September 1, 2022

This summer, the California Public Utilities Commission rolled out a new set of rules for utilities to decide when solar and energy storage projects get permission to interconnect with the grid. We’ll share some information that has helped us understand what’s happened, plus a short Q&A we put together with support from the Interstate Renewable Energy Council (IREC), an advocate for regulations supporting clean energy adoption and a driving force for the new rules.

Interconnection is a mission-critical step in renewable energy project development. To get interconnection approval, projects have to show they can operate safely and reliably and prevent grid disruptions. Projects need an interconnection agreement before they can start exporting energy to the grid.

California, like many states, has had long-standing rules to screen projects for potential to compromise grid reliability so projects can be approved to interconnect faster when the risk of grid disruption is de minimis. But as more renewable energy projects come online, fewer projects are passing this screen.

Out: 15% limits on annual peak load

Under the old rules, projects passed this screen, avoiding additional time-consuming studies by the utility, if distributed energy made up less than 15 percent of the annual peak load on the nearest electric distribution lines. Once distributed generation topped the 15 percent limit, projects could be held up for further review. In a recent PV Magazine article, one project developer said commercial and industrial solar projects often wait more than three years for interconnection approval.

California’s new rules ditch the 15 percent threshold and replace it with a more precise analysis of the grid’s operational limits, known as a hosting capacity analysis (HCA). The analysis, as described on the IREC website, shows where distributed energy projects can seamlessly interconnect to the grid. It also shows where solar and storage can add value to the grid and where network upgrades are needed most.

Want to find out how suitable a project site would be for solar and energy storage projects? Here are maps with results from the latest analyses for California’s three investor-owned utilities.

PG&E and SDG&E require you to register and login before viewing their maps. PG&E provided instant access. SDG&E granted us access after a six-day wait.

The Sepi team would like to smooth the transition for the California contractors we work with, and help inform the manufacturers, contractors and consultants we’re in contact with throughout the industry. See our Q&A with IREC Communication Director Gwen Brown below. Responses have been edited for length. If you have more questions, share them with us on LinkedIn.

What should California contractors do to get prepared for the new interconnection process before it takes effect?

Familiarize yourselves with the hosting capacity analysis of the investor-owned utilities in the territories where you operate.

In: Hosting capacity analysis

How easy is it for contractors to view a hosting capacity analysis to know how a project might be affected by grid constraints in the interconnection process?

Searching an HCA map is like searching any online map, like Google Maps. Just enter the address to view a section of the grid and select the data you want to display. Each map has a legend and user guide for reference.

Here’s a map of the grid closest to the SepiSolar office in Fremont, California, showing the amount of PV generation that can be installed without any thermal, voltage, distribution protection or operational flexibility violations at the time the HCA analysis was performed. Lines with no capacity are colored in red. Lines with more than 2 MW of capacity are green. Purple and light blue show transmission and feeder lines.

Sample of a hosting capacity analysis map

Using tables, you can also view HCA data to find out precisely how much capacity is available for new generation.

Which projects will be eligible for expedited review?

The HCA is the new form of expedited review for all distributed energy resource projects, including solar and energy storage on both sides of the meter. From IREC’s press release: “Under the newly adopted rules, projects that do not exceed 90% of available capacity as shown in the ICA (a conservative buffer requested by utilities) will be able to pass the new screen. Projects that do not pass this improved screen will be subject to supplemental reviews; however, the rule changes also include significant improvements to the supplemental review process that are expected to allow a greater amount of DERs to be integrated through the screening process.”

All projects are now eligible for this review process. If you know a project will fail the HCA screen (that is, it exceeds 90 percent of available capacity), you might want to take another path, such as going directly to supplemental review.

When will contractors notice a difference in the interconnection queue?

Good question. Nobody truly knows the answer yet. It depends how the utilities manage the transition. Review times may vary from one utility to the next. In theory, at least, HCA maps can allow for rapid approval where the grid shows capacity for new projects.

The future of interconnection in California and beyond

Will there be differences in the way projects are treated across California’s three investor-owned utilities, its munis, and other electric service providers?

The process should be the same for each of the investor-owned utilities. Munis and other providers may not have the resources to perform an HCA. The details for each utility can be found in utility advice letters submitted during regulatory proceedings. Here is PG&E’s 342-page advice letter. The advice letter from Southern California Edison can be found here. A search for the file from SDG&E, Advice Letter 3677-E-B, on the utility’s web page hosting electric filings to the CPUC produced no results.

Is there any indication that another state will soon follow in California’s footsteps on streamlined interconnection?

According to IREC’s records on hosting capacity adoption in the US, last updated in February, 16 states are using HCA data in some form or another. The group includes New York, New Jersey, North Carolina, Michigan, Colorado, and Hawaii. A major limitation here is that the HCA has to be of high quality in order to be used for grid interconnection. California was the first to develop HCAs and has the best systems. A handful of other states (see HCA page linked above) have HCAs but most still have further work to do to get them to the point that they are ready for this application.

What other changes can California and other states make going forward to further simplify interconnection?

In the future, the plan per prior proceedings is that hosting capacity data will be used to allow developers to propose seasonal operating profiles for their projects so they could limit export in times when the grid has excess generation (such as spring, before load increases with AC use), and export more during times when that generation is needed on the grid (in summer). That concept was approved in Sept. 2020. Further work is needed to iron out the details. The timeline for that proceeding remains unclear. To learn more about emerging standards for scheduling the import and export of solar, energy storage, and other distributed energy resources, see Chapter 9 of IREC’s BATRIES toolkit for storage and solar-plus-storage interconnection.

Feature image by PG&E, accessed Sept. 1, 2022. PG&E updates ICA values on a monthly basis when significant changes to the feeder occur. Register for an account and login to see the most up-to-date maps in your service territory.

Matthew Hirsch


June 8, 2022

Fire safety has always been a hot topic in commercial and industrial solar, now as much as ever.

First responders need to know that crews won’t be put in harm’s way in the event of an emergency. Section 690.12 of the National Electrical Code has led many C&I projects to adopt extra equipment that can reduce system voltage at the flip of a switch.

Contractors have to adhere to safety standards. But they also have to look for opportunities to simplify construction and keep costs under control. Compliance can increase system costs, requiring additional hardware, longer installation times, and time-consuming operations and maintenance.

Manufacturers are starting to bring forward solutions that aim to address safety, simplicity, and cost. Inverter maker SMA America and mounting system supplier Sollega have obtained certification showing that the Sollega FastRack 510 and the SMA Sunny Tripower CORE1 meet the Underwriters Laboratory (UL) 3741 definition of a Photovoltaic (PV) Hazard Control System, as first reported by Solar Builder.

The finding is significant. It means projects can meet rapid shutdown requirements without needing module-level power electronics or mid-circuit interrupters. With permitting approval, contractors can look forward to a whole new category of system design options for rapid shutdown compliance. Sepi provides system design among our project planning services.

But one big question remains: What will the authorities having jurisdiction do?

AHJs are key stakeholders

Developers and asset owners invest a lot of time and money in C&I projects. Investors want to mitigate risk. You increase the risk of project delays any time you stand first in line for approval with a new solution.

The US has more than 20,000 cities and counties. Naturally, we couldn’t ask each one for an opinion on PV Hazard Control Systems. But as a service to the industry, we selected 15 AHJs in communities that install high volumes of solar projects. We included municipalities from the East Coast, the Midwest, the Rocky Mountains, the Pacific Coast, and Hawaii.

We contacted agencies where our communications team had direct contact information for at least one senior official in the department. Many did not respond during the one-week response period we provided.

The variety of responses and the response rate, at 20 percent, underscores some of the industry’s perennial challenges with project permitting. Not only the inconsistency from one jurisdiction to another but sometimes a lack of transparency.

Here are the responses we received.

UL 3741 approval in Sacramento, California

Michael Bernino, Sacramento’s supervising building inspector, consulted with an electrical plan reviewer and concluded that PV Hazard Control Systems would be treated as a design choice which is allowed by code.

“Given the fact that the proposed product is UL listed, it would be approved as code compliant,” Bernino said.

Alternative review process in Tampa, Florida

Florida has not yet adopted the 2020 NEC, which includes the UL 3741 standard for PV Hazard Control Systems. The Florida Building Code incorporates the previous 2017 code.

Until Florida adopts the 2020 NEC, JC Hudgison, Tampa’s construction services center manager and chief building official, suggests an alternative. Try an Alternative Means & Method Request (AMMR) to get projects with PV Hazard Control Systems approved.

The AMMR process gives building officials discretion to approve system designs that satisfy and comply with the intent of existing code. Designs must also provide at least an equivalent measure of fire resistance and safety.

Alternative review in Napa County, California, too

The City of Napa’s Building Division issues permits for commercial solar systems. But a senior building inspector, when asked about UL 3741, directed us to inquire with the county Fire Marshall.

Fire Plans Examiner Adam Mone explained that the Fire Marshall’s review would be limited to a comparison of system designs as presented against the 2019 edition of the California Fire Code. Mone encouraged us to talk with Napa County’s Building Division about compliance with the 2019 edition of the California Electrical Code.

We will update this post if we get Napa County’s perspective on UL 3741 PV Hazard Control Systems. UPDATE: According to Interim Chief Building Official Harvey Higgs, Napa will also accept UL 3741 PV Hazard Control Systems as an alternate means until January 1, 2023, when the 2022 edition of the California Electrical Code takes effect and the devices are explicitly allowed by code.

We will post additional responses from other jurisdictions too.

Ask an AHJ

Want our communications team to ask an AHJ in your community about approval for PV Hazard Control Systems? Send a message through our contact page or email us at [email protected].

Also keep an eye on our LinkedIn page. We post daily content for renewable energy professionals, including our new monthly feature: Ask an AHJ.

Matthew Hirsch


May 2, 2022

Forum, the Consumer Attorneys of California’s bimonthly magazine, discusses how engineering expertise can protect the interests of solar project owners in its latest publication. Sepi CEO Joshua Weiner, a member of the Consumer Attorneys of California (CAOC) expert witness referral network, wrote the article.

CAOC is a 61-year-old professional association based in Sacramento. It provides support and continuing legal education for over 3,000 lawyers. CAOC members represent plaintiffs and consumers on a wide range of claims, including those involving product safety and product defects.

Weiner’s article tells the story of a growing issue for property owners who produce solar energy. After installation, these systems do not always generate the expected financial returns. Consumers then wonder if their contractors can or should be held accountable. The article describes a representative case in Southern California that Sepi handled as an expert.

When expectations go unmet

At an RV park with 434.7 kW of solar generating capacity, Sepi found a system that was producing about 93 percent of its expected energy output but only 58 percent of expected year-one cost savings. Technical performance had hit the mark. Financial performance was amiss.

Utility rate tariffs, it turns out, were both the cause and the solution.

The contractor modeled financial performance based on one of many utility rates offered by Southern California Edison (SCE). The interconnection agreement, a contract that gives permission for solar project owners to interconnect with the utility grid, specified a different rate.

A change in net energy metering, which sets out compensation and fees for solar energy supplied to the grid, led SCE to switch the utility rate once again.

Finally, Sepi analyzed SCE’s utility rates and recommended a different rate that would restore most of the lost savings.

Expertise as a service

Sepi’s engineering team provides expertise for three groups of customers: companies creating solar and energy storage projects, companies creating solar and energy storage products, and various professionals, including attorneys, who need consulting services from an industry expert.

Expert witness services are an important part of our work for attorneys, representing both plaintiffs and defense. We fulfill discovery, analysis, and fact finding for projects that result in financial loss, technical failure, or contractual claims. Areas of expertise include project development, construction agreements, energy technologies, policy, finance, codes, and industry standards.

For free access to the entire March/April edition of Forum magazine, including our article on solar expertise for conflict resolution, visit the CAOC Forum 2022 article index.

To learn more about CAOC’s expert witness referral network, go to the CAOC Vendor Directory. Select ‘Expert Witness Referral’ in the ‘Services Provided’ drop-down menu. Leave all other fields blank, and click on the Search button.

Feature photo by Rachel Brown at Spring Green Graphics

Matthew Hirsch


April 1, 2021

FREMONT, Calif. — APRIL 1, 2021 — Propelled by growing concerns about electric grid reliability, lithium battery safety, and long charging times for electric vehicles, SepiSolar today announced the results of a six-month search for next-generation EV battery systems. The winner: rechargeable alkaline batteries.

The global alkaline battery market, valued at over $17 billion, is poised for year-over-year growth of nearly 10 percent due to a long cycle life, low cost, and proven hazard-free performance. You can also buy replacements at the neighborhood pharmacy or have them delivered in the mail.

SepiSolar has partnered with leading original equipment manufacturers on electrical system design for rechargeable alkaline batteries for electric vehicles (RABEVs). In Q2 2021, SepiSolar will also debut a Center of Excellence for Rechargeable Alkaline Battery Retrofits in Electric Vehicles (CERABREV) at a location near our company offices in Fremont, Calif., a landmark in automotive history since the 1960s.

“When I was a child, I sat behind the wheel of a 12V two-seater and dreamed of traveling cross country in an alkaline battery-powered car. Today’s announcement brings that vision one step closer to reality,” said SepiSolar CEO Josh Weiner.

SepiSolar will use our engineering expertise to maximize stored energy relative to the weight of the vehicle, leading to increased driving range. The team will also explore opportunities to incorporate alkaline batteries, including AA, AAA, and 12V batteries, into the body of the vehicle for improved structural integrity.

Sign up below to attend the CERABREV grand opening and test drive a AA Class vehicle later this year.

Reserve your place now.


Photo by John Holden on Unsplash

Matthew Hirsch


August 5, 2019

Lithium battery safety is not rocket science. Manufacturers with a robust set of production data can show customers success rates for their batteries and the conditions that cause batteries to fail. The problem is that very little safety data is accessible to most buyers or the public.

Buyers will always have to decide for themselves how much risk they are willing to tolerate. Some source batteries from a selective group of original equipment manufacturers (OEMs) and pay a premium to avert risks associated with the lowest-priced batteries. But many buyers are operating in the dark, lacking the safety data they would need to make an informed decision.

Consequently, the energy storage industry in its brief history has already witnessed dangerous and damaging lithium battery safety incidents, including the April 19 fire at Arizona Public Service’s McMicken Energy Storage facility. Other notable incidents include a lithium battery fire and subsequent battery malfunction that led the Federal Aviation Administration in 2013 to ground Boeing’s entire 787 Dreamliner fleet. The next lithium battery fire can happen almost anywhere, anytime.

To safeguard against fire risks, ask lithium battery makers the questions about cell production and testing in this post. Battery buyers don’t have to wait for technology development or new regulations. They can bring about a new safety standard by demanding better safety data and buying lithium batteries only from OEMs that make the data available.

Questions to ask about cell production

Some online shoppers go to commerce platforms like Kickstarter for innovative products and products that may be available at a significant discount from an upstart manufacturer. When sourcing lithium batteries, you want to take the opposite approach. Instead of pursuing innovative products, look for proven products that have a long track record of consistent production. Instead of hunting for discounts from unknown suppliers, expect to pay fair value for a product that has completed a rigorous safety analysis and achieved an exceptionally low failure rate.

How many battery cells and battery packs does your supplier produce each year?

One lithium cell represents one data point. The more cells you produce, the more data you have. As such, the highest-volume producers have the most data on performance, thermal runaway, and failure.

For this reason, an OEM producing 10 million cells per year should have a better understanding of cell safety and performance. Large-volume manufacturers have probably seen every possible failure occur many times. By the same token, a small-volume manufacturer needs more time to analyze and understand cell failure. Buying cells from small-volume manufacturers may carry more risk.

What changes have been made to the battery cell and battery pack production process?

A consistent manufacturing process yields predictable safety and performance results. It’s plain to see that different cell materials bring about different cells. But different production equipment can affect safety characteristics just as much. Even if the materials and equipment stay the same, a manufacturer that relocates production may alter a host of environmental conditions and other variables that affect results. Changes in relative humidity, temperature range, and impurities in the air can impact safety characteristics of lithium cells. Differences in quality control and other processes introduced by a new manufacturing technician crew can also have an effect. All these changes should be understood and quantified in a prudent lithium battery safety analysis.

How does your supplier handle material acceptance and storage?

Even if everything goes right during the manufacturing process, pre-production material acceptance and storage can affect lithium battery safety. About five years ago, a global supplier of solar inverters experienced a series of product failures after electronic circuit boards had been stored in the wrong warehouse and exposed to moisture. Once product assembly was complete and the inverters were energized, a short circuit on the boards caused a fire and led to quite a bit of property damage. While moisture can also affect battery cell safety, so can other environmental conditions, such as air impurities and particulate matter.

It’s not easy to perform a safety analysis that identifies failure points for battery cells. To test how moisture affects safety, you would have to take identical cells and store one of the cell materials in an environment that gets wetter in small increments until you find a statistically relevant number of failures. Then you would have to repeat the process with incremental changes in temperature, dust, and other variables. Testing would require a lot of cells, a lot of minor changes in cell processing, a lot of time, and a lot of analysis. And it would all have to be done without vastly increasing cell production costs.

What are the failure rates for your supplier’s battery cells and battery packs?

In the absence of industry-wide standards, contractors seeking assurances about product safety have their work cut out for them. First, they have to request failure rates and analysis from each of their suppliers. Then the manufacturers must provide the data. Next comes the subjective test. If the contractor feels comfortable with the risk, he or she can decide if the battery quality is adequate. Different contractors have different tolerance levels for quality. A contractor who installs one small system per year may not place a great deal of emphasis on quality. The chances of failure are small. However, contractors installing many large systems must pay more attention to quality. Their businesses depend on the successful operation of a much larger population of cells.

Consider an OEM with a 99.98 percent success rate for battery cells in the first three years of operation. That translates to a 0.02 percent failure rate. If a contractor installs 1,000,000 cells per year, the contractor can expect 600 cells to fail. [Multiply failure rate (0.0002) x annual production (1,000,000) x number of years (3).] This might be an unacceptable level of risk. On the other hand, if a contractor installs 10,000 cells per year, the contractor can expect 6 cells to fail. This level of risk might be no big deal, so long as those cell failures don’t propagate to the entire pack or the entire storage system.

Questions to ask about cell testing

We all know not to leave a fireplace unattended or a gas oven running when nobody’s home. We understand that doing so introduces a serious risk of fire. But how many people know the temperature threshold that is likely to cause a lithium battery to catch fire or explode? Before procuring lithium batteries, especially those that will be sited at a building where people live or work, be sure to understand the conditions that create lithium battery safety hazards. Safety hazards that start in a single battery cell can quickly spread to the battery pack and the entire energy storage system.

What are your supplier’s battery cell thermal runaway characteristics?

It’s important to understand how a battery cell responds to the conditions that can initiate a fire or an explosion. There are many ways to test lithium cells for these conditions. Some examples are the top nail test, where a nail of standard size is driven with standard force into the top of the battery, and the side nail test, where the same procedure is carried out with a battery lying on its side.

Other tests include the fast heat test, where a battery inside a control chamber is exposed to a rapid temperature increase; the slow heat test, where a battery is exposed to a slow temperature increase, and the overcharge test, where a fully charged battery stays connected to a power source and is continually charged.

What is the probability of thermal runaway for your battery cells?

With test results in hand, you can make reasonable predictions about how a battery will perform according to design specifications. Graph 1 shows how increased temperature leads to thermal runaway. While all five cells exhibit similar power generation as temperature increases, there is a notable difference in how close each cell comes to the failure point represented by the horizontal red line at 160°.

how increased temperature leads to battery cell thermal runaway

Graph 1

Graph 2 shows how constant temperature over time leads to thermal runaway. The battery cell depicted by this graph remains at very low risk of thermal runaway when temperature is held constant at 159°. But a 1° increase in constant temperature vastly increases the probability of thermal runaway. A 2° increase makes thermal runaway a near certainty.

how constant temperature over time leads to battery cell thermal runaway

Graph 2

One of the challenges when characterizing lithium cell failure is calculating at what temperature and over what duration a cell fails. Because the answer is different for each cell, we need to see how different the answers are. What if one cell failed after two hours at 60°, another cell failed after 5 hours at 190°, and a third cell failed after 3 hours at 250°? This data would be difficult to characterize. It seems like almost every temperature is dangerous and could lead to cell failure.

Now what if the data looked more like this? Cell 1 fails after two hours at 160°, Cell 2 fails after two hours at 161°, and Cell 3 fails after 1.5 hours at 162°. This data suggests that thermal runaway is consistent and predictable. If we can find consistent results, we know when failures occur and how to prevent failure by designing systems for lithium battery safety.

How does thermal runaway spread from cell to cell?

This is really a two-part question. For starters, let’s look at how thermal energy from a failed lithium cell gets distributed across neighboring cells. Do all neighboring cells get the same amount of energy from the failed cell? Does one cell get all the energy while the others get none? Do two cells get 90 percent of the energy? Next, let’s look at how much stress an initiator cell applies on neighboring cells. If a failed cell exposes neighboring cells to temperatures up to 120°, the risk of cell-to-cell propagation is low. The risk is much higher if a cell failure has a magnitude of 180°. If energy is distributed unevenly, we would want to know the magnitude of stress for each of the neighboring cells.

What are the conditions that lead an entire battery pack to catch fire?

If cell-to-cell propagation extends to one or two neighboring cells and stops, failure of the whole battery pack or battery module is unlikely. If cell-to-cell propagation extends to hundreds of neighboring cells, it’s far more likely that the entire pack will burn. By understanding when battery packs catch on fire and start heating up the neighboring packs, the system designer can plan for fire detection and suppression systems as required by NFPA 855 and UL 9540A to kick in as a last line of defense.

What are the conditions that lead an entire energy storage system to catch fire?

If a fire containment system fails to contain a fire within the energy storage system enclosure, the charging infrastructure for the batteries may also catch on fire. (Think of a car catching on fire while being pumped with fuel at the gas station. Fire can spread to the gas pump, then the entire gas station.) Once the charging infrastructure is on fire, the entire property, including its occupants, are at risk. In sum, one battery cell failure can lead to the destruction of an entire building and the loss of life.

Demand lithium battery safety data

A safe battery is a well-documented battery. Test data helps engineers, system integrators, system owners, and regulators make smart, effective business decisions. While data doesn’t eliminate risk, it does inform us of the risk. Therefore, data empowers us to make decisions on how to manage, contain, suppress, mitigate, or ignore it. By putting appropriate measures in place, we can reduce risk to an industry-acceptable level. Without test data, a battery might operate safely today, but we don’t know why. Then if conditions change and the battery is no longer safe, we won’t know how to mitigate the risk.

The industry can expect a steady supply of safe lithium batteries as soon as buyers make purchasing decisions conditional on access to safety data. There are many safe batteries on the market. But there are many more cheap, risky batteries on the market. The simple solution is to buy safe batteries—which might mean accepting a higher price.

Contractors should request data from OEMs or look for third-party evaluations from independent engineering (IE) reports or independent test laboratories. The data is not publicly available, or hard to find, which is a serious problem. UL, the “gold standard” in product safety, even has trouble gaining access to this sort of data. So one requirement in the UL 9540 standard is to capture thermal runaway data, even for batteries that pass all the tests. In other words, when a lithium battery goes for the UL 9540 test, the test lab will force the battery into thermal runaway and then document the results to help characterize lithium cell failure.

Matthew Hirsch


July 22, 2019

We’ve seen this movie before. In 2008, project developers in the US prepared for the sunset of the 30 percent federal investment tax credit (ITC), a key source of financing for solar projects of all sizes. Urged on by industry lobbyists, Congress passed legislation extending the tax credit, and President George W. Bush signed it.

In 2016, the ITC was again due to expire. Congress and President Barack Obama gave the tax credit new life, preserving its 30 percent value until the end of 2019. In addition, they established a gradual step down over three years. In 2022, the credit settles at 10 percent for commercial and utility-scale projects. For residential projects, the credit goes away.

As the industry rallies to defend the ITC, this might look like the opening scenes of another sequel. But there’s no guarantee that the story concludes with the same happy ending.

With less than six months till the end of the year, let’s mobilize for the best possible outcome. But let’s also be prepared for expiration of the 30 percent ITC. After all, the tax code, under a mechanism known as the safe harbor provision, allows qualifying projects to preserve the full value of the 30 percent credit as projects advance through the development lifecycle, including projects that come online in 2020 and beyond.

A design and engineering firm can provide crucial assistance as the clock winds down on the 30 percent ITC. Because our services can help qualify projects for safe harbor, developers and EPCs working with SepiSolar can create value while taking steps to show that a project has commenced construction for federal tax purposes.

A specialized firm can also share knowledge about securing tax credits for solar and storage projects and maintaining eligibility throughout the project lifecycle.

Value creation for projects

When a developer engages an engineering firm to begin processing interconnection agreements, perform feasibility studies, and obtain PE stamps for project plan sets, this work buys valuable time for projects to mature.

The benefits to the developer are twofold. Project design work can help keep the 30 percent tax credit in play even after the calendar turns to January 2020. It also creates an opportunity to smooth workflow. Instead of hustling to complete projects in December, developers can start scheduling for the start-of-year “slow season.”

EPCs also benefit by increasing projected revenue. What’s good for the developer is good for the nimble EPC.

While evaluating tax equity for solar projects, consider opportunities to claim the fuel cell ITC for stand-alone storage projects. Vanadium flow batteries qualify because charging and discharging happens in an aqueous state through an embedded fuel cell. The process of preserving the 30 percent ITC is the same for qualified fuel cells as for solar projects.

In addition, SepiSolar can help design solar-plus-storage projects to optimize tax credits for different project risk profiles. To qualify for the ITC, a renewable energy source must supply more than 75 percent of energy to the battery.

In an AC-coupled configuration, electrons must be “counted” and “measured and verified” each time they’re generated and sent to a battery. Depending on generating capacity, storage capacity, and the project use case, it may be difficult to meet the 75 percent rule, thereby putting the tax credit at risk.

In some cases, it might be better to switch to DC-coupling for tighter control of ITC compliance. In a DC-coupled configuration, a project can ensure that all energy to the battery comes from PV and none from the grid. This would not only comply with ITC but maximize it.

Applying for ITC safe harbor

There are two ways to preserve eligibility for the 30 percent ITC under the tax code’s safe harbor provision. A project can start physical work, or it can incur 5 percent of an energy property’s total cost.

Design and engineering generally does not meet the conditions of the physical work test. But these services can be included in the 5 percent safe harbor test. As noted in a 2018 advisory from the IRS:

Construction of energy property will be considered as having begun if: (1) a taxpayer pays or incurs five percent or more of the total cost of the energy property, and (2) thereafter, the taxpayer makes continuous efforts to advance towards completion of the energy property.

To satisfy the continuity requirement over the months and years to come, projects can pay additional amounts toward the total cost, enter into binding contracts to produce project components or the project itself, obtain project permits, or perform physical work on the project.

Consult a licensed tax advisor with questions about how to apply provisions of the tax code to specific projects.

Engineering for safe harbor

Design and engineering services that help a project qualify for safe harbor under the 30 percent ITC can quickly pay for themselves. After all, the difference between a 30 percent credit and the 26 percent credit that kicks in on January 1, 2020, may be greater than the total cost of design and engineering, especially for commercial and industrial projects.

For instance, consider a 500 kW flat-roof solar project with an all-in cost of $1.50 per Watt.

Project cost


30 percent ITC (2019)


26 percent ITC (2020)


ITC difference


Estimated design and engineering fee


Estimated savings


Contact SepiSolar to find out how we can help secure safe harbor for solar and storage projects, extending development and EPC activities past the busy end of year and into the normally quiet early months of the new year.

Matthew Hirsch


July 8, 2019

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.


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.


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.

Matthew Hirsch


June 24, 2019

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.

Matthew Hirsch


June 3, 2019

SepiSolar project engineers use one powerful solar design tool to perform many system design functions. Some are completed in minutes. Others take hours. This points to a perennial challenge we face as a customer service organization committed to continual improvement.

When all support requests go into a single queue, quick and easy tasks don’t always get resolved quickly enough.

The fact is, our solar design tool is necessarily complex for highly trained engineers working through a streamlined process. But if you separate the pieces, you’ll find several user-friendly tools that contractors can use themselves. A wire size calculator and a string configuration calculator, for example.

Later this year, SepiSolar will provide six web tools for contractors to perform quick and easy design tasks. Our engineers will continue to handle any project design changes, or all of them if you’d like. We are always available with a wide variety of customer support resources. This is just one opportunity, when the cost of waiting for support on a simple design change exceeds the benefit, for SepiSolar to empower our customers to use some of our solar design tools yourself.

When to use our design tools

Each time a change request comes in to SepiSolar, an assistant project manager or operations manager tags it according to priority, complexity, time needed, and root cause. Tickets go into queue for the engineering team sorted by priority.

If a contractor submits a support ticket to resize a run of wire estimated to be 100 feet but later measured at closer to 200 feet, the complexity and time required would be set to “low.” The same might be true for a contractor wanting to move an inverter from inside a building to a location outdoors, who needs to know if the wire size must change.

Using SepiSolar’s wire size calculator, you enter inputs such as current through the conductor, number of wires in the conduit, and the project site’s maximum ambient temperature. The calculator auto-populates electrical resistance and generates the wire size that you need.

When there’s no urgency, let SepiSolar run the calculation. On the other hand, if you’re in the field and a quick calculation can prevent a return trip to the project site, direct access to our wire size tool can save time and money, eliminating a costly truck roll.

Complex and time-consuming design changes will continue to go directly to the engineering team. For example, an EPC might want to replace 60-cell modules with 72-cell modules in the plan set for an 850 kW agricultural project. Our engineers would use the new module specifications to recheck wire sizes and overcurrent protection and redraw the module array as needed.

If an EPC wants to replace central inverters with string inverters, in order to optimize the project for cost, then instead of using these calculator tools, our engineers would begin a consultation to help with inverter selection, AC wiring design, and DC wiring design, which is what creative, solutions-focused designers do best.

DIY solar design tools

The solar design tools that SepiSolar will make accessible to our customers on the web are simple and user friendly. These tools are not revolutionary. They just make a contractor’s job a little easier, one day at a time. Here’s how they work.

Wire sizing calculator

Oversizing electrical wire means overspending on materials, given the current that will flow through the system. To undersize means the system is carrying so much current that you risk melting conductor wire or insulation. Correct wire sizing avoids both extremes based on conductor material (copper or aluminum), current through the conductor, environment (in conduit, direct buried, or open air), how many conductors in conduit, insulation type (THHN, THWN-2, USE-2, XHHW), and ambient temperature plus adders for the environment.

String sizing calculator

Module string configuration introduces another set of tradeoffs. If you connect too many modules in series, the system can exceed an inverter’s maximum input voltage, causing equipment damage. Connect too few modules and you might fall short of the minimum input voltage required to start up the inverter. To determine string configuration, look at your solar module datasheet and input the following data points into the SepiSolar calculator: solar module manufacturer, model name or number, and quantity; inverter manufacturer and model name or number; racking type (e.g., flush or tilted roof mount, ground mount); maximum, minimum, and average high and average low temperature at the project location.

Conduit sizing calculator

The National Electrical Code limits how much wiring can go inside a conduit. It does so to control heat gain, manage risk of wire damage, and preserve space to eventually add more wires. In the NEC, you can find fill tables for frequently used wire and conduit types and equations for any application. Or input wire and conduit specifications into our conduit sizing calculator to get a fast and dependable conduit size.

120% rule

The 120 percent rule refers to a simple calculation used to confirm that the size of an electrical distribution panel in a home or business facility is large enough to handle the capacity of the circuit breakers feeding it. Most of these residential electrical panels have a 100 amp or 200 amp main breaker. For solar projects interconnected on the customer side of the meter, the National Electrical Code allows total ampacity from all sources up to 120 percent of the busbar or conductor rating. Why? In brief, it’s because when you connect a supply source to the service panel, it has the opposite effect of connecting a load source to the service panel. Instead of reducing capacity on the busbar, the solar generator actually increases capacity.

Voltage drop calculator

Voltage drop is a measure of efficiency in an electrical circuit. A 1 percent drop in voltage equals a 1 percent power reduction at the end of the line. Electrical calculator programs are generally available, but they don’t always consider all solar project inputs, as noted in Solar Pro. (See Issue 3.2, ‘Voltage drop in PV systems’) To calculate voltage drop, input circuit type: AC (1-phase or 3-phase) or DC, nominal voltage, current, wire gauge and material (aluminum vs copper), and the length of your conductor run.

Load calculator (structural and electrical)

Before issuing project permits, local authorities will compare system specifications to the electrical load and structural load requirements on site. Using SepiSolar’s load calculator, customers can size a building’s electrical service capacity based on service voltage (1-phase or 3-phase) and the sum of all motor loads, continuous loads, and non-continuous loads. To generate structural load limits, customers can also enter module weight and quantity, the number of modules racked in portrait and landscape, racking rail weight, rack type (tilt up or flush mount), weight adders (microinverters, optimizers, ballast blocks), and a measurement of wind exposure, such as wind speed, exposure zone, or the mean height of the roof.

Unlike other design tools

Contractors looking for solar design tools will find a variety of options on the market. Some products generate project proposals for use in the sales process along with plan sets for permitting and interconnection. Others require experience with sophisticated CAD software.

SepiSolar’s user-friendly tools are relatively simple in comparison. These are calculators used by licensed engineers, governed by codes and standards that protect public health and safety. They do not take the place of a licensed engineer. They complement the engineer’s work, empowering contractors to make code-compliant calculations yourself and increasing the value of the SepiSolar service.

Matthew Hirsch


March 7, 2019

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 [email protected] 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 [email protected]. 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.


Matthew Hirsch

CA Small Business Enterprise

Certification ID:

Bidder/Supplier ID:

NAICS Codes:
541330 – Engineering services
541340 – Drafting services
541490 – Other specialized design services
541618 – Other management consulting services
541690 – Other scientific and technical consulting services
541990 – All other professional, scientific, and technical services

D-U-N-S number:

811024, 81101701, 81101516, 81101604, 43232614, 81101505

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