April 13, 2023

The California Public Utilities Commission (CPUC) recently passed the NEM 3.0 bill, which brings significant changes to the state’s net metering policy compared to the previous NEM 2.0. As a homeowner or business owner interested in solar, it’s essential to understand the differences between the two policies and the new opportunities they present. In this blog post, we will explore the key differences between NEM 2.0 and NEM 3.0, and how to effectively sell solar panel systems to maximize savings under the new policy.

NEM 2.0 vs. NEM 3.0: Key Differences

The Value of Export Rates

Under NEM 2.0, customers received a full retail rate for any excess electricity they exported to the grid, allowing for a faster return on investment (ROI) in solar energy systems. With NEM 3.0, export rates have been reduced by about 75%, meaning customers will receive less money for the energy they sell back to their utility company. As a result, it may take longer for homeowners to recoup their investment in solar energy.

Instantaneous Netting

NEM 2.0 calculated electricity rates every hour based on a user’s net generation and usage during that hour, which was more favorable for solar customers. NEM 3.0 introduces instantaneous netting (or rapid cycling), allowing meters to communicate in real-time instead of hourly. This change may result in less financial benefit for solar customers and more complex calculations.

Grid Participation Charge

NEM 3.0 introduces a “Mandatory Grid Participation Charge” that requires all participants to pay a fee for using the network’s resources and services. Solar customers can expect to pay an extra $8 charge per kilowatt (kW) of solar power capacity, resulting in an average additional cost of $48 per month for homeowners, further reducing solar energy savings.

Strategies for Maximizing Solar Savings under NEM-3.0

Emphasize long-term savings and environmental benefits

Despite the policy changes, solar energy systems still offer significant long-term savings on electricity bills and environmental benefits. Communicate the long-term advantages and the positive environmental impact of solar energy investments, such as reducing greenhouse gas emissions and conserving natural resources.

Promote solar+storage solutions

With NEM-3.0 encouraging battery storage adoption, solar providers can promote solar+storage solutions to maximize self-consumption, take advantage of time-of-use (TOU) rates, and provide backup power during outages. By incorporating battery storage, customers can offset the reduced export rates and increased grid participation charges under NEM 3.0, achieving substantial long-term savings.

Offer tailored solar+storage solutions

With NEM-3.0 encouraging battery storage adoption, solar providers can promote solar+storage solutions to maximize self-consumption, take advantage of time-of-use (TOU) rates, and provide backup power during outages. By incorporating battery storage, customers can offset the reduced export rates and increased grid participation charges under NEM 3.0, achieving substantial long-term savings.

Leverage available incentives and financing options

Despite the higher initial costs of solar+storage systems, customers can still take advantage of various incentives, such as the federal solar Investment Tax Credit (ITC), California’s Self-Generation Incentive Program (SGIP), and other state and local incentives. Additionally, offering flexible financing options like solar loans, leases, and power purchase agreements (PPAs) can make these systems more accessible to a wider range of customers.

Build trust through transparency and education

Establish credibility with your customers by being transparent about the costs, savings, and potential challenges associated with solar+storage installations under NEM-3.0. Provide honest and accurate information, and educate your customers about how solar+storage systems can help them maximize their savings and reduce their environmental impact. By fostering long-lasting relationships built on trust and transparency, you will position yourself as a valuable partner in their clean energy journey.

Conclusion: Learn to thrive in California’s dynamic solar energy market

Although the NEM 3.0 policy brings significant changes to California’s net metering landscape, there are still opportunities for solar providers to help customers maximize their savings. By understanding the key differences between NEM 2.0 and NEM 3.0, promoting solar+storage solutions, offering tailored recommendations, and leveraging available incentives, you can help your customers make informed decisions and achieve long-term savings. By adapting your sales strategies and focusing on the benefits of solar+storage, you can continue to thrive in California’s dynamic solar energy market.


March 8, 2023

In today’s rapidly changing world, companies are always looking for ways to streamline their processes and provide their customers with the best possible experience. SepiSolar is no exception. As a leading provider of renewable energy engineering and planning, the company is constantly seeking new and innovative ways to improve its services and stay ahead of market demand.

That’s why we are excited to announce that we are now able to perform in-person site surveys! Led by Peter Florin, our resident electrical contractor of 45 years, SepiSolar is now able to perform site surveys for projects in California.

In-Person Surveys Reduce Project Costs

In the past, SepiSolar relied on 3rd parties or remote surveying techniques to gather information about potential sites for renewable energy installations. While these methods were fast and cost-efficient in the beginning, they had their limitations and impacts to cost and schedule further down the project timeline. For example, remote surveys often lacked the detail and accuracy needed to provide a comprehensive assessment of a site. This could lead to clarifications that are found late in the design process, which could lead to issues during planning and construction that ultimately lead to change orders, impacting project costs and schedules.

With in-person site surveys, SepiSolar is able to gather much more detailed and accurate information about a potential site. The survey team will visit the site in question, assess the physical and environmental conditions, and gather data on factors such as potential electrical interconnection locations, electrical upgrade needs, conduit paths, and even roof details for structural feasibility analysis. This information will be used to streamline the design process, mitigate negative impacts to cost and schedule, and reduce construction risks.

site survey

SepiSolar is Committed to Strong Industry Relationships

In-person site surveys also provide SepiSolar with the opportunity to interact with the site owners and other stakeholders. This allows the company to answer any questions they may have, address their concerns, and provide a more comprehensive and personalized solution. This level of customer engagement and support is essential for building strong, long-lasting relationships with clients.

The addition of in-person site surveys to SepiSolar’s services is just one of the many ways that the company is driving innovation in the energy industry. With a commitment to providing the best possible experience for its customers, SepiSolar is poised to continue growing and evolving to meet the ever-changing needs of the market.

SepiSolar Leads the Way for Renewable Energy Design and Engineering

SepiSolar’s ability to perform in-person site surveys is a major step forward for the company and a significant development in the energy industry. With more accurate and detailed information about potential sites earlier in the process, SepiSolar can minimize project costs while designing the most effective and efficient renewable energy systems. By putting the customer at the center of its services, SepiSolar is positioning itself for long-term success.


December 23, 2022

Last month we launched a Thanks/Giving program that expressed gratitude to our clients for their loyal business in 2022. With that gratitude we wanted to give back. We searched for an organization that fit not only the mission and goals of SepiSolar, but also the missions and goals of most of our clients so that, in a way, we were donating on their behalf. We searched for an organization that supported the growth of the solar industry, and alleviated burdens of low income and disadvantaged communities.

On Wednesday, November 23rd, we announced that 1% of SepiSolar’s expected 2022 net income would be donated to GRID Alternatives. In this month’s blog post, we’d like to tell you more about Grid Alternatives, and why we feel they’re a good fit for our Thanks/Giving program.

About Grid Alternatives

GRID Alternatives is a non-profit organization that works to promote and provide access to clean, renewable energy for low-income communities. Its mission is to make renewable energy technology and training accessible to underserved communities, and to promote the use of renewable energy as a means of addressing social, economic, and environmental issues.

GRID Alternatives works on a variety of projects in the United States and internationally, including the installation of solar panels on the homes of low-income households, the development of community solar projects, and the implementation of energy efficiency measures in affordable housing. The organization also provides job training and education programs for individuals from underserved communities, helping them to enter the renewable energy industry.

GRID Alternatives’ work has a number of impacts, including reducing greenhouse gas emissions, improving public health by reducing air pollution, and providing affordable access to clean energy for low-income households. The organization’s job training programs also help to create career opportunities in the growing renewable energy industry, particularly for individuals from underserved communities who may have previously had limited access to these types of jobs.

GRID Alternatives Helps Low Income Families

GRID Alternatives has a number of specific impacts on low-income families:

1. Reduced energy bills: By installing solar panels on the homes of low-income households, GRID Alternatives helps to reduce energy bills and make energy more affordable for these families. Solar panels can generate a significant portion of a household’s energy needs, which can result in significant savings on monthly energy bills.

2. Improved health: GRID Alternatives’ work helps to reduce air pollution, which can have a number of health benefits for low-income communities. By promoting the use of clean, renewable energy sources, GRID Alternatives helps to reduce the negative health impacts of air pollution, such as respiratory issues, heart disease, and stroke.

3. Economic benefits: GRID Alternatives’ job training programs can provide economic benefits for low-income families by helping individuals from these communities enter the renewable energy industry and gain access to well-paying, stable jobs.

4. Environmental benefits: GRID Alternatives’ work helps to reduce greenhouse gas emissions and protect the environment. By promoting the use of clean, renewable energy sources, GRID Alternatives helps to reduce the negative environmental impacts of fossil fuel use, such as air pollution and climate change.

Overall, GRID Alternatives’ work helps to improve the quality of life for low-income families by reducing energy costs, improving health, providing economic opportunities, and protecting the environment.

GRID Alternatives Trains the Next Generation of Solar Professionals

GRID Alternatives provides a variety of training programs to help individuals enter the renewable energy industry and become solar professionals. These programs include:

1. Hands-on training: GRID Alternatives provides hands-on training opportunities through its solar installation projects, where individuals can work alongside experienced solar professionals and learn about solar panel installation and other related skills.

2. Formal education programs: GRID Alternatives offers a range of formal education programs, including courses and certification programs, to help individuals learn about renewable energy and gain the knowledge and skills needed to become solar professionals.

3. Apprenticeship programs: GRID Alternatives offers apprenticeship programs that provide on-the-job training and education, allowing individuals to learn from experienced professionals while also earning a wage.

4. Job placement assistance: GRID Alternatives provides job placement assistance to help individuals who have completed its training programs find employment in the renewable energy industry.

Overall, GRID Alternatives’ training programs are designed to provide individuals with the knowledge and skills needed to enter the renewable energy industry and become solar professionals, with a focus on helping individuals from underserved communities gain access to these types of careers.

During this season of giving, we encourage everyone to give generously to an organization they believe will make the world a better place. We chose GRID Alternatives. Whatever your focus or beliefs, let’s all find ways to contribute, to give back, and to uplift those less fortunate than us.

From all of us here at SepiSolar, Happy Holidays and Happy New Year.


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.


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

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


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


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


May 31, 2020

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.

  • Enphase IQ7+
  • SolarEdge SE7600H
  • SolarEdge SE11400H
  • SolarEdge SE-66.6K
  • 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.

Equipment costs

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 except the combiner panel for the Enphase IQ7+. That one I priced at

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.

Price list

Company Equipment Cost
Enphase IQ7+ 129
100A AC Combiner panel 74
SolarEdge SE7600HD 1,706
SolarEdge SE11400H 1,360
SolarEdge P400 Optimizers 77
SolarEdge SE-66.6K 2,822
SMA SunnyBoy 7.7 (41) 1,360
SMA TriPower 12000TL 2,375
SMA TriPower CORE1 62 5,343
SMA TS4-R-F RSD Devices 26

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.


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.


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.

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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