December 9, 2021

Putting a project together for the first time? Not sure where to start in the confusing jungle that is energy project development?

You probably have a few questions:

  • Does my project pencil out?
  • Can I connect to the grid?
  • Do I have the right site?

It’s important to resolve these questions sequentially. You’re best off addressing revenue discovery and selecting among technologies and products before approaching site feasibility. And model cash flows before asking for permission to interconnect with the grid.

Working closely with a solar development engineer, someone who can lead an energy project through every stage of development, you get more value than by keeping project development and engineering in silos.

Here’s how a development engineer can help eliminate confusion for new developers.

Does my project pencil out?

Let’s start with the revenue. It has to be high enough to justify the cost and risk of developing a new project. Revenue can come from a variety of sources — utilities, municipalities, ISO markets, aggregators, consumers, to name a few. The revenues available for solar-only projects in saturated markets are dwindling, but energy storage provides a new opportunity for sites that are strategically located.

What about all the various costs that come into a new project? Let’s start with the cost of land. It has to be low enough for your project to make low-cost energy. The assumed cost of a land lease should be about 2.5¢ per Watt per year for utility-scale projects and commercial ground-mount projects, according to the National Renewable Energy Laboratory.

You also need access to capital, someone who will buy the energy you produce, and an interconnection agreement granting permission to connect with the electric grid. That leads us to the next question.

Can I connect to the grid?

Proximity to a load-serving entity also affects the cost of the project. All things being equal, projects sited closer to a utility substation will incur lower interconnection costs. This is important as grid interconnection costs are on the rise in several US regions, including the northeast, the midwest, and the southwest.

The sequence of events has not changed. But solar project developers, especially first-time developers, tend to recognize that the early stages of the process can be tedious, that an interconnection agreement means money, and go straight for the goal. This is a mistake.

Do I have the right site?

Your site is in the desert, not a tree in sight, and gets beautiful sunlight all year long. What’s not to like? Wouldn’t everyone want to buy the energy that your site could produce?

Well, these types of remote locations might bode well for production. But deliverability suffers due to higher costs of transporting energy across long distances to reach the site of consumption. In other words, “more sunlight” doesn’t always mean “more money.”

Why interconnection can’t come first

It’s reasonable to question the status quo. We live in an age of disruption fueled by new ideas. What if you could specialize in the lucrative business of obtaining interconnection agreements and let someone else handle the rest?

Would it be like starting a race halfway to the finish line? Sort of.

But instead of discovering a shortcut, you will find yourself running further, all the way back to the starting line before you can continue along your way.

That’s because of two fundamental laws of project development.

1. Changes upstream require subsequent changes roughly 99 percent of the time.

2. It’s slower and more expensive to do project development out of order. Maybe not always; just about 99 percent of the time.

Any good construction manager will tell you about the need for a detailed geotechnical analysis to understand impacts of soil corrosivity, groundwater, and other subsurface conditions before solidifying an approach to civil engineering and structural design.

Pile driving is expensive. If you overspend on equipment, material, and labor, the impact on project financials will be noticeable. Underspend and the consequences may be ruinous.

Two solar specialists at Burns & McDonnell, a leading EPC firm, have said in a Power Engineering article that change orders stemming from an incomplete geotechnical study “can sometimes result in seven-figure cost differentials.”

Preconstruction activities can also derail a project. Just think what would happen if you designed a solar project and procured equipment on the assumption that you could easily export power to the grid, only to discover that interconnection would require severe limits on power exports?

This is not a hypothetical scenario. It happened.

The solar development engineering process

When a developer first contacts SepiSolar about project engineering, we usually begin by identifying whether plans call for interconnection in front of the meter or behind the meter. The answer helps us know which engineering processes to follow.

If it’s a rooftop solar project connecting behind the meter, there’s no need to explore the most favorable markets and the most feasible sites for development. These decisions are already set in stone. Operating within the given constraints, we can tell you how to maximize system size and begin to model project cash flows accordingly.

Behind-the-meter projects benefit from streamlined engineering. Front-of-the-meter projects go through SepiSolar’s development engineering process.

You invest more time upfront. But instead of hoping your basic assumptions are correct—Interconnection via PJM, Midcontinent ISO, or Southwest Power Pool? Solar only or solar-plus-storage?—you’ll use data to make the right decisions.

Development engineering follows a six-step process based on a chronological series of questions each project needs to answer.

Solar development engineering questions


1. First, what type of system should we build? Policy research, tariff research, and incentive research help decide whether you can make more money with solar, solar-plus-storage, or neither.

Right now in California, solar has a 14- to 15-year payback period. If you’re focused on developing projects in California, plan to build solar with batteries.


2. Once you know the type of system to build, it’s time to narrow down the options by technology, vendor, and product. If batteries are part of the equation, should they be lithium batteries or flow batteries? How to select from a multitude of module and inverter options?

A development engineer will perform due diligence looking at bankability studies, warranty analyses, and more to recommend the least cost/best fit alternatives for your project.


3. Next, let’s look at your site. Is it in a swamp? In extreme wind, could it blow away? Answers from your completed feasibility study will identify what you can build on the property, site constraints, and what hoops you’ll have to jump through.

Solar developers sometimes try to bypass the initial questions and begin with cash flow modeling, but this often leads us back to that very first question: Where’s the money?


4. With cash flow modeling and system sizing, you will know for the first time how much money a project can make. This is a magical moment, a point where developers make go/no go decisions on large-scale projects. Are the decisions based in fact or fiction? That depends on the analysis that came beforehand.


5. Assuming you have decided to go forward with development, the next question is, where to place the equipment based on property setbacks and easements, the location of access roads, staging areas, and electrical equipment? The answers produce the details needed for a conceptual design that you’ll need to submit to the authority having jurisdiction (AHJ) and the utility.


6. Finally, what are the local requirements for permitting and interconnection approval? Once you satisfy these requirements, at last, it’s time to think about the start of construction.

Talk to us about development engineering

As the solar and energy storage industries have grown, the development engineering process has stayed largely the same. The underlying value comes in two parts.

First, the ability to stick with the process. There’s always pressure to move faster through solar project development. It can be tempting to accept someone else’s word about site feasibility. A good development engineering team will independently verify the risks itself.

Second, the ability to keep up with rapid changes that affect the types of projects to develop and where to build them. Policies and tariffs may shift from year to year, even quarter to quarter. Product research next year will look quite a bit different than the due diligence you performed a year ago.

Visit the SepiSolar development engineering service page to learn more about how we can support your utility-scale projects and commercial ground-mount projects and to get in touch with our team.


September 16, 2021

It might seem counterintuitive but it’s true. If you want to save time and money by avoiding change orders on your solar and energy storage projects, spend some time and money on value engineering before you get too far down the road.

Trial lawyers know how this works. Get all the facts up front so there are no surprises when the time comes to stand before a judge and jury. A good lawyer is more than an advocate. A good lawyer performs a detailed investigation, assesses risk, and works to achieve the best possible outcome.

The same is true about a good project engineer. When you’re building solar and energy storage projects, the authority having jurisdiction (AHJ) serves as the judge. The construction crew is the jury. And the engineer who reviews all the technical data and asks all the necessary questions will make the most convincing case for permitting approval.

A structured and repeatable process is important. So is the quality of communication between the contractor and the engineering and design team. And never underestimate the value of experience. Nobody can see into the future, but experience guides us to the right questions to ask and the permitting pitfalls to avoid.

Knowing that, we’ve asked three of SepiSolar’s most experienced engineers to share some tips on how they guard against project delays and surprise budget jumps. Change orders late in the planning process can lead to unhappy project owners and can compromise bids on future projects.

Here are three steps to avoiding change orders from SepiSolar development engineer Taylor Bohlen, design engineer Ryan Mateo, and operations project manager Dylan Brown.

Next-level detail in the site survey

It’s all about the level of detail in the site survey, Bohlen says. The site survey lays the groundwork for potential issues to be caught up front so that they can be accurately estimated and dealt with before the project moves forward to a point where engineering revisions will be needed.

It can also help to verify layout and equipment spacings in the field instead of accepting what you see in off-the-shelf solar design software assumptions. Assumptions baked into the proposal generating process might not align precisely with the reality at the project site. These discrepancies can result in change orders.

Here’s a checklist SepiSolar uses to generate the most comprehensive dataset for commercial and industrial projects and utility-scale projects.

The engineer will evaluate site survey details procedurally at the beginning of a project in context of the final system and its objectives. Structural information will go to a structural engineer for analysis up front. Feasibility of the physical layout will drive decisions related to electrical layout.

Each step of the design process determines feasibility in the steps that follow.

Ripple effects from design changes

There’s a misconception out there about the impact of seemingly small changes in project design, Mateo says. Consider what happens with one of the more common changes, swapping one type of solar module for another.

Contractors often recommend one type of module during the sales process but then find its unavailable. You might find another module that costs about the same and has the same power class but slightly higher short-circuit current rating.

Does that seem like a miniscule change? It can sometimes make or break your ability to run parallel strings in an inverter maximum power point tracker (MPPT).

If you can’t run parallel strings and you don’t have enough inputs in the selected inverter, the module swap can lead to an inverter swap. That’s more than a ripple. It’s a tidal wave.

Every input in project design affects something else. Contractors should work with designers to finalize aspects of the project starting with least dependent portions and moving up to the most dependent.

Finalize layout before moving to wire diagrams. If you remove modules because the roof could not handle the weight, the electrical calculations have changed.

SepiSolar’s milestone process, commonly used in the construction industry, reduces the amount of change orders we see.

Know agreements like the back of your hand

All parties need to understand what’s involved with a project, from timelines to equipment to subcontractor roles. These details should be well defined before project execution, says Brown.

When site owners ask questions about items that are outlined in the project brief, that’s a change order red flag.

If multiple contractors are involved in a project, is it clear who’s responsible for each aspect of the project? Every structural, electrical, or civil detail should be accounted for.

Resist pressure to advance to the next project milestone without obtaining stakeholder approval. Contractors may get pressure from site owners, financiers, even your own boss. If you need a cautionary tale, see what happened when SepiSolar was brought in to re-engineer a project that was initially built for power to flow in one direction and then had to accommodate bidirectional distribution.

The need for re-engineering was an avoidable mistake caused by confusion about who would file an interconnection agreement.

Avoiding change orders is risk management

If you have completed all three steps to avoiding change orders—producing a detailed site survey, recognizing the ripple effects from design changes, and mastering the finer points of your agreements—you’re well on your way to a successful outcome.

For more ideas, download our C&I Risk Management Guide. We put together the guide as a resource to help contractors get consistent, repeatable project planning without surprise bottlenecks, permitting delays, and escalating costs.

There are no practice rounds in project management. You need to know that designs are always accurate and error free. Find out how in the risk management guide.


August 6, 2021

In a recent analysis of energy storage test results, SepiSolar engineers Taylor Bohlen and Richard Dobbins noted the shortcomings of system availability as a measure of long-term performance.

System availability quantifies the percentage of time that a storage unit has been operating. If a system stays online, charging and discharging power for 750 hours during a period of 1,000 hours, system availability is 75 percent.

Do you want to know how well the system is performing while it’s online? Or the impacts that product failure events have on performance? These questions are critical for energy users, system operators, and grid managers. But system availability doesn’t answer them, and we don’t want to sift through archives of data to find the answer.

So the SepiSolar engineering team got together and created a metric that does. We adjusted the definition of availability, so it’s weighted by the operational capacity of the system, giving us the battery’s weighted availability.

Weighted availability is the missing piece of the puzzle. It’s one number that takes into account several different aspects of availability and reliability, including mean time between failure (MTBF) and mean time to repair (MTTR). You could also call it average discharge capacity or average functional capacity.

Weighted availability provides a quick snapshot of how an energy storage system is going to perform long term. And it allows comparisons across energy storage products of all types, such as lithium, flow, and flywheels.

This post will show you how to calculate weighted availability for any time interval. We hope this improves your independent engineering evaluations for purchasing, warranties, system design and more.

The weighted availability difference

Availability by itself means practically nothing. A system can be on nearly all the time, but if it’s performing suboptimally when it is on, availability can mask real issues with the system. By the same token, for a system that’s on for a little less time but performs always at peak capacity, availability can understate how well the system performs.

One battery system in our analysis really drove home the importance of digging deeper into availability and reliability. With system availability at almost 87 percent, this battery appeared to be one of the best-performing units in the lab. But the performance history told a different story.

Since March 2020, the battery manufacturer has suspended maintenance due to COVID-19, with components that appeared to be nearing the end of their service life. The manufacturer limited cycling depth to prevent battery damage and maintained a limited cycling profile through October 2020.

Inverter failures in 2018 and 2019 also contributed to reductions in energy dispatch until the manufacturer completed inverter replacements and upgrades in May 2019.

For all the time that this battery curtailed cycling and limited energy output, the system was operational. There was no impact on system availability, but weighted availability was reduced at times by one-third or two-thirds due to inverter failure. The error and the impact of the error are captured in weighted availability.

To drill deeper and understand why weighted availability was getting pushed down, see MTTR, the average time needed to restore the unit to full operational capacity after a failure event. In this case, MTTR was nearly 86 days.

When independent engineers evaluate batteries, we look at how operational characteristics affect risk-adjusted value. One system might increase performance but also increase the need for maintenance. Another system providing less energy might reduce downtime and maintenance costs.

We created the weighted availability metric to show a more complete picture of the use and lifecycle of each battery unit.

Calculating weighted availability

Here’s the formula for availability where Operational Time means a unit of time where battery operational capacity is greater than 0, and T equals total installation lifetime, or time since the beginning of an initial battery cycle.

Now, here’s the formula for weighted availability.

Instead of measuring when the system is operational, weighted availability calculates available power at each measure of time and divides it by the system’s nominal power.

For the best analysis, look at weighted availability along with all the other metrics. If you’re designing residential storage systems to keep the lights on and small electronics charged during intermittent breaks in utility service, availability might still be the most useful metric. If you’re developing microgrids with complex storage needs, weighted availability can help you decide whether to accept suboptimal performance or dispatch a maintenance crew.

Better yet, look at multiple metrics in tandem. If you have a battery with 99 percent availability and 90 percent average discharge capacity, you can know that the system will be available nearly all the time and, of the time the system is operational, you can expect it’ll be performing at 90 percent of its rating over the long term. That’s more than you’d know if you had only one metric to work with.

Solar sabermetrics

The movie Moneyball, released in 2011, tells the true story of how a small-market baseball team used sabermetrics—essentially, baseball statistics—to compete with the big boys.

Old-school talent evaluators used subjective criteria to identify which players were destined for stardom. Attitude. Perceived confidence. The shape of the jaw. They also used simple performance metrics like batting average, the ratio of hits to total times at bat.

Through quantitative analysis, some teams realized that swagger and batting average have little meaning. As a better predictor of success, they looked at two metrics, on-base percentage and slugging percent, and added them together.

On-base percentage is the ratio of hits and walks to total times at bat. Slugging percentage is a weighted measure of hits to at-bats with extra weight ascribed to doubles (two-base hits), triples (three-base hits), and home runs (four-base hits).

If the weighted average of battery systems becomes a standard metric, it will help improve our understanding of energy storage like sabermetrics improved our understanding of baseball.

Feature photo by Victor Freitas on Unsplash


July 8, 2021

State of market

California has an enormous need to bring new energy storage capacity on the grid, especially for commercial and industrial (C&I) energy users. As you’ll see below, the project pipeline reflects the need. However, procurements and interconnections are not keeping up with demand.


37,040 MW solar+storage projects in the Cal ISO interconnection queue, as of June 2021

15,115 MW stand-alone energy storage projects in the Cal ISO queue


4,189 MW energy storage procured, according to California Energy Storage Alliance

250 MW behind-the-meter energy storage procured


Key barriers to growth

What’s standing in the way of market growth for C&I energy storage in California? A little bit of everything. Although California is a market leader, it takes longer to complete project permitting than in other states, like Florida and Nevada. Interconnection costs are higher, too. One way to make utility rates more energy storage-friendly would be to shift from monthly demand charges to daily demand charges, as described below.


Median inspection times for on-site commercial-scale energy projects in California are slow, according to solar data collected by the National Renewable Energy Laboratory. The wait time tends to be 19.5 days. This contributes to a wait time of nearly 3 months overall for permitting, interconnection, and inspection. California can speed up inspection times.


Many utilities in California and around the country require no fee to apply for interconnection for on-site energy projects. The investor-owned utilities in California are different. PG&E customers pay an interconnection fee of $145. San Diego Gas & Electric customers pay a $132 fee. Southern California Edison customers pay a $75 fee. California can eliminate interconnection fees.

Utility rate design

In November 2019, PG&E introduced commercial rate tariffs with daily demand charges, becoming the first utility in California to do so, according to the California Solar + Storage Association. Instead of collecting demand charges based on the highest single interval of demand in the monthly billing cycle, PG&E’s new approach assesses charges according to the highest level of demand within set periods each day. For system operators, this offsets the risk of unpredictable demand charges and the need for risk mitigation.

When PG&E introduced daily demand charges, California regulators limited participation to 50 MW of storage for each rate tariff offering daily demand charges, or 150 MW overall. Regulators should make daily demand charges the norm in California and make sure they are accessible to commercial customers throughout the state.


In 2019, California regulators gave operators of solar-plus-storage projects an opportunity for the first time to export battery power onto the grid and receive net energy metering (NEM) credits for the output. NEM for storage has huge implications for the market, as we explained in a recent blog post.

  • NEM for storage eliminates the need for expensive meters, relays, and switchgear.
  • It simplifies design for solar-plus-storage systems.
  • And it builds consensus around the value of distributed energy resources at a time when legislators and utilities are pushing hard to undercut NEM for solar.

Featured project

For a Riverside County office building, SepiSolar Chief Electrical Engineer Richard Dobbins designed a 694.9 kW array of solar canopies to cover the parking lot and an 87 kW, 193.5 kWh battery energy storage system for an enclosure at the edge of the property. See our solar and storage design examples page to download the project’s site plan, three-line diagram, parts list and more.

Have a C&I solar project of your own?

If you have a C&I solar project and need some design and engineering expertise, don’t hesitate to contact us for help. Simply click below, provide some details about your project and we will follow up promptly to discuss it with you.


April 22, 2021

Solar advocates and investor-owned utilities are feuding again.

The arguments might sound a little wonky but take our word for it. There’s no love lost here. This is a rematch from California’s last skirmish over net energy metering (NEM) five years ago. And the many disputes that follow similar battlelines from solar state to state.

The utilities contend that NEM imposes an unfair cost shift from solar customers onto everyone else. People who champion solar say the benefits continue to outweigh the costs, and regulations should facilitate the energy transition rather than slowing it down. (For all you who are not policy geeks out there, those are fighting words.)

The problem confronting the grid isn’t new. The transmission and distribution networks, designed a hundred years ago to send power in one direction from centralized generators to end customers, has struggled to accommodate the need for bidirectional energy flow with producers popping up all over the place.

The solutions aren’t new, either. Two years ago, California adopted a proposal developed by SepiSolar that allows DC-coupled solar-plus-storage systems to qualify for NEM for the first time, in cases where storage exports only solar energy back to the grid.

Instead of driving up costs with utility charges and artificially lowering the value of solar, California can eliminate an entire system cost category, accelerate the transition to distributed energy resources, and resolve the conflict over NEM once and for all.

It’s time to set aside our differences and embrace energy storage.

Let’s do this.

Eliminating interconnection costs

California’s adoption of NEM for storage represents one of those rare occasions where engineering and policy reform work hand in hand to reduce hard costs and soft costs all at once.

Beforehand, AC-coupled solar-plus-storage systems needed separate inverters for generation and storage. They would routinely run up against grid constraints due to the relatively high AC nameplate rating. And higher system costs due to meters, relays, and switchgear equipment. And lower efficiencies due to power conversion in both directions—DC to AC and back again.

DC-coupled systems also faced the prospect of adding meters, relays, and other electrical equipment at the behest of the utility. And adopting system size limits based on the local distribution infrastructure. These requirements had been put in place to prevent system owners from gaming the system, like mini Enrons, charging batteries when electricity prices are low and selling when prices are high.

The utilities needed a way to tell a unit of solar energy apart from any other unit of energy on the grid. So did the IRS, which awards federal tax credits for storage based on how much energy comes from renewable sources.

Through a partnership with Nextracker and support from the California Solar and Storage Association (CalSSA), SepiSolar showed that a firmware modification to the DC-coupled inverter and battery system could be as effective as all the expensive hardware the utilities had previously required us to install. The inverter firmware disables the battery’s ability to charge from the grid.

See our NEM for storage white paper here.

It’s win-win scenario for system owners and utilities.


Accelerating the energy transition

The solution is elegant. Today, DC-coupled solar-plus-storage systems are no longer arbitrarily capped by the utility. Systems can use just one inverter and a single DC-AC inversion path. No extra meters, relays, or switchgear. The inverter’s AC rating determines system size, as it always has with solar projects that qualify for NEM.

And the entire project qualifies for the full investment tax credit. There’s no need for complex metering, additional relays, and the whole nine yards.

It’s true what they say, that the pace of evolution is speeding up. Here’s human evolution over 7 million years.

And here’s how the single-line diagram has improved for solar-plus-storage projects, going from the height of complexity (AC-coupled systems) to a little less complexity (DC-coupled systems before NEM for storage) to pure simplicity (DC-coupled systems after NEM for storage).

Turning the corner on NEM

The tone of this post has been a little tongue in cheek at times, but we recognize that the stakes are high for the solar industry and by extension the burgeoning energy storage market.

Last month, CalSSA warned members that a consulting firm had pegged utility costs associated with NEM so high that San Diego Gas & Electric would have to charge residential customers on NEM tariffs $177 per month just to break even.

While it’s unlikely the California Public Utilities Commission would approve such an astronomically high fixed charge, state regulators are considering fixed charges in the range of $50 to $70. Plus monthly charges of $5 to $7 per kilowatt (kW) installed. Plus $10 to $20 per kW each month in demand charges. All while cutting daytime net metering credits down as low as 10 cents per kilowatt-hour (kWh).

The California solar market will likely suffer if this is the outcome for NEM. A decision is expected to take effect in 2022.

NEM is also under a new threat in the California Legislature. Yesterday, the Assembly Utilities and Energy Committee approved a bill, AB 1139, that would make going solar more expensive for everyone. See CalSSA’s description of the bill for more info.

Meanwhile, regulators and industry advocates must not lose sight of the impact that NEM will have on energy storage. When solar is concerned without storage, it seems like there’s no room for compromise. Storage, on the other hand, has advantages for everyone.

For now, NEM for storage is optional. Systems can add batteries or leave them aside. In the future, regulators could make storage a requirement for NEM.

All that would be left to decide is at what penetration level would the storage requirement kick in.

At that point, solar advocates and utilities can take matters back into their own hands.

We can’t agree on everything, after all. Can we?

Seeking innovation solutions to extraordinary technical challenges? Contact us and we’ll show you what we can do.


June 10, 2019

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

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

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

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

Arizona storage system fire

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

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

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

Lithium battery risks

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


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

Thermal runaway

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

Hazardous materials

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

Warranty claims

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

Human rights

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

Downstream costs

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

Parasitic load

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

Advantages of flow batteries

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

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


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

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


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

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


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

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

Battery design

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

Trust and visionary thinking

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

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

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

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

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


February 20, 2019

When it comes to choosing the equipment used to interconnect the combined output of a PV system to the utility grid, it is important to ensure that the equipment is sized in order to withstand the full amount of power capable of being delivered by the PV system.

SepiSolar’s recently published a white paper that describes what our engineers consider before recommending PV system output equipment.

Download this resource and learn how SepiSolar engineers conduct a comprehensive evaluation.


February 1, 2019

When I saw this article about LG lithium-ion energy storage fires in Korea, I couldn’t help but think of the fires that PG&E is being held responsible for in California. Those fires have ultimately lead PG&E into bankruptcy and will inevitably increase energy costs to ratepayers.

It’s amazing how something as seemingly simple as a campfire, power line, or a 18650 lithium cell—about the size of a lipstick container–can cause so much damage to California, one of the wealthiest states in the world and PG&E, the largest utility in the state, and, of course to the loss of lives and homes.

Some of these hazards defy logic or at least expectations. When SepiSolar was providing technical due diligence and engineering review services to NRG Home Solar from 2014 – 2016, we came across residential projects on the East coast that had unexpected dangers. For example, there was a solar PV system installed on top of the garage where snow had piled up on the PV system. Some rain had turned that snow into a giant slab of hardened ice. When the ice slipped off the solar array, it crushed the car parked in the driveway–not dented, dinged, or scratched. It completely totaled the car. The homeowner told us “that’s exactly where my children play in the summertime.”

Having just become a father at the end of December 2018, I think it’s fair to say that safety cannot, should not, and will not ever be taken for granted on my watch.

Risks vs Benefits

I don’t mean to suggest that we ought to over-design, over-engineer, over-regulate, over-install, or somehow bullet-proof every single component or assembly in a traditional solar or storage system.  That’s like saying “Since car accidents kill people, let’s require everyone to drive army-grade tanks down the street.” That line of thinking effectively kills an industry and becomes a zero-sum game. Instead, I would pose that taking risks is a part of life and is healthy for us, since taking risks and stepping outside our comfort zones is exactly how we grow, learn, and evolve.

The goal is to take calculated risks, or, alternatively, educated risks. What’s a calculated risk? It’s a risk that you’re aware you’re taking. The difference between educated risks and blind or reckless risks is awareness.

We then need to weigh those risks against the benefits in order to make effective decisions. After those decisions are made, we need to be ready to revisit them again soon because the learning process never stops. Assumptions will need to be revised, data recalculated, risks revisited, benefits re-weighed, and decisions re-evaluated. This is how we evolve and approach an ever-safer future, together.

So, let’s build some awareness, shall we? Let’s have a data-driven discussion about the fire risks associated with energy storage systems, and let’s turn our blind risks into calculated ones. Having helped build Green Charge Networks into a nationwide energy storage integrator (acquired by Engie in 2015), engineered solar and battery systems for over 10+ years, and having worked with utilities, UL, code officials, etc. on safety standards, I think I might have a thing or two to say about this subject.

Evaluate the Energy Storage Technology

To minimize risks in energy storage, perhaps the most obvious approach is to work with a technology that inherently works with chemicals and materials that have no fire risk associated with them. This is particularly difficult with batteries because when almost any battery is short-circuited, they instantly become a fire hazard. But that’s the nature of batteries – they can produce insanely high amounts of current, since the resistance in the battery circuit is governed by however fast (or slow) the chemicals involved can react with each other, allowing the free flow of electrons to accumulate. Of course, these chemicals are designed to react with each other in order to release electric charge. So, fire hazard is almost inherent in any battery (with at least 1 exception).

I love this side-by-side technology comparison authored by Fire Captain Matthew Paiss, a 22-year veteran of the San Jose Fire Department. Captain Paiss is the Fire Department’s subject matter expert on energy storage and is the IAFF primary representative to NFPA 70 (National Electrical Code) and NFPA 855 (Energy Storage System Standards), which has been incorporated into UL standards such as UL 9540. It was surprising and gratifying to know that there’s at least 1 technology that rises above the rest when it comes to safety.

Codes & Standards

There are a ton of uber-smart tradesmen, engineers, officials, and subject matter experts who love to wordsmith and craft codes and technical language (God love them!) in order to impose a minimal, universal set of health and safety standards designed to protect personal property and life. Some of these codes go all the way back to 1897, as is the case with the National Electrical Code, when electricity was thought of as a liquid! (Check out Leyden jars.)

Bottom line, let’s be sure to read and understand the modern codes thoroughly, including NFPA, NEC, UL, among others. Every word, comma, and comment were crafted with the care one would expect of a nationally applicable set of requirements, even if you disagree with many of them. It’s important to follow voltage, current, and sizing requirements, naturally. NEC 706, for instance, was just added to the NEC in the 2017 edition. That’s the first time batteries have been overhauled in the NEC since Article 480 was written back in the early 20th century! Let’s expect this new code section to evolve with the times as more data becomes available and continue to think of these codes as a “minimal” set of safety standards that we can go above-and-beyond as necessary to ensure the safety of the systems we design and build.

Real-time Data

While codes and standards are important, one of their drawbacks is that they are slow to change. Technology and data often evolve faster than codes and policies. Because of this, it’s important to look at the data, stay up-to-date on the latest-and-greatest information available, and dynamically build this data into your systems as it becomes available. Basically, I’m advising you to read. Read articles, publications, journals, media newsletters, and absorb as much as possible to keep up-to-date.

For instance, now that the above Korean article has surfaced about LG battery fires, it’s imperative to find out the root cause failures that led to these hazards. There is much to learn from failure, thereby converting failure into learning opportunities (which perhaps negates the use of the term “failure” in the first place – nothing is a failure, so long as you learn something from it!). We don’t have to wait for new technologies or new codes to come out. Instead, let’s use the data right away in any or all systems that we may be using with LG batteries, or any battery, for that matter.

The first time I thought about the risks associated with batteries was when I heard that Boeing grounded the Dreamliner. Our Co-Founder and CEO of Green Charge Networks at the time was a retired Boeing executive, so this naturally caught our attention. Wikipedia does a decent job summing up that experience, and you can get the full investigative report here.

The general takeaway is that regulatory bodies, manufacturers, and engineers were not “up to snuff” on the risks associated with battery technology. To a great degree, as the above Korean article shows, we are still learning these risks. At our time at Green Charge Networks, we understood that this meant that the safe deployment of battery systems would largely rest on us, since codes, standards, products, and regulations were still too much in their infancy to support us.

Direct Experience and Training

Nothing prepares you for danger, uncertainty, or risk more than education, experience, and training. The more hands-on experience you have with a particular product or technology, the more you will understand its limitations, weaknesses, and risks. Understanding not only what and when a battery undergoes thermal runaway, but also the “how” can really help put battery risks into perspective. What I learn from this is that it’s not just the battery one should be cautious of, but also the environment the battery is in. For example, does the battery have a fire suppression system? Is the battery located near any buildings or structures that have no fire suppression?.

One time I dropped a wrench on an old golf cart battery, and it just so happened that the wrench landed perfectly on both positive and negative terminals simultaneously. It was the first time I saw metal turn bright red, orange, and then white, and eventually melting all over the battery. This was just a regular ol’ lead acid battery, so it was surprising to me that such an old battery could have such a great impact on something as solid and stiff as a wrench. Needless to say, I am very cautious around terminals of batteries, since most batteries cannot be inherently turned “off” (again, with some exceptions).

In a nutshell, if you’re working with lithium batteries, make sure to identify the risks and retire them as much as possible. For instance:

  • HVAC systems for lithium are not just there to support battery performance, but they are safety devices as well. Make sure they’re appropriately sized and adequate for the operating environment the batteries will be in.
  • Lithium batteries that get too hot can result in thermal runaway, and other types of hazards, aside from accelerated degradation of the cell capacities and efficiencies. Fire suppression systems are required with the appropriate cleaning agents.
  • Closely monitoring and isolating cells that are approaching their end-of-life is critical. Battery degradation not only leads to capacity loss, but also battery failure.

There are many other aspects to keep in mind, and nearly all are avoidable if you’re aware of them in the first place.

I strongly believe that lithium-ion battery systems will continue to grow and thrive in our new renewable energy world, but as the Korean article shows, there are risks. As engineers, it’s our responsibility to be aware of these risks, evaluate them, and to find the solutions that will decrease those risk and perhaps even eliminate them with new safety innovations.


January 24, 2019

UPDATED: The CPUC has unanimously passed this California NEM Storage decision on January 31, 2019. The information in our white paper reflects the final decision.  

In December, SepiSolar published a white paper that reviews a proposed CPUC decision to include net energy metering (NEM) with DC-coupled energy storage for commercial solar systems. As of the writing of this blog post, the CPUC is set to vote to finalize the decision on January 31, 2019, and is expected to pass. However, it’s possible the vote will be postponed due to other priorities, such as PG&E’s bankruptcy filing. (Check the latest CPUC agenda here.)

While our white paper describes many of the financial benefits to the decision, several energy storage and inverter manufacturers had questions about the firmware solution that we designed for NEXTracker’s NX Flow system, a DC-coupled energy storage system.

Below is a list of some of these questions and the answers. As always, if you have more questions, please submit them in the comments section or send them to

Is DC-coupled storage with net metering approved in California only with NEXTracker’s NX Flow product?

As soon as the CPUC approves the policy change (hopefully by the end of January 2019), the NX Flow would be immediately eligible, since its firmware has already been verified by UL. However, other DC-coupled storage manufacturers may design similar firmware for their products. Eventually, UL will update their 1741 standard to include these protocols. In the meantime, utilities are allowing discretionary approvals of this policy, even though the CPUC hasn’t fully adopted it yet.

The white paper says that SepiSolar co-developed the firmware. Does that mean that energy storage or inverter OEMs need to license the code from SepiSolar or NEXTracker?

No. SepiSolar wrote the specifications, designed the testing protocol, and demonstrated the underwriting and verification process with our client, NEXTracker.

As with NEXTracker, OEMs will need to develop their own code and implement into their California NEM/Rule 21 compliant product after UL verification. Based on our experience, a manufacturer can typically develop the code within a day or so.

While SepiSolar does not write the firmware code, as an independent engineering firm, we’re able to help inverter and energy storage manufacturers with the functional and technical requirements to comply with this updated NEM energy storage policy for DC-coupled systems. Having gone through the UL process ourselves, we can advise on firmware design, testing pain points, pitfalls, and how to get through the UL approval process as expeditiously as possible.

Eventually, UL will update its 1741 standard to include the protocols that SepiSolar developed.

What do you mean by “firmware”? Don’t you mean “software”?

In order to adjust to this NEM storage proposal, utilities asked that the associated OEM software not be changed after interconnection, and that it be “hard-coded” into the hardware device’s “firmware” itself. They wanted to be certain that nobody could come back to the system later, after PTO (Permission to Operate) was issued, and re-program the battery to charge off the grid, thereby breaching the system’s interconnection agreement with the utility company.

While “firmware” involves software coding, it’s typically installed once at the manufacturer’s facility and implies that the software can’t be modified after installation or interconnection. On the other hand, “software” is inherently adjustable and can often be updated remotely by the system owner, OEM, or even third parties.

As a result, the “NEM software” (firmware) cited in the proposed CPUC decision must be hard-coded into the DC-coupled inverter device. It must then be recorded, tested, and verified by a Nationally Recognized Testing Laboratory (NRTL), such as UL or TUV. The inverter product must also have a specific version number and checksum that cannot be confused with other non-NEM-compliant hardware.

In the future, it’s possible that we’ll find ways to allow “un-editable” software to be located outside of the DC-coupled inverter device, perhaps in an EMS (Energy Management System) controller. However, the EMS would need to prove to the utilities that it, indeed, cannot be updated post-PTO. These alternatives are currently being discussed.

What happens if you update the firmware after interconnection?

As mentioned, the firmware protocol that SepiSolar developed ensures that the software is hard-coded by the OEM and verified that it was installed correctly by an NRTL. In our UL-verified protocol, if the firmware is changed after installation or interconnection, it will necessarily void the UL verification and put the entire installation in breach of its interconnection agreement (and Rule 21) with the utility. The utility will then be able to shut down the system and potentially fine the customer for any damages the utility may have sustained for the breach.

What are the firmware requirements?

The firmware requirements that any DC-coupled system would need to satisfy to receive NEM credits are fairly straight forward. It must be designed so that the battery can never charge from the grid. In addition, the firmware solution must be tested and verified by an NRTL, such as UL.

If you’d like to learn more about the specific tests themselves (there are 5 total), feel free to reach out to us at, and we can share, specifically, what these tests entail. In summary, the tests involve:

1) The inverter’s ability to sense a potential “battery-charge-from-the-grid” event (which would violate this NEM policy) and mitigate it by controlling a DC bus voltage in order to turn the battery “off,”
2) The battery’s ability to be turned “on” or “off” by the inverter vis-à-vis this DC bus voltage control method described in (1) above,
3) The verification of software version number,
4) That no other software-controlled device (like an EMS) can override the inverter’s firmware, and
5) Sensitivity testing on all the above in the event that the PV supply varies widely (say, with variable cloud cover events).

Instead of inverters, can DC-DC converters adopt the firmware?

Yes. We see a clear use-case for getting a DC-DC converter approved under California NEM, but it would require a slightly different testing regime than the one we’ve developed for NEXTracker’s NX Flow product.

Is NEM with DC-coupled storage only available in California?

Yes, for now, due to this pending CPUC policy change, DC-coupled NEM with energy storage will only be available in California. However, other states typically follow California’s lead with policies like this. As of mid-January, 2019, we haven’t seen a system get approved outside of California.


We hope these responses answer your questions about the UL-verified firmware that is required for DC-coupled energy storage. If you have further questions, please add a comment or contact us at


December 8, 2018 0

As we approach this holiday season, I’d like to take a moment to look back at 2018 and share some of what’s in store at SepiSolar for 2019.

First, on behalf of our entire team, we want to thank you for selecting SepiSolar as your 2018 solar design and engineering partner. This year has seen many changes in the solar industry–as well as at SepiSolar.

In addition to our usual design work, we redesigned our logo and then redesigned a new HQ, expanding to larger offices in Fremont. The move was largely due to adding new team members to our engineering and operations teams, enabling us to design more efficiently and deliver plans on time.

Along with new team members, SepiSolar instituted new quality control measures and new design tools that are helping SepiSolar engineers design solar-plus-storage systems with increased speed and accuracy. In fact, we’re proud to report that nearly 90% of our customers’ residential designs receive permits without any revisions. For commercial, industrial, agricultural, and multi-family projects, 80% of projects receive a permit without revisions, even in America’s most demanding jurisdictions.

2018 also saw the launch of several new services, including Salesforce consulting for solar companies and Sepi Academy, our new NABCEP solar and energy storage training program.

What’s in Store for 2019

For 2019, SepiSolar will be keeping up with all the new permitting changes here in California and across the U.S. With a 100% renewable energy goals set for Hawaii and California, plus California’s new Title 24 solar roof mandate, we’ll be informing our clients on all the latest requirements and best design practices.

You’ll also see a new SepiSolar website that will be easier to use and filled with more resources, such as our site survey checklists and more new downloads and White Papers. Of course, we’ll also be generating new useful blog content and continuing our Ask SepiSolar Anything webinar series.

Thank you for being a part of SepiSolar in 2018. We’re excited for 2019 and look forward to working together on bringing more GW of solar and energy storage to the U.S. and the world.

From all of us at SepiSolar, we wish you and your family a wonderful holiday and a prosperous and happy new year!


Josh Weiner, CEO of SepiSolar

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