power for 750 hours during a period of 1,000 hours, system availability is 75 percent.
Do you want to know how well the system is performing while it’s online? Or the impacts that product failure events have on performance? These questions are critical for energy users, system operators, and grid managers. But system availability doesn’t answer them, and we don’t want to sift through archives of data to find the answer.
So the SepiSolar engineering team got together and created a metric that does. We adjusted the definition of availability, so it’s weighted by the operational capacity of the system, giving us the battery’s weighted availability.
Weighted availability is the missing piece of the puzzle. It’s one number that takes into account several different aspects of availability and reliability, including mean time between failure (MTBF) and mean time to repair (MTTR). You could also call it average discharge capacity or average functional capacity.
Weighted availability provides a quick snapshot of how an energy storage system is going to perform long term. And it allows comparisons across energy storage products of all types, such as lithium, flow, and flywheels.
This post will show you how to calculate weighted availability for any time interval. We hope this improves your independent engineering evaluations for purchasing, warranties, system design and more.
The weighted availability difference
Availability by itself means practically nothing. A system can be on nearly all the time, but if it’s performing suboptimally when it is on, availability can mask real issues with the system. By the same token, for a system that’s on for a little less time but performs always at peak capacity, availability can understate how well the system performs.
One battery system in our analysis really drove home the importance of digging deeper into availability and reliability. With system availability at almost 87 percent, this battery appeared to be one of the best-performing units in the lab. But the performance history told a different story.
Since March 2020, the battery manufacturer has suspended maintenance due to COVID-19, with components that appeared to be nearing the end of their service life. The manufacturer limited cycling depth to prevent battery damage and maintained a limited cycling profile through October 2020.
Inverter failures in 2018 and 2019 also contributed to reductions in energy dispatch until the manufacturer completed inverter replacements and upgrades in May 2019.
For all the time that this battery curtailed cycling and limited energy output, the system was operational. There was no impact on system availability, but weighted availability was reduced at times by one-third or two-thirds due to inverter failure. The error and the impact of the error are captured in weighted availability.
To drill deeper and understand why weighted availability was getting pushed down, see MTTR, the average time needed to restore the unit to full operational capacity after a failure event. In this case, MTTR was nearly 86 days.
When independent engineers evaluate batteries, we look at how operational characteristics affect risk-adjusted value. One system might increase performance but also increase the need for maintenance. Another system providing less energy might reduce downtime and maintenance costs.
We created the weighted availability metric to show a more complete picture of the use and lifecycle of each battery unit.
Calculating weighted availability
Here’s the formula for availability where Operational Time means a unit of time where battery operational capacity is greater than 0, and T equals total installation lifetime, or time since the beginning of an initial battery cycle.
Now, here’s the formula for weighted availability.
Instead of measuring when the system is operational, weighted availability calculates available power at each measure of time and divides it by the system’s nominal power.
For the best analysis, look at weighted availability along with all the other metrics. If you’re designing residential storage systems to keep the lights on and small electronics charged during intermittent breaks in utility service, availability might still be the most useful metric. If you’re developing microgrids with complex storage needs, weighted availability can help you decide whether to accept suboptimal performance or dispatch a maintenance crew.
Better yet, look at multiple metrics in tandem. If you have a battery with 99 percent availability and 90 percent average discharge capacity, you can know that the system will be available nearly all the time and, of the time the system is operational, you can expect it’ll be performing at 90 percent of its rating over the long term. That’s more than you’d know if you had only one metric to work with.
The movie Moneyball, released in 2011, tells the true story of how a small-market baseball team used sabermetrics—essentially, baseball statistics—to compete with the big boys.
Old-school talent evaluators used subjective criteria to identify which players were destined for stardom. Attitude. Perceived confidence. The shape of the jaw. They also used simple performance metrics like batting average, the ratio of hits to total times at bat.
Through quantitative analysis, some teams realized that swagger and batting average have little meaning. As a better predictor of success, they looked at two metrics, on-base percentage and slugging percent, and added them together.
On-base percentage is the ratio of hits and walks to total times at bat. Slugging percentage is a weighted measure of hits to at-bats with extra weight ascribed to doubles (two-base hits), triples (three-base hits), and home runs (four-base hits).
If the weighted average of battery systems becomes a standard metric, it will help improve our understanding of energy storage like sabermetrics improved our understanding of baseball.
California has an enormous need to bring new energy storage capacity on the grid, especially for commercial and industrial (C&I) energy users. As you’ll see below, the project pipeline reflects the need. However, procurements and interconnections are not keeping up with demand.
What’s standing in the way of market growth for C&I energy storage in California? A little bit of everything. Although California is a market leader, it takes longer to complete project permitting than in other states, like Florida and Nevada. Interconnection costs are higher, too. One way to make utility rates more energy storage-friendly would be to shift from monthly demand charges to daily demand charges, as described below.
Median inspection times for on-site commercial-scale energy projects in California are slow, according to solar data collected by the National Renewable Energy Laboratory. The wait time tends to be 19.5 days. This contributes to a wait time of nearly 3 months overall for permitting, interconnection, and inspection. California can speed up inspection times.
Many utilities in California and around the country require no fee to apply for interconnection for on-site energy projects. The investor-owned utilities in California are different. PG&E customers pay an interconnection fee of $145. San Diego Gas & Electric customers pay a $132 fee. Southern California Edison customers pay a $75 fee. California can eliminate interconnection fees.
Utility rate design
In November 2019, PG&E introduced commercial rate tariffs with daily demand charges, becoming the first utility in California to do so, according to the California Solar + Storage Association. Instead of collecting demand charges based on the highest single interval of demand in the monthly billing cycle, PG&E’s new approach assesses charges according to the highest level of demand within set periods each day. For system operators, this offsets the risk of unpredictable demand charges and the need for risk mitigation.
When PG&E introduced daily demand charges, California regulators limited participation to 50 MW of storage for each rate tariff offering daily demand charges, or 150 MW overall. Regulators should make daily demand charges the norm in California and make sure they are accessible to commercial customers throughout the state.
In 2019, California regulators gave operators of solar-plus-storage projects an opportunity for the first time to export battery power onto the grid and receive net energy metering (NEM) credits for the output. NEM for storage has huge implications for the market, as we explained in a recent blog post.
NEM for storage eliminates the need for expensive meters, relays, and switchgear.
It simplifies design for solar-plus-storage systems.
And it builds consensus around the value of distributed energy resources at a time when legislators and utilities are pushing hard to undercut NEM for solar.
For a Riverside County office building, SepiSolar Chief Electrical Engineer Richard Dobbins designed a 694.9 kW array of solar canopies to cover the parking lot and an 87 kW, 193.5 kWh battery energy storage system for an enclosure at the edge of the property. See our solar and storage design examples page to download the project’s site plan, three-line diagram, parts list and more.
Have a C&I solar project of your own?
If you have a C&I solar project and need some design and engineering expertise, don’t hesitate to contact us for help. Simply click below, provide some details about your project and we will follow up promptly to discuss it with you.
Solar advocates and investor-owned utilities are feuding again.
The arguments might sound a little wonky but take our word for it. There’s no love lost here. This is a rematch from California’s last skirmish over net energy metering (NEM) five years ago. And the many disputes that follow similar battlelines from solar state to state.
The utilities contend that NEM imposes an unfair cost shift from solar customers onto everyone else. People who champion solar say the benefits continue to outweigh the costs, and regulations should facilitate the energy transition rather than slowing it down. (For all you who are not policy geeks out there, those are fighting words.)
The problem confronting the grid isn’t new. The transmission and distribution networks, designed a hundred years ago to send power in one direction from centralized generators to end customers, has struggled to accommodate the need for bidirectional energy flow with producers popping up all over the place.
The solutions aren’t new, either. Two years ago, California adopted a proposal developed by SepiSolar that allows DC-coupled solar-plus-storage systems to qualify for NEM for the first time, in cases where storage exports only solar energy back to the grid.
Instead of driving up costs with utility charges and artificially lowering the value of solar, California can eliminate an entire system cost category, accelerate the transition to distributed energy resources, and resolve the conflict over NEM once and for all.
It’s time to set aside our differences and embrace energy storage.
Let’s do this.
Eliminating interconnection costs
California’s adoption of NEM for storage represents one of those rare occasions where engineering and policy reform work hand in hand to reduce hard costs and soft costs all at once.
Beforehand, AC-coupled solar-plus-storage systems needed separate inverters for generation and storage. They would routinely run up against grid constraints due to the relatively high AC nameplate rating. And higher system costs due to meters, relays, and switchgear equipment. And lower efficiencies due to power conversion in both directions—DC to AC and back again.
DC-coupled systems also faced the prospect of adding meters, relays, and other electrical equipment at the behest of the utility. And adopting system size limits based on the local distribution infrastructure. These requirements had been put in place to prevent system owners from gaming the system, like mini Enrons, charging batteries when electricity prices are low and selling when prices are high.
The utilities needed a way to tell a unit of solar energy apart from any other unit of energy on the grid. So did the IRS, which awards federal tax credits for storage based on how much energy comes from renewable sources.
Through a partnership with Nextracker and support from the California Solar and Storage Association (CalSSA), SepiSolar showed that a firmware modification to the DC-coupled inverter and battery system could be as effective as all the expensive hardware the utilities had previously required us to install. The inverter firmware disables the battery’s ability to charge from the grid.
It’s win-win scenario for system owners and utilities.
Accelerating the energy transition
The solution is elegant. Today, DC-coupled solar-plus-storage systems are no longer arbitrarily capped by the utility. Systems can use just one inverter and a single DC-AC inversion path. No extra meters, relays, or switchgear. The inverter’s AC rating determines system size, as it always has with solar projects that qualify for NEM.
And the entire project qualifies for the full investment tax credit. There’s no need for complex metering, additional relays, and the whole nine yards.
It’s true what they say, that the pace of evolution is speeding up. Here’s human evolution over 7 million years.
And here’s how the single-line diagram has improved for solar-plus-storage projects, going from the height of complexity (AC-coupled systems) to a little less complexity (DC-coupled systems before NEM for storage) to pure simplicity (DC-coupled systems after NEM for storage).
Turning the corner on NEM
The tone of this post has been a little tongue in cheek at times, but we recognize that the stakes are high for the solar industry and by extension the burgeoning energy storage market.
Last month, CalSSA warned members that a consulting firm had pegged utility costs associated with NEM so high that San Diego Gas & Electric would have to charge residential customers on NEM tariffs $177 per month just to break even.
While it’s unlikely the California Public Utilities Commission would approve such an astronomically high fixed charge, state regulators are considering fixed charges in the range of $50 to $70. Plus monthly charges of $5 to $7 per kilowatt (kW) installed. Plus $10 to $20 per kW each month in demand charges. All while cutting daytime net metering credits down as low as 10 cents per kilowatt-hour (kWh).
The California solar market will likely suffer if this is the outcome for NEM. A decision is expected to take effect in 2022.
NEM is also under a new threat in the California Legislature. Yesterday, the Assembly Utilities and Energy Committee approved a bill, AB 1139, that would make going solar more expensive for everyone. See CalSSA’s description of the bill for more info.
Meanwhile, regulators and industry advocates must not lose sight of the impact that NEM will have on energy storage. When solar is concerned without storage, it seems like there’s no room for compromise. Storage, on the other hand, has advantages for everyone.
For now, NEM for storage is optional. Systems can add batteries or leave them aside. In the future, regulators could make storage a requirement for NEM.
All that would be left to decide is at what penetration level would the storage requirement kick in.
At that point, solar advocates and utilities can take matters back into their own hands.
We can’t agree on everything, after all. Can we?
Seeking innovation solutions to extraordinary technical challenges? Contact us and we’ll show you what we can do.
It’s one of the biggest misconceptions in project design and engineering: Permitting is all about technical compliance. Yes, you have to prove that the electrical system you intend to build satisfies all the codes that protect public safety. But there’s more to it than that. There’s an often-overlooked psychological component involved in the permitting process.
Imagine filing a permit application on a paper napkin. If it has all the necessary lines, squares and circles, equipment specifications, locations, and other requisite data, you’d have a complete application. But at least 9 times out of 10, your application would be rejected.
And for good reason. Because permitting is not only about code compliance. It’s about building trust and accountability. It’s about convincing the local permitting office that smart people have expertly designed your system for safety and reliability.
How do we win permit approvals? To begin with, we follow these five strategies:
Local permitters treat building and electrical codes the way that some people interpret the Bible, or the US Constitution. It’s not enough to size wire by multiplying output current by 125 percent. Instead, show your calculations and cite the latest version of National Electrical Code Article 690 approved in your jurisdiction, as well as any other applicable codes.
Spell out all the details so it’s clear that you not only know how to design systems but why the codes are in place to begin with. Plan checkers are going to ask questions. Get ahead of the game by showing them you know what you’re talking about.
Some system designers and engineers have a natural aversion to sharing too much with the permitting authority. As the thinking goes, it’s easier to ask forgiveness than to get permission.
That’s not always the best approach. The concern with sharing too much information is that the permitting authority will seize on small details to probe deeper, delaying approval and potentially altering project plans.
In our experience, permitters behave according to human nature. If you withhold information, they treat you with suspicion and distrust. If you’re upfront about complexity and nuance as well as your thoughtful solutions, and you show open-mindedness in response to questioning, you gain a measure of respect. This dynamic will carry over to future visits to the permit office. Good representation will improve your reputation with local permitters.
Call for backup
In many cases, SepiSolar customers have contacted us from the service counter during a conversation with a permit officer. It’s like having an on-call technical support hotline. We can answer permitting questions in real time. On more than one occasion, at the conclusion of these conversations, our customers have walked away with approved permits in hand.
Hedge against risk
Search engines have made everybody seem smarter by putting information at our fingertips, but at the same time our knowledge base has become a mile wide and an inch deep. The same thing is happening to an extent with the UL standards for energy storage systems. People can cite UL 9540, but not the component-level certifications for batteries, inverters and other key products.
If you don’t understand the various UL standards, you increase risk in the permitting process. When projects depend on system-level certification, any question that comes up about the test lab used for UL listing, or the test procedures, or anything else, can slow down permitting and add on project costs. On the other hand, applicants who know they have inverters that comply with UL 1741 and batteries that comply with UL 1973 have a fallback plan, so they can hedge against risks in the permitting process.
Channel your inner electrician
A lot of solar designers and solar engineers know about the 120 percent rule pertaining to energy generation, but they have no idea about NEC Article 220, which is all about loads and load calculations. Electricians and electrical engineers, on the other hand, know Article 220 like the back of their hand, but not the common solar codes.
System integrators today in all segments of the market need to design for systems that can dynamically change modes of operation, ramping up or down, quickly or slowly, staying still, or supplying any number of power applications, such as reactive power and VAR control.
System controls have a direct impact on system safety and code compliance. Integrators should understand all the modes of operation and be sure system designs comply with each mode affecting generation and load.
Ask us about complete design and engineering services
If you would like to reduce risk in the permitting process for your solar and energy storage projects, find out how SepiSolar approaches design and engineering for C+I solar projects and energy storage projects, and send us your project specifications today for a fast and accurate design quote.
Nobody remembers when you get the interconnection process right in solar or energy storage projects. The mistakes? Those stay with you longer.
A California developer who contracts project engineering and design work to SepiSolar once tasked a construction firm with handling interconnection. Due to miscommunication, nobody submitted the interconnection application to the utility.
The system was built. The utility refused to turn it on, as you’d expect. The developer filed an interconnection application, but found out the property is located in a secondary network area, part of the distribution system in urban areas designed to meet higher reliability needs and space constraints.
SepiSolar re-engineered the system to prevent power exports to the grid. We made the best of a difficult situation. But make no mistake. The solution increased the overall cost of the project and sacrificed a lot of revenue. All in all, it was a bad outcome for the project developer brought on by poor interconnection administration.
Getting interconnection right
Successful interconnection administration means more than preparing application forms and turning them in. It also means communicating clearly with the utility, responding to information requests and clarifications, avoiding delays, managing changes and making sure system designs match the system that will be interconnected to the grid.
If SepiSolar had managed the interconnection process for this developer, we would have submitted a pre-application before performing any detailed engineering work, which is part of our standard process for complex interconnections (say, on a secondary network), to verify that subsequent development work like designing, engineering, planning, etc. are even worth pursuing. This is all part of managing project risks in a cost-effective way.
Not all contractors want to act as the intermediary between engineering and the utility, especially when interconnection service may require some amount of input from engineering. After giving out a lot of advice on an hourly basis, we’ve created a standard interconnection service package.
The offering is well defined, responsive to our customers’ needs, and closely coordinated with project engineering. Keep reading to find out why we’ve come to believe it makes perfect sense for project engineering to handle interconnection administration and how interconnection service can add value to your projects at a reasonably low cost.
Interconnection and engineering are intertwined
Interconnection and engineering are parallel processes that continually intersect and diverge. A change to the interconnection application impacts engineering and vice versa.
For starters, engineers provide AC power calculations for interconnection. Routine changes in module or inverter supply simultaneously affect engineering and interconnection.
Further on in project planning, the engineers go off to develop project designs while the interconnection team sorts account names, meter numbers, interconnection type, data submission, and utility verification.
The groups come together again if the utility throws up a surprise interconnection cost, or if the project needs utility approval to establish a point of connection on the utility side of the meter.
A utility-side point of common coupling (POCC) can reduce project costs and can be obtained by verifying code compliance. Sometimes this means doing some research to see if the electrical panel was designed for this type of connection. Or maybe commissioning an inspector to recertify the switchgear.
Once resolved, engineering goes back to supporting construction crews with information requests while interconnection works to get project approval from the utility, signed agreements, and formal permission to operate.
Why not do interconnection administration yourself?
SepiSolar provides interconnection checklists for projects in the SoCal Edison, San Diego Gas & Electric, and PG&E service territories. This increases transparency and accountability with our customers, showing you how we perform the service. But it doesn’t mean we recommend doing interconnection service yourself.
The checklist is a starting point for data collection. What we do with the data determines the path to interconnection.
In some cases, it’s as simple as selecting the most appropriate utility rate tariff, such as NEM-V or NEM-A rather than standard NEM. Sometimes even NEM-MT or non-export makes more sense. In some instances, these choices result in a net savings on interconnection service.
If projects incur utility infrastructure costs, like a million-dollar feeder upgrade, energy storage can help buffer those costs. Other solutions, like demand reduction and energy arbitrage, can go beyond cost mitigation to improve project financials.
Interconnection administration costs
For years, solar project development was all about driving down CapEx. Engineers have strong opinions about modules and inverters. Investors mainly wanted to know about the levelized cost of electricity. If one project doesn’t pencil out, let’s move on to the next one.
Times are changing. As the federal investment tax credit steps down—it’s 4 percent lower than last year and will be another 4 percent lower in January—system performance has a greater effect on return on investment. Energy storage is also affecting long-term performance. All this means developers are showing more interest in projects that don’t have the lowest possible CapEx but can generate the most overall value.
Solar is no longer an analysis of cost only. It’s a cost-benefit analysis, as it ought to be.
SepiSolar charges a base rate for interconnection services on projects with a single meter. More complex projects with a NEM-A or NEM-V rate tariff and those with more complex interconnection processes incur added costs based on the number of meters.
We’ve handled interconnection administration for multi-family housing with over 40 meters. And we have yet to encounter a project we couldn’t manage.
Here to help
Interconnection administration is the most important part of any project. If a project fails at interconnection, it cannot operate and in most cases the goals of the project cannot be achieved.
Yet interconnection is also the most convoluted process riddled with rabbit holes, traps, administrative challenges, and costs. It’s a fascinating process that requires a solid administrative team.
A project engineer who’s familiar with your project can reduce risk and free up contractors to focus on what you do best, construction and customer service.
Ever heard someone say one man’s trash is another man’s treasure? They might be talking about a site survey for a distributed energy project.
We know. Some contractors don’t value site surveys.
Here, let’s take a poll. Results are anonymous. Tell us what you truly think.
If you marked any of the first three answers, chances are you view site surveys as a necessary evil. Maybe an unnecessary one.
So why is it that sophisticated, experienced developers and construction firms build in-house staff to handle site surveys? If we were in your shoes, we’d have site survey expertise in house too.
Site surveys are hands down the most important part of the discovery process.
In addition, we’d augment internal resources by contracting with a specialized project engineering and design firm. Bringing engineers, construction managers, project managers and project owners together for a couple hours, you get the best insight on your project all at once. With a trusted engineering and design team that can be on site in your place, as needed, you can also turn to outsourced service when your own bandwidth is constrained.
The site survey is an intimate and high-touch activity that is supremely important for overall project success. All the information, requirements, and other pieces of the installation process fall out of the original site survey. Site surveys make or break sales verification, discovery, data acquisition and analysis, and the entire project plan.
The problem with doing a site survey alone
You make decisions efficiently when the project host, the contractor, and an independent engineer are on site together. Instead of passing questions and answers back and forth remotely, with expected delays and potential for miscommunication every step of the way, we can all walk it through and talk it through at one time, in one place, and make decisions accordingly.
It’s not easy to select conduit paths and construction means and methods within project engineering constraints. But when you weigh the options on site, you flush out the best ideas to draft and the details to check and verify in a feasibility assessment.
Site survey is a collaborative process. You get a limited analysis when one party performs a site survey alone.
Project planning is complex. The site survey can address many of the challenges that emerge through development and construction, including
Operational constraints of the host during and after construction
Labor constraints from workplace safety authorities, such as Cal/OSHA
The goal of a recent site survey that SepiSolar performed at the office of an industrial services company in Northern California goes well beyond obtaining engineering requirements. We captured details for a structural engineer to determine whether the structure can handle the additional load of a rooftop solar project. We compiled photos and information for potential paths of conduit and appropriate electrical switchgear and infrastructure. And we delivered findings to the contractor, along with a property report showing highly accurate building dimensions.
Expected outcomes from a good site survey
Thorough project planning consists of far more than engineering feasibility. It includes sales verification, discovery, and data acquisition and analysis.
The site survey is the first line of defense for testing and verifying expectations set in the sales process. Why wait when you can get a technical expert involved to resolve problems before they cost money?
Whoever does the site survey should be familiar with the entire construction process. This will help prevent the ‘snowball effect’ that happens in poorly managed construction projects.
Think about real estate. Often, salespeople and developers overestimate the space available for a project. Why? They’re not looking at fire setbacks, property setbacks, shading obstructions from parapet walls or HVAC units, and other nuanced bits of technical detail.
Another commonly missed detail is the run of conduit, giving rise to a host of questions that only an experienced project engineer would ask.
Should conduit go inside the wall or outside?
How does conduit affect aesthetics? And wall fire ratings and sealing?
If conduit goes underground, should there be trenching or boring?
Are there cheaper or better ways to run the conduit with fewer penetrations into / out of the building?
We’ve seen deals where 20-30 percent of the entire job is in the conduit run.
Think about a solar project on a six-story roof. You can’t run conduit outside the building because of aesthetics and bay windows that run ceiling to floor. So conduit must find its way down six floors and a basement or a parking garage.
This is no small conduit, either. We’re talking 2- to 2.5-inch tubes. Each requires fireproofing and sealing when penetrating fire-rated walls. Some go through crawl spaces or cavities in the ceilings and floors. There are lots of holes to drill and interior surfaces to open and close back up.
What is the best time and place to evaluate and discuss options? The site survey.
Site surveys are inherently part of the discovery process.
Everyone has had that horrific experience when someone misses one detail, just one, causing immeasurable problems downstream. Often by surprise.
An independent engineering and design firm has to think about permitting requirements, site constraints, equipment specs, design strategies, construction means and methods, and more. All these facets work their way into the process anyway. Professional assistance can help you address them during the site survey.
We know a contractor that always conducts site surveys on its own to save cost. On one project at an agriculture facility, the contractor read “208 delta” on the nameplate of the panelboard and noted it in the site survey.
After construction, the inverters wouldn’t fire up. Input voltage was too high. To make matters worse, PG&E had to upgrade the transformer to accommodate the energy expected to backfeed to the grid. The utility crew installed the new transformer to the specification on the panelboard.
The entire site lost power. The site owner brought in backup generators to keep the business running. PG&E had to replace the transformer again, at the customer’s expense. The contractor also swapped out inverters. And we essentially redesigned the project post-construction. It was very expensive. Liabilities and losses continue to emerge. All because the site survey said “208” instead of “240.”
Measuring on-site voltage at the main service panel, a 5- to 10-minute process, would have solved the problems before they began.
Data acquisition and analysis
Yes, data acquisition is important. But it’s not just about grabbing data points. It’s about grabbing the right data points. And all the data points. It’s good to be accurate, precise, and comprehensive.
Engineers need to think comprehensively because plans are inherently meant to communicate the entire project’s construction to permitting officials, utility officials, and construction teams.
When we see a building’s architectural plans during discovery, we ask for the as-builts. We all know what gets built isn’t always the same as the design.
Hunting for as-built plans is a process itself. We try the owner first. Then the construction company that finished the work. If neither has them, we dig them up from city records (sometimes in microfiche, in the basement), scan them (sometimes with a large-format scanner), and work to decipher them for assistance in the design phase.
One overlooked detail is data exchange. All the tools we now have to exchange data—email, Box.com, Dropbox, FTP, SepiSolar portal, SMS—are great. But they can lead to failures.
Communication transmits and receives information. Many times we receive information through three or more communication channels, all for the same project. Letters and packages get lost in the mail. We’ve all tried to view information online and found access is denied. All these little exchanges are failure points, opportunities for good, hard-earned data to get lost or misplaced.
Sidestep these risks by having an engineer on-site to directly grab details.
Walk away with a sound project plan
The best outcome of a site survey is to walk away with a plan. After the site survey, there will be details to verify and research. But the overall plan should be sound. A sound plan needs consensus from the design, construction, and ownership teams.
It is very efficient to have all stakeholders together at the job site, developing a plan to execute most advantageously.
Download SepiSolar’s site survey checklists for C&I projects, energy storage projects, and residential projects. Or contact our technical sales team to find out how SepiSolar engineers can add value to your next site survey.
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.