Chris Crowell
August 27, 2018
Shadow Costs: How Outdated Local Processes Stifle the True Solar Market
(Originally appeared in Solar Builder magazine; reprinted with permission by the author.)
While PV technology has made considerable gains in terms of cost reduction and increased efficiency over the last decade, many authorities having jurisdiction (AHJs) around the country have not. Government often gets credit for growing the solar market through subsidies, but this ignores regulatory hurdles in the way of project completion such as old-timey zoning laws, overly burdensome permitting practices and time-consuming interconnection policies. All of that sticky red tape can stifle PV growth. Certain AHJs are deemed so cumbersome, or confusing, that solar installers avoid them completely — regardless of the true long-term value of solar as a generating asset to a customer and community.
We think it’s worth asking, of the 10,000 jurisdictions out there, how many are not worth the effort, and how many viable solar projects are lost as a result?
Soft Cost Hype
According to the National Renewable Energy Laboratory’s PV System Cost Benchmark Study in 2017, from 2010 to 2017 there was a 61 percent reduction in the installed cost for residential PV systems, 61 percent of which is attributed to hardware costs and 21 percent attributed to non-hardware “soft” costs. From 2016 to 2017, there was a 6 percent reduction in installed system costs — about half of which is a reduction in module factory gate price.
For residential solar PV, hardware costs account for only 0.89 cents per watt of a $2.80 per watt system cost total. A full two-thirds of the cost of a residential solar installation are soft costs, a majority of which are unavoidable business operating expenses, such as customer acquisition ($0.34 per watt) and overhead ($0.31 per watt). Permitting, inspection and interconnection (PII) only made up $0.10 per watt, which seems kind of harmless in the bar graph relative to the non-hardware costs benchmarked in NREL’s study. But what is included in the $0.10 per watt PII cost benchmark?
“There are direct costs that are easier to quantify, like a building permit application fee, but there are opportunity costs associated with regulatory delays that are more difficult to quantify in terms of installed cost, as measured by dollars per watt,” says Kristen Ardani, a solar program lead and analyst at NREL. “For example, NREL’s cost benchmark for residential PII of 0.10 per watt mainly captures direct costs, including an assumed $400 permit fee and six hours of back office labor for building permit and interconnection application preparation and submission. It does not include the costs associated with any regulatory delay or need to submit revised applications.”
She reiterates that NREL’s PV system cost benchmark represents the national average for a typical PV system and does not necessarily reflect the cost of PV installations in jurisdictions with burdensome permitting requirements. Ardani did note more onerous jurisdictions could easily quadruple the assumptions of the PII benchmark.
“For every day a system is delayed, that’s one less day the system is producing revenue and other benefits,” she says. “Also, think of it in terms of time, delays and the cost impact of those delays.”
While less common for the residential market segment, there’s also the cost associated with projects that are stalled to a point in which they are no longer economically viable, which means more indirect costs absorbed in overhead and operating margins. You won’t necessarily find these measured in dollars per watt.
“It can be difficult to quantify the whole suite of soft costs that are perhaps better measured in terms of time and lost opportunity,” Ardani says. “While we have looked more closely at the time required for the utility interconnection process, in terms of business days, NREL has not directly quantified how PV growth is impacted by the lack of standardization in building permitting and inspection processes across more than 18,000 AHJs.”
Beyond Benchmarks
Instead of a big invisible hand pushing the market forward, many municipalities around the country are being kept under the invisible thumb of bureaucracy. The last real study of how many jurisdictions are avoided by solar installers because of onerous permitting processes was a poll done by Clean Power Finance in 2015. At that time, the 273 residential installers (which accounted for 90 percent of the market) showed more than a third of U.S. solar installers say permitting requirements limited growth.
We looked for an update to that Clean Power Finance study and came up empty, but the anecdotal experience of solar installers is still full of head scratchers and headaches. The cities of Portland, Ore., and New York City will elicit audible groans from the solar community, and we’ve heard of many solar contractors avoiding (or charging a premium) to install in seemingly solar-friendly places like Palo Alto, Berkeley and LADWP jurisdictions in California. As a national solar and energy storage design and engineering company based in California, SepiSolar sees and hears it all, much of which boils down to overly burdensome back and forths with AHJs.
“As a general rule, Southern California is the hardest region to pull solar permits,” says SepiSolar CEO Joshua Weiner. “Lots of structural Professional Engineer [PE] work is required, even on residential projects. The Southern California area has many permitting authorities with their own, little, ad-hoc and idiosyncratic rules.”
Example: Some towns have concerns about landscaping and rooftop aesthetics. Rejecting a solar permit based on aesthetics is especially egregious in California because it is actually illegal according to California’s Solar Rights Act. But, that doesn’t stop it from happening and causing a chilling effect in certain pockets of an otherwise solar-friendly state.
“Fairfield, Calif., wouldn’t let us submit plans for a Mercedes-Benz dealership because the solar panels would be visible from the street,” Tiffany Hanson, project manager at SepiSolar says. “We had to throw the Solar Rights Acts at them, and they finally changed their zoning ordinances, but it delayed the project by two months.”
Respondents to the Clean Power Finance survey cited individual projects being subject to the permitting requirements of multiple AHJs. An average installation requires the involvement of two AHJs (including a utility), with some installers reporting up to five AHJs for a single project. This may include a utility, city and/or county planning offices, city and/or county fire departments, a state permitting agency and other AHJs as well.
“It can be difficult for installers to determine which AHJs must be consulted,” says Chelsea Barnes, director of policy services at EQ Research, a provider of policy research, analysis and data services to businesses active in renewable energy. “We often work with installers who need assistance in figuring out the various permitting requirements in a new area where they are seeking to do business. I can tell you from personal experience that you sometimes feel like you are going in circles, being passed from one agency to the next, trying to navigate what the requirements might be for a particular project.”
Delays can arise from inefficient processes and lack of clear communication between installers and AHJs, but often delays can happen due to lack of familiarity with PV technology. The EQ Research team conducted research on solar permitting practices of cities and towns in New York and Massachusetts in 2015. In both states, they report encountering situations where local permitting staff was unfamiliar with solar PV technology and could not provide clear permitting requirements for solar projects to be constructed in their jurisdictions.
“This demonstrated a clear need for training, education and outreach for local officials,” Barnes notes.
In Massachusetts and New York, EQ encountered jurisdictions that did not have an inspector on staff at all, contracting out its inspections instead, which added time. Weiner recalls one permit pulling experience in Rohnert Park, Calif., that involved a city building official who was also the city electrical inspector, plumbing inspector, assistant deputy sheriff and part-time handyman.
Needless to say, that took a while too.
“Things have probably changed over there, but the lesson here is that there are many jurisdictions in the U.S. where solar — and now energy storage — is new, and building inspectors are just getting up to speed on best practices. Rather than complain, offer to help,” he says. “Not only can you speed up your plans, but you’ll also make a friend with someone who can help streamline your permits.”
Ease the Pain
The Department of Energy began funding the SolSmart program in 2015 to help local communities address solar soft costs. One focus area of the program, which is led by The Solar Foundation and the International City/County Management Association, is to reduce friction throughout the solar permitting process. Jurisdictions interested in growing their solar market can consult the checklist of best practices set by SolSmart to achieve one of three levels of certification. In the two years since, SolSmart adoption is ahead of its target (currently at 211 municipalities and counties designated in 37 states with the end goal originally being 300).
The core issue from the SolSmart team’s vantage point, according to Zach Greene, program director at The Solar Foundation, is the lack of transparency, as many jurisdictions literally no information on what developers need to submit.
“A lot of communities don’t express what their needs are for a permitting package and because of that, a developer might not know what to submit,” Greene says. “When that happens there is a constant back and forth between permitting office and installer about forms needed and spec sheets needed or what diagrams they require. That can add a lot of time to the process, especially depending on the responsiveness of local government.”
This is why a baseline requirement for the Bronze SolSmart designation is an online checklist of requirements for the permitting process. Something that basic is a huge first step for reducing the back and forth and general uncertainty holding back business. For large-scale projects, zoning ordinances usually need to be reviewed in terms of decommissioning and the role the county needs to play. Check out some SolSmart designee success stories here.
For solar installers inching that boulder up the hill, Weiner recommends keeping good notes. “It’s really trial and error,” he says. “In other words, the best way to find out how horribly an AHJ or utility will treat you is to submit an application and just go through the process in a brute-force type of manner. Then, the second step is to keep notes of everything that goes wrong or sideways. Then the next time you encounter that jurisdiction, you’ll be prepared with the experience you gained the last time you visited that office.”
Of course, making calls to chief electrical inspectors and plan checkers to get clarity before submitting applications is great, but the right person is often hard to track down.
“Another solution is to collaborate with other installers,” Weiner says. “If it’s the first time you’ve gone to this AHJ, see if you can find another contractor or buddy who has gone through the process and get the skinny on the situation from him or her, so you don’t have to get surprised throughout the process.”
Interconnection Inconsistencies
A slick permitting process is only half the battle because interconnection is often more arduous. In EQ’s 2016 Interconnection report, the researchers found utilities took longer to approve interconnection applications and gain permission to operate (PTO) in 2015 compared to 2014, although the delay increases were much more significant for PTO than for pre-construction applications. For preconstruction waiting periods, the median utility wait time increased from 14 in 2014 to 18 days in 2015; for PTO waiting periods, the median utility wait time increased from 28 in 2014 to 45 days in 2015.
“This is pretty astounding when in some territories, the entire interconnection approval process can take place in less than a week,” Barnes says.
Barnes is correct that the range in waiting periods is wildly inconsistent. In 2015, the average PTO waiting period ranged from one day for ComEd (Ill.) to 154 days for Western Massachusetts Electric Co. (WMECO). These delays were caused by all sorts of things. Installers in North Carolina reported bi-directional meter replacement taking up to a month in Duke Energy territory. Installers in California’s Imperial Irrigation District service territory reported two months for the same thing after already waiting for PTO, which could take up to three months. Installers in Washington, D.C., and Maryland had big complaints of checks getting separated from applications and then lost in Pepco territory (which the utility has since worked to correct).
Maybe increases in processing times are attributed in part to rising volumes of applications and therefore unavoidable? Not necessarily. Ardani notes the examples of San Diego Gas and Electric and Pacific Gas and Electric (PG&E) in California. These two utilities implemented measures to streamline the interconnection process, resulting in decreased processing times despite rising volume of PV interconnection applications. Specifically, in 2012, PG&E’s median cycle time for interconnection applications submitted under the standard net energy metering program approached 20 business days. By the end of 2015, PG&E had decreased the median cycle time to less than 5 business days and today boasts of a same-day turn around for some systems. What’s more, as the number of days plummeted, the number of applications went from 20 a month to more than 6,000. So, even as the office was inundated with applications, the turn times fell off a cliff.
Lastly, as everything sped up, errors went down. Barnes with EQ Research was told by PG&E staff that its online application system would allow it to reduce application errors and application processing time to 5 percent by July 2015, down from a 30 to 40 percent error rate prior to the implementation of the online application system. This happened because the utility linked existing customer data systems to interconnection and net metering application systems so that DG application systems can pull or verify information such as usage data, address, account numbers and even payment information from existing customer accounts.
Alas, nothing is perfect. San Jose, Calif., was the first place to pioneer the online permitting process. It did this by requiring a minimal amount of information on the plans, making the plan check process super simple and basically an instant permit approval, which proved inefficient in its own way.
“Installers in the field got ripped apart by the inspectors,” Weiner reports. “Since no plans were required for a permit, this put all the pressure on installers to get it right the first time. If the installers screwed up or did something the city didn’t like, they’d have to rip off the roof and re-install.”
Installers specializing in San Jose came to understand the idiosyncrasies and made it work, but any installer just trying to install there every so often runs into problems.
Proactive Power
We tried to come up with a number of jurisdictions avoided because of the many issues mentioned. That number doesn’t exist, but those jurisdictions certainly do. In those onerous jurisdictions, even more effects emerge: One project delay causes other delays, causing scheduling difficulties and customer and installer frustration. This leads to fewer solar customers and installers avoiding certain territories, which then reduces competition. Reduced competition leads to a less efficient market, which can lead to higher costs or poor service on top of an already frustrating process.
Contrasted with the pace of innovation by the solar industry to improve efficiencies while decreasing costs, the barriers that exist in the public sector seem relatively straight forward to remove. Consider it from this perspective: How much more cost-effective could solar be in a jurisdiction that prioritized it as a crucial component of a modern, distribution grid — something as simple as solar-ready building requirements for new construction? This question has been top of mind for NREL’s solar analysis team who recently published a roadmap for reducing residential PV costs by 2030.
“There are considerable opportunities for cost reduction resulting from solar ready building codes or installing PV at the time of new construction,” Ardani says. “With much less time dedicated to installing conduit and wiring, costs and time associated with installation can drop dramatically.”
But then, why stop there? We live in a brave new world where the fifth largest economy on the globe (California) is mandating all new residential construction come equipped with solar power.
Ardani notes that “NREL’s recent roadmap analysis findings indicate that there are considerable opportunities to reduce solar soft costs but that innovation in both technology and regulatory practices will be required first.”
Opportunity Lost
All of the above could probably be summed by the meme of two Spidermans pointing at each other.
“In general, there can be a chicken-and-egg problem with interconnection and permitting,” Barnes says. “If utilities or local jurisdictions don’t have much solar, they don’t have a need to develop a better process (or, any processes) to deal with it. If there aren’t transparent processes, it may deter installers from seeking customers in those areas. If the opportunity is great enough, there may be a developer who is willing to be the first mover and figure out the process. All this is to say, there are a lot of factors that a developer will weigh when considering entering a new market, but burdensome permitting and interconnection requirements have historically been significant barriers in many areas throughout the country.”
SolSmart cities and PG&E show that the chicken-egg conundrum is easily avoided by municipalities and utilities that actively do so by coordinating communication, revamping workflow and modernizing outdated assumptions. This secure footing then lets a true local solar market take shape. All of that isn’t necessarily easy, but neither was developing low-cost renewable energy. Since the latter is here, the former has an obligation to catch up.
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