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.
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.
Fire safety has always been a hot topic in commercial and industrial solar, now as much as ever.
First responders need to know that crews won’t be put in harm’s way in the event of an emergency. Section 690.12 of the National Electrical Code has led many C&I projects to adopt extra equipment that can reduce system voltage at the flip of a switch.
Contractors have to adhere to safety standards. But they also have to look for opportunities to simplify construction and keep costs under control. Compliance can increase system costs, requiring additional hardware, longer installation times, and time-consuming operations and maintenance.
Manufacturers are starting to bring forward solutions that aim to address safety, simplicity, and cost. Inverter maker SMA America and mounting system supplier Sollega have obtained certification showing that the Sollega FastRack 510 and the SMA Sunny Tripower CORE1 meet the Underwriters Laboratory (UL) 3741 definition of a Photovoltaic (PV) Hazard Control System, as first reported by Solar Builder.
The finding is significant. It means projects can meet rapid shutdown requirements without needing module-level power electronics or mid-circuit interrupters. With permitting approval, contractors can look forward to a whole new category of system design options for rapid shutdown compliance. Sepi provides system design among our project planning services.
But one big question remains: What will the authorities having jurisdiction do?
AHJs are key stakeholders
Developers and asset owners invest a lot of time and money in C&I projects. Investors want to mitigate risk. You increase the risk of project delays any time you stand first in line for approval with a new solution.
The US has more than 20,000 cities and counties. Naturally, we couldn’t ask each one for an opinion on PV Hazard Control Systems. But as a service to the industry, we selected 15 AHJs in communities that install high volumes of solar projects. We included municipalities from the East Coast, the Midwest, the Rocky Mountains, the Pacific Coast, and Hawaii.
We contacted agencies where our communications team had direct contact information for at least one senior official in the department. Many did not respond during the one-week response period we provided.
The variety of responses and the response rate, at 20 percent, underscores some of the industry’s perennial challenges with project permitting. Not only the inconsistency from one jurisdiction to another but sometimes a lack of transparency.
Here are the responses we received.
UL 3741 approval in Sacramento, California
Michael Bernino, Sacramento’s supervising building inspector, consulted with an electrical plan reviewer and concluded that PV Hazard Control Systems would be treated as a design choice which is allowed by code.
“Given the fact that the proposed product is UL listed, it would be approved as code compliant,” Bernino said.
Alternative review process in Tampa, Florida
Florida has not yet adopted the 2020 NEC, which includes the UL 3741 standard for PV Hazard Control Systems. The Florida Building Code incorporates the previous 2017 code.
Until Florida adopts the 2020 NEC, JC Hudgison, Tampa’s construction services center manager and chief building official, suggests an alternative. Try an Alternative Means & Method Request (AMMR) to get projects with PV Hazard Control Systems approved.
The AMMR process gives building officials discretion to approve system designs that satisfy and comply with the intent of existing code. Designs must also provide at least an equivalent measure of fire resistance and safety.
Alternative review in Napa County, California, too
The City of Napa’s Building Division issues permits for commercial solar systems. But a senior building inspector, when asked about UL 3741, directed us to inquire with the county Fire Marshall.
Fire Plans Examiner Adam Mone explained that the Fire Marshall’s review would be limited to a comparison of system designs as presented against the 2019 edition of the California Fire Code. Mone encouraged us to talk with Napa County’s Building Division about compliance with the 2019 edition of the California Electrical Code.
We will update this post if we get Napa County’s perspective on UL 3741 PV Hazard Control Systems. UPDATE: According to Interim Chief Building Official Harvey Higgs, Napa will also accept UL 3741 PV Hazard Control Systems as an alternate means until January 1, 2023, when the 2022 edition of the California Electrical Code takes effect and the devices are explicitly allowed by code.
We will post additional responses from other jurisdictions too.
Ask an AHJ
Want our communications team to ask an AHJ in your community about approval for PV Hazard Control Systems? Send a message through our contact page or email us at [email protected].
Also keep an eye on our LinkedIn page. We post daily content for renewable energy professionals, including our new monthly feature: Ask an AHJ.
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.
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.
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?
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.
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.
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.
In a recent analysis of energy storage test results, SepiSolar engineers Taylor Bohlen and Richard Dobbins noted the shortcomings of system availability as a measure of long-term performance.
System availability quantifies the percentage of time that a storage unit has been operating. If a system stays online, charging and discharging power for 750 hours during a period of 1,000 hours, system availability is 75 percent.
Do you want to know how well the system is performing while it’s online? Or the impacts that product failure events have on performance? These questions are critical for energy users, system operators, and grid managers. But system availability doesn’t answer them, and we don’t want to sift through archives of data to find the answer.
So the SepiSolar engineering team got together and created a metric that does. We adjusted the definition of availability, so it’s weighted by the operational capacity of the system, giving us the battery’s weighted availability.
Weighted availability is the missing piece of the puzzle. It’s one number that takes into account several different aspects of availability and reliability, including mean time between failure (MTBF) and mean time to repair (MTTR). You could also call it average discharge capacity or average functional capacity.
Weighted availability provides a quick snapshot of how an energy storage system is going to perform long term. And it allows comparisons across energy storage products of all types, such as lithium, flow, and flywheels.
This post will show you how to calculate weighted availability for any time interval. We hope this improves your independent engineering evaluations for purchasing, warranties, system design and more.
The weighted availability difference
Availability by itself means practically nothing. A system can be on nearly all the time, but if it’s performing suboptimally when it is on, availability can mask real issues with the system. By the same token, for a system that’s on for a little less time but performs always at peak capacity, availability can understate how well the system performs.
One battery system in our analysis really drove home the importance of digging deeper into availability and reliability. With system availability at almost 87 percent, this battery appeared to be one of the best-performing units in the lab. But the performance history told a different story.
Since March 2020, the battery manufacturer has suspended maintenance due to COVID-19, with components that appeared to be nearing the end of their service life. The manufacturer limited cycling depth to prevent battery damage and maintained a limited cycling profile through October 2020.
Inverter failures in 2018 and 2019 also contributed to reductions in energy dispatch until the manufacturer completed inverter replacements and upgrades in May 2019.
For all the time that this battery curtailed cycling and limited energy output, the system was operational. There was no impact on system availability, but weighted availability was reduced at times by one-third or two-thirds due to inverter failure. The error and the impact of the error are captured in weighted availability.
To drill deeper and understand why weighted availability was getting pushed down, see MTTR, the average time needed to restore the unit to full operational capacity after a failure event. In this case, MTTR was nearly 86 days.
When independent engineers evaluate batteries, we look at how operational characteristics affect risk-adjusted value. One system might increase performance but also increase the need for maintenance. Another system providing less energy might reduce downtime and maintenance costs.
We created the weighted availability metric to show a more complete picture of the use and lifecycle of each battery unit.
Calculating weighted availability
Here’s the formula for availability where Operational Time means a unit of time where battery operational capacity is greater than 0, and T equals total installation lifetime, or time since the beginning of an initial battery cycle.
Now, here’s the formula for weighted availability.
Instead of measuring when the system is operational, weighted availability calculates available power at each measure of time and divides it by the system’s nominal power.
For the best analysis, look at weighted availability along with all the other metrics. If you’re designing residential storage systems to keep the lights on and small electronics charged during intermittent breaks in utility service, availability might still be the most useful metric. If you’re developing microgrids with complex storage needs, weighted availability can help you decide whether to accept suboptimal performance or dispatch a maintenance crew.
Better yet, look at multiple metrics in tandem. If you have a battery with 99 percent availability and 90 percent average discharge capacity, you can know that the system will be available nearly all the time and, of the time the system is operational, you can expect it’ll be performing at 90 percent of its rating over the long term. That’s more than you’d know if you had only one metric to work with.
The movie Moneyball, released in 2011, tells the true story of how a small-market baseball team used sabermetrics—essentially, baseball statistics—to compete with the big boys.
Old-school talent evaluators used subjective criteria to identify which players were destined for stardom. Attitude. Perceived confidence. The shape of the jaw. They also used simple performance metrics like batting average, the ratio of hits to total times at bat.
Through quantitative analysis, some teams realized that swagger and batting average have little meaning. As a better predictor of success, they looked at two metrics, on-base percentage and slugging percent, and added them together.
On-base percentage is the ratio of hits and walks to total times at bat. Slugging percentage is a weighted measure of hits to at-bats with extra weight ascribed to doubles (two-base hits), triples (three-base hits), and home runs (four-base hits).
If the weighted average of battery systems becomes a standard metric, it will help improve our understanding of energy storage like sabermetrics improved our understanding of baseball.
California has an enormous need to bring new energy storage capacity on the grid, especially for commercial and industrial (C&I) energy users. As you’ll see below, the project pipeline reflects the need. However, procurements and interconnections are not keeping up with demand.
What’s standing in the way of market growth for C&I energy storage in California? A little bit of everything. Although California is a market leader, it takes longer to complete project permitting than in other states, like Florida and Nevada. Interconnection costs are higher, too. One way to make utility rates more energy storage-friendly would be to shift from monthly demand charges to daily demand charges, as described below.
Median inspection times for on-site commercial-scale energy projects in California are slow, according to solar data collected by the National Renewable Energy Laboratory. The wait time tends to be 19.5 days. This contributes to a wait time of nearly 3 months overall for permitting, interconnection, and inspection. California can speed up inspection times.
Many utilities in California and around the country require no fee to apply for interconnection for on-site energy projects. The investor-owned utilities in California are different. PG&E customers pay an interconnection fee of $145. San Diego Gas & Electric customers pay a $132 fee. Southern California Edison customers pay a $75 fee. California can eliminate interconnection fees.
Utility rate design
In November 2019, PG&E introduced commercial rate tariffs with daily demand charges, becoming the first utility in California to do so, according to the California Solar + Storage Association. Instead of collecting demand charges based on the highest single interval of demand in the monthly billing cycle, PG&E’s new approach assesses charges according to the highest level of demand within set periods each day. For system operators, this offsets the risk of unpredictable demand charges and the need for risk mitigation.
When PG&E introduced daily demand charges, California regulators limited participation to 50 MW of storage for each rate tariff offering daily demand charges, or 150 MW overall. Regulators should make daily demand charges the norm in California and make sure they are accessible to commercial customers throughout the state.
In 2019, California regulators gave operators of solar-plus-storage projects an opportunity for the first time to export battery power onto the grid and receive net energy metering (NEM) credits for the output. NEM for storage has huge implications for the market, as we explained in a recent blog post.
NEM for storage eliminates the need for expensive meters, relays, and switchgear.
It simplifies design for solar-plus-storage systems.
And it builds consensus around the value of distributed energy resources at a time when legislators and utilities are pushing hard to undercut NEM for solar.
For a Riverside County office building, SepiSolar Chief Electrical Engineer Richard Dobbins designed a 694.9 kW array of solar canopies to cover the parking lot and an 87 kW, 193.5 kWh battery energy storage system for an enclosure at the edge of the property. See our solar and storage design examples page to download the project’s site plan, three-line diagram, parts list and more.
Have a C&I solar project of your own?
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Solar advocates and investor-owned utilities are feuding again.
The arguments might sound a little wonky but take our word for it. There’s no love lost here. This is a rematch from California’s last skirmish over net energy metering (NEM) five years ago. And the many disputes that follow similar battlelines from solar state to state.
The utilities contend that NEM imposes an unfair cost shift from solar customers onto everyone else. People who champion solar say the benefits continue to outweigh the costs, and regulations should facilitate the energy transition rather than slowing it down. (For all you who are not policy geeks out there, those are fighting words.)
The problem confronting the grid isn’t new. The transmission and distribution networks, designed a hundred years ago to send power in one direction from centralized generators to end customers, has struggled to accommodate the need for bidirectional energy flow with producers popping up all over the place.
The solutions aren’t new, either. Two years ago, California adopted a proposal developed by SepiSolar that allows DC-coupled solar-plus-storage systems to qualify for NEM for the first time, in cases where storage exports only solar energy back to the grid.
Instead of driving up costs with utility charges and artificially lowering the value of solar, California can eliminate an entire system cost category, accelerate the transition to distributed energy resources, and resolve the conflict over NEM once and for all.
It’s time to set aside our differences and embrace energy storage.
Let’s do this.
Eliminating interconnection costs
California’s adoption of NEM for storage represents one of those rare occasions where engineering and policy reform work hand in hand to reduce hard costs and soft costs all at once.
Beforehand, AC-coupled solar-plus-storage systems needed separate inverters for generation and storage. They would routinely run up against grid constraints due to the relatively high AC nameplate rating. And higher system costs due to meters, relays, and switchgear equipment. And lower efficiencies due to power conversion in both directions—DC to AC and back again.
DC-coupled systems also faced the prospect of adding meters, relays, and other electrical equipment at the behest of the utility. And adopting system size limits based on the local distribution infrastructure. These requirements had been put in place to prevent system owners from gaming the system, like mini Enrons, charging batteries when electricity prices are low and selling when prices are high.
The utilities needed a way to tell a unit of solar energy apart from any other unit of energy on the grid. So did the IRS, which awards federal tax credits for storage based on how much energy comes from renewable sources.
Through a partnership with Nextracker and support from the California Solar and Storage Association (CalSSA), SepiSolar showed that a firmware modification to the DC-coupled inverter and battery system could be as effective as all the expensive hardware the utilities had previously required us to install. The inverter firmware disables the battery’s ability to charge from the grid.
It’s win-win scenario for system owners and utilities.
Accelerating the energy transition
The solution is elegant. Today, DC-coupled solar-plus-storage systems are no longer arbitrarily capped by the utility. Systems can use just one inverter and a single DC-AC inversion path. No extra meters, relays, or switchgear. The inverter’s AC rating determines system size, as it always has with solar projects that qualify for NEM.
And the entire project qualifies for the full investment tax credit. There’s no need for complex metering, additional relays, and the whole nine yards.
It’s true what they say, that the pace of evolution is speeding up. Here’s human evolution over 7 million years.
And here’s how the single-line diagram has improved for solar-plus-storage projects, going from the height of complexity (AC-coupled systems) to a little less complexity (DC-coupled systems before NEM for storage) to pure simplicity (DC-coupled systems after NEM for storage).
Turning the corner on NEM
The tone of this post has been a little tongue in cheek at times, but we recognize that the stakes are high for the solar industry and by extension the burgeoning energy storage market.
Last month, CalSSA warned members that a consulting firm had pegged utility costs associated with NEM so high that San Diego Gas & Electric would have to charge residential customers on NEM tariffs $177 per month just to break even.
While it’s unlikely the California Public Utilities Commission would approve such an astronomically high fixed charge, state regulators are considering fixed charges in the range of $50 to $70. Plus monthly charges of $5 to $7 per kilowatt (kW) installed. Plus $10 to $20 per kW each month in demand charges. All while cutting daytime net metering credits down as low as 10 cents per kilowatt-hour (kWh).
The California solar market will likely suffer if this is the outcome for NEM. A decision is expected to take effect in 2022.
NEM is also under a new threat in the California Legislature. Yesterday, the Assembly Utilities and Energy Committee approved a bill, AB 1139, that would make going solar more expensive for everyone. See CalSSA’s description of the bill for more info.
Meanwhile, regulators and industry advocates must not lose sight of the impact that NEM will have on energy storage. When solar is concerned without storage, it seems like there’s no room for compromise. Storage, on the other hand, has advantages for everyone.
For now, NEM for storage is optional. Systems can add batteries or leave them aside. In the future, regulators could make storage a requirement for NEM.
All that would be left to decide is at what penetration level would the storage requirement kick in.
At that point, solar advocates and utilities can take matters back into their own hands.
We can’t agree on everything, after all. Can we?
Seeking innovation solutions to extraordinary technical challenges? Contact us and we’ll show you what we can do.
It’s one of the biggest misconceptions in project design and engineering: Permitting is all about technical compliance. Yes, you have to prove that the electrical system you intend to build satisfies all the codes that protect public safety. But there’s more to it than that. There’s an often-overlooked psychological component involved in the permitting process.
Imagine filing a permit application on a paper napkin. If it has all the necessary lines, squares and circles, equipment specifications, locations, and other requisite data, you’d have a complete application. But at least 9 times out of 10, your application would be rejected.
And for good reason. Because permitting is not only about code compliance. It’s about building trust and accountability. It’s about convincing the local permitting office that smart people have expertly designed your system for safety and reliability.
How do we win permit approvals? To begin with, we follow these five strategies:
Local permitters treat building and electrical codes the way that some people interpret the Bible, or the US Constitution. It’s not enough to size wire by multiplying output current by 125 percent. Instead, show your calculations and cite the latest version of National Electrical Code Article 690 approved in your jurisdiction, as well as any other applicable codes.
Spell out all the details so it’s clear that you not only know how to design systems but why the codes are in place to begin with. Plan checkers are going to ask questions. Get ahead of the game by showing them you know what you’re talking about.
Some system designers and engineers have a natural aversion to sharing too much with the permitting authority. As the thinking goes, it’s easier to ask forgiveness than to get permission.
That’s not always the best approach. The concern with sharing too much information is that the permitting authority will seize on small details to probe deeper, delaying approval and potentially altering project plans.
In our experience, permitters behave according to human nature. If you withhold information, they treat you with suspicion and distrust. If you’re upfront about complexity and nuance as well as your thoughtful solutions, and you show open-mindedness in response to questioning, you gain a measure of respect. This dynamic will carry over to future visits to the permit office. Good representation will improve your reputation with local permitters.
Call for backup
In many cases, SepiSolar customers have contacted us from the service counter during a conversation with a permit officer. It’s like having an on-call technical support hotline. We can answer permitting questions in real time. On more than one occasion, at the conclusion of these conversations, our customers have walked away with approved permits in hand.
Hedge against risk
Search engines have made everybody seem smarter by putting information at our fingertips, but at the same time our knowledge base has become a mile wide and an inch deep. The same thing is happening to an extent with the UL standards for energy storage systems. People can cite UL 9540, but not the component-level certifications for batteries, inverters and other key products.
If you don’t understand the various UL standards, you increase risk in the permitting process. When projects depend on system-level certification, any question that comes up about the test lab used for UL listing, or the test procedures, or anything else, can slow down permitting and add on project costs. On the other hand, applicants who know they have inverters that comply with UL 1741 and batteries that comply with UL 1973 have a fallback plan, so they can hedge against risks in the permitting process.
Channel your inner electrician
A lot of solar designers and solar engineers know about the 120 percent rule pertaining to energy generation, but they have no idea about NEC Article 220, which is all about loads and load calculations. Electricians and electrical engineers, on the other hand, know Article 220 like the back of their hand, but not the common solar codes.
System integrators today in all segments of the market need to design for systems that can dynamically change modes of operation, ramping up or down, quickly or slowly, staying still, or supplying any number of power applications, such as reactive power and VAR control.
System controls have a direct impact on system safety and code compliance. Integrators should understand all the modes of operation and be sure system designs comply with each mode affecting generation and load.
Ask us about complete design and engineering services
If you would like to reduce risk in the permitting process for your solar and energy storage projects, find out how SepiSolar approaches design and engineering for C+I solar projects and energy storage projects, and send us your project specifications today for a fast and accurate design quote.
Nobody remembers when you get the interconnection process right in solar or energy storage projects. The mistakes? Those stay with you longer.
A California developer who contracts project engineering and design work to SepiSolar once tasked a construction firm with handling interconnection. Due to miscommunication, nobody submitted the interconnection application to the utility.
The system was built. The utility refused to turn it on, as you’d expect. The developer filed an interconnection application, but found out the property is located in a secondary network area, part of the distribution system in urban areas designed to meet higher reliability needs and space constraints.
SepiSolar re-engineered the system to prevent power exports to the grid. We made the best of a difficult situation. But make no mistake. The solution increased the overall cost of the project and sacrificed a lot of revenue. All in all, it was a bad outcome for the project developer brought on by poor interconnection administration.
Getting interconnection right
Successful interconnection administration means more than preparing application forms and turning them in. It also means communicating clearly with the utility, responding to information requests and clarifications, avoiding delays, managing changes and making sure system designs match the system that will be interconnected to the grid.
If SepiSolar had managed the interconnection process for this developer, we would have submitted a pre-application before performing any detailed engineering work, which is part of our standard process for complex interconnections (say, on a secondary network), to verify that subsequent development work like designing, engineering, planning, etc. are even worth pursuing. This is all part of managing project risks in a cost-effective way.
Not all contractors want to act as the intermediary between engineering and the utility, especially when interconnection service may require some amount of input from engineering. After giving out a lot of advice on an hourly basis, we’ve created a standard interconnection service package.
The offering is well defined, responsive to our customers’ needs, and closely coordinated with project engineering. Keep reading to find out why we’ve come to believe it makes perfect sense for project engineering to handle interconnection administration and how interconnection service can add value to your projects at a reasonably low cost.
Interconnection and engineering are intertwined
Interconnection and engineering are parallel processes that continually intersect and diverge. A change to the interconnection application impacts engineering and vice versa.
For starters, engineers provide AC power calculations for interconnection. Routine changes in module or inverter supply simultaneously affect engineering and interconnection.
Further on in project planning, the engineers go off to develop project designs while the interconnection team sorts account names, meter numbers, interconnection type, data submission, and utility verification.
The groups come together again if the utility throws up a surprise interconnection cost, or if the project needs utility approval to establish a point of connection on the utility side of the meter.
A utility-side point of common coupling (POCC) can reduce project costs and can be obtained by verifying code compliance. Sometimes this means doing some research to see if the electrical panel was designed for this type of connection. Or maybe commissioning an inspector to recertify the switchgear.
Once resolved, engineering goes back to supporting construction crews with information requests while interconnection works to get project approval from the utility, signed agreements, and formal permission to operate.
Why not do interconnection administration yourself?
SepiSolar provides interconnection checklists for projects in the SoCal Edison, San Diego Gas & Electric, and PG&E service territories. This increases transparency and accountability with our customers, showing you how we perform the service. But it doesn’t mean we recommend doing interconnection service yourself.
The checklist is a starting point for data collection. What we do with the data determines the path to interconnection.
In some cases, it’s as simple as selecting the most appropriate utility rate tariff, such as NEM-V or NEM-A rather than standard NEM. Sometimes even NEM-MT or non-export makes more sense. In some instances, these choices result in a net savings on interconnection service.
If projects incur utility infrastructure costs, like a million-dollar feeder upgrade, energy storage can help buffer those costs. Other solutions, like demand reduction and energy arbitrage, can go beyond cost mitigation to improve project financials.
Interconnection administration costs
For years, solar project development was all about driving down CapEx. Engineers have strong opinions about modules and inverters. Investors mainly wanted to know about the levelized cost of electricity. If one project doesn’t pencil out, let’s move on to the next one.
Times are changing. As the federal investment tax credit steps down—it’s 4 percent lower than last year and will be another 4 percent lower in January—system performance has a greater effect on return on investment. Energy storage is also affecting long-term performance. All this means developers are showing more interest in projects that don’t have the lowest possible CapEx but can generate the most overall value.
Solar is no longer an analysis of cost only. It’s a cost-benefit analysis, as it ought to be.
SepiSolar charges a base rate for interconnection services on projects with a single meter. More complex projects with a NEM-A or NEM-V rate tariff and those with more complex interconnection processes incur added costs based on the number of meters.
We’ve handled interconnection administration for multi-family housing with over 40 meters. And we have yet to encounter a project we couldn’t manage.
Here to help
Interconnection administration is the most important part of any project. If a project fails at interconnection, it cannot operate and in most cases the goals of the project cannot be achieved.
Yet interconnection is also the most convoluted process riddled with rabbit holes, traps, administrative challenges, and costs. It’s a fascinating process that requires a solid administrative team.
A project engineer who’s familiar with your project can reduce risk and free up contractors to focus on what you do best, construction and customer service.