By: Adam Baker
Problems the solar industry must overcome to survive
There are five very specific challenges in utility scale solar projects, making it difficult for the industry to progress.
1. Site Requirements Vary for Utility Scale Solar Projects
This one is especially poignant for developers and owners. Requirements for your solar farm will vary based on transmission region. Three regions in the continental U.S. include Western Interconnection, Eastern Interconnection, and Electric Reliability Council of Texas (ERCOT) Interconnection (Texas).
Texas is the smallest domestic grid, essentially acting as a big island. The smaller the region is, the more variability there is in load vs. demand balance. In Texas it’s usual for utility scale solar projects to require frequency droop, voltage droop, active power curtailment, and voltage control. However, if you’re starting a project in the Eastern interconnection region, active power curtailment has traditionally been the only power requirement.
Within those regions, there are nine sub regions (in the continental U.S), including:
WECC - Western Electricity Coordinating Council
MRO – Midwest Reliability Organization
NPCC – Northeast Power Coordinating Council
RFC – Reliability First Corporation
SERC- Southeast Electric Reliability Council
SPP – Southwest Power Pool
TRE - Texas Reliability Entity
FRCC - Florida Reliability Coordinating Council
Now, those sub-regions don’t necessarily cut off on state lines, so developers and owners must be aware of where potential or current solar sites sit within those regions.
Within the Southeast Region, the pace of installation of solar in North Carolina has been great for the industry, but South Carolina has lagged behind, lacking the financial incentives that have driven the pace to the north.
But we’re not done yet. Your requirements will also vary by state.
This affects commercial and residential solar most prevalently with renewable energy credits, and issues like net metering, but also affects the market for solar with portfolio standards driving the installation of renewables to meet the population’s appetite for clean energy.
Your requirements will also vary by utility, and even within a single utility.
For example, Duke Energy is a large utility in southern North Carolina. They require field witnessing of an anti-islanding test before going to commercial operation. However, if your utility is Duke Progress in northern North Carolina, as long as you can prove your plant meets IEEE requirements for anti-islanding, they don’t require a field witness test. If you contract with Dominion Power (southern Virginia), they require an external system that detects an islanding condition, and a command configured to shut down each inverter.
Lastly, requirements will vary within the county (JHA, or, jurisdiction having authority) in which your utility scale solar projects lie.
Counties are responsible for the electrical and mechanical inspection of the site. An electrical inspector’s level of scrutiny will vary, and the electrical inspectors vary per county. I’ve seen an inspector walk onto the site, open up an inverter control cabinet to look inside, inspect one ground ring connection at an inverter pad, then leave. Obviously, that inspector didn’t have a deep understanding of the most likely places an electrical connection could fail in a solar site. I’ve also seen inspectors come onsite and check for torque witness marks inside a dozen combiner boxes, and verify the torque on those connections. Really both ends of the spectrum, so as you enter a new JHA, it’s hard to know how long the permitting and inspection process will last. The good news here is that strict adherence to NEC and understanding any local extensions to those rules will keep you in compliance, and delays can be avoided.
Ultimately, the requirements you must comply with will be dependent on the stiffness of the grid where the interconnection will occur to ensure the highest level of reliability. Unless you’re building an identical plant over and over again in the same county, it’s likely detailed requirements will vary greatly from project to project.
2. Inconsistent Labor Between Utility Scale Solar Projects (In Certain Regions)
In areas where the labor force has a lot of experience installing solar sites, they develop expertise, and differences between inverter platforms, thin film or silicon, and different interconnection voltages become non-issues. In areas where they don’t install a lot of solar…well, it’s easy to tell.
In a mature solar market like Arizona or California, many of the same workers go from solar project to solar project, bringing their experience. But in the Southeast, it seems like constant training is a requirement. Labor is not fully up to speed.
True, solar is relatively new to some regions, but even in North Carolina, the third ranked solar state by SEIA, it’s difficult to secure the same labor resources for each subsequent project. Often with each new construction project, personnel are trained from scratch and don’t gain the experience required to make the process more efficient over time.
Lumping skills together
As Liam Neeson famously said...
A different set of skills are required in solar construction. You need civil engineering, land management, mechanical installation, electrical installation, and (an often forgotten skill) instrumentation.
Too often, EPCs don’t sufficiently differentiate electrical installation skills from monitoring and instrumentation. If you hire electricians used to working in medium voltage collection, or 1000V DC combiner box termination and expect them to land the 24 or 30 gauge RTD or pyronometer leads, your results won’t be nearly as consistent as they should be, and you’ll receive inaccurate data.
In the labor market, you get what you pay for. When estimating cost of construction, the regionally variable question is “What should I expect to pay people to do this work?” Well, it depends on what region your utility scale solar projects are in. In mature markets with a history of successful PV solar deployments, prevailing wage is accurate. In new markets, prevailing wage for electrical work may be representative of commercial or industrial electrician wages, and not that of an experienced solar installer where the skillset required to be proficient is harder to find.
If you want to ensure quality – expect to pay above prevailing wage in new developing markets.
Even if you have five projects in the same JHA with the same utility, you often won’t get the same workers showing up with contracted labor…which means you may end up training different sets of people to do the same thing.
I’ve seen success with developers/owners that self-perform the work. If you manage the general contractor, the quality is likely be more consistent with your expectations.
3. Too Many Equipment Vendors
This one is more of a nuisance than an actual problem. If you use multiple vendors across sites, it will cost more and take more time.
I’ve seen five solar sites in the same area with five different inverter vendors. What does this mean for consistency? O&M techs have to retrain on every new platform. The inverter installation will be handled differently. Spare parts won’t be the same. Troubleshooting and programming will be different. Interoperability of any component between sites is not likely to be possible.
Here’s my advice. Try to standardize to the extent that you can. More often than not, equipment purchasing decisions are made solely based on procurement pricing. Know that even if keeping the same equipment across sites is a little more expensive, you’ll actually save money in the long run with fewer parts to maintain, support contracts, training, and spare parts. This is most impactful with the intelligent devices like inverters, and meteorological instrumentation, but also true of ‘less intelligent’ components like combiner boxes and transformers.
4. No Desire to Change
My father loved the phrase “If it ain’t broke, don’t fix it”, which although sometimes true, cannot be applied universally. If taken literally, why would I ever change my oil if my engine starts in the morning?
Utilities are responsible for the reliability of the electric system, and the grid has been very reliable over the last 50 years. Therefore, they’re very reluctant to embrace technology change. And for good reason. Nobody wants to be the one that lands in the history books for messing up the grid. I can recall the details of First Energy’s role in the cause of the Northeast Blackout in 2003. Not so much because it affected me, but because the federal investigation was on the nightly news for weeks afterwards.
Unfortunately, this attitude can make implementing/installing/constructing utility scale solar projects an absolute nightmare. For example, a central controller commanding inverter VARs is a valid and proven way of doing real-time voltage control. But most utilities insist on static VAR devices like capacitor banks for voltage management because “that’s the way it’s always been done.” Seems to me that if voltage control is needed when the inverters are operating, and the inverters are capable of VERY fine adjustments to plant VAR output, why would expensive CAP banks be used when they can only deliver steps of adjustment?
On the whole, large utilities make it difficult for independent operators to build and commission sites. System impact study results SHOULD clearly define any required devices for compensation before the project starts, but I have seen several cases where AVR capabilities were needed after construction to avoid flicker. If the requirements were consistent, it would be easier to deal with, but the reality is that requirements can, and sometimes do, change in the middle of a project.
If individual companies want to fight with utilities, I applaud you. But a consistent message will be difficult. It’s up to our industry organizations like SEIA and SEPA to collect best practices and have utility interventions on behalf of individual organizations.
5. Inaccurate Evaluation of Plant Performance
Oftentimes the resources in the operation center are looking for big problems like comms losses, inverters offline, or site trips, and they’re not performing detailed performance analysis to ensure the plant is operating at peak performance.
Part of the problem is that there are only a very small number of people with a very deep understanding on how to evaluate solar plant performance.
Understand that you need specific instrumentation to help you evaluate your plant performance. Take it upon yourself to learn how module soiling affects your site(s). There is certainly a point at which contracting a water truck to wash a site is justified, but without knowing how much energy loss is due to environmental soiling (whether from pollen, the farm next door that just turned a field, or other discreet/seasonal events), it will be very difficult to know when to dispatch that service.
Solar String Analysis is another technology that exists, but is rarely used. From a practical standpoint, day to day monitoring of each of the roughly 200 strings per MW is not valuable. Finding the one bit of datum different today from yesterday amongst the thousands of values collected every 15 minutes is not a reasonable expectation. Sophisticated data analytics may be able to find it, but the cost of all that infrastructure is expensive, and not valuable on an ongoing basis. You may be able to find some insight looking at the inverter input current from a combiner box, but comparing one to the next will only be valuable if you can normalize the data for the amount of DC feeding that combiner.
Alternatively, you could partner with a company that can provide periodic field service to collect some of this data, and work with them to train your operators on how to do this kind of analysis.
Adam Baker is Senior Sales Executive at Affinity Energy with responsibility for providing subject matter expertise in utility-scale solar plant controls, instrumentation, and data acquisition. With 23 years of experience in automation and control, Adam’s previous companies include Rockwell Automation (Allen-Bradley), First Solar, DEPCOM Power, and GE Fanuc Automation.
Adam was instrumental in the development and deployment of three of the largest PV solar power plants in the United States, including 550 MW Topaz Solar in California, 290 MW Agua Caliente Solar in Arizona, and 550 MW Desert Sunlight in the Mojave Desert.
After a 6-year stint in controls design and architecture for the PV solar market, Adam joined Affinity Energy in 2016 and returned to sales leadership, where he has spent most of his career. Adam has a B.S. in Electrical Engineering from the University of Massachusetts, and has been active in environmental and good food movements for several years.