Nov 6, 2025 The Future of Grid - Scale Storage Grid forming projects: Should developers want to design grid-forming inverters they will need to engineer their systems differently. This means that auxiliary loads and losses will be higher, and economics will need to be re-casted to account for SoC-loss during standby operation and forming operation In addition, the following challenges must be navigated: Transformer inrush control POW switching or V/f pre-flux ramp for soft energization Over-voltage issues Handling reactive power absorption Resonance and harmonics Damping network oscillations and ensuring stable short-circuit response Frequency and load pick-up challenges Stabilizing V/f during cold load pickup and staged block loading Operational sequencing Q-droop hierarchy, staged energization, etc. validated via EMT and HIL tests Synchronization issues Smooth ramping, droop control, etc. Ramp rate tuning Staged load pickup and reserve margins Raafe Khan and Shawn Shaw < Back Back

Apr 4, 2025 New U.S. Tariff Policy In an Executive Order signed on April 2, 2025, President Trump has instituted a minimum 10% universal tariff on all imports starting April 5. These 10% tariffs will be additional to “Reciprocal Tariffs” between 10% and 50% on products from about 60 countries starting April 9. The Trump Administration has calculated these Reciprocal Tariffs based on the ratio of country-level trade deficits with the US divided by the value of US imports from the target country. This ratio is being described as a measure of perceived unbalanced trade practices against the US and the Reciprocal Tariffs are being set at 50% of this value for most countries. We note that there are a variety of reasons for countries to have trade deficits and the existence of such deficits is not, in its own, an indication of unfair or unfavorable trade policies. It merely conveys that the US buys more of a country’s exports than that country buys of US exports and these deficits are a normal part of global trade between nations. Exceptions ➡️These new tariffs will not apply to goods that have been loaded on a vessel at a port and are deemed to be in transit before the new rates go into effect. ➡️The universal rate will not apply to goods in transit to the US before April 5 and the reciprocal rates will not apply to goods in transit to the US before April 9. ➡️According to the Executive Order, the new tariffs will not apply to certain articles that President Trump has already singled out for current or possible future sector-specific tariffs. Per the National Electrical Contractors Association (NECA), these sectors are steel, aluminum, some downstream products that use steel or aluminum, copper, pharmaceuticals, autos and auto parts, semiconductors, certain critical minerals and energy and energy products. ➡️The tariffs apply only to the non-US content of goods that include US components. However, at least 20% of the value of such goods would have to originate within the US. Implications for the Energy Sector The new tariffs will impact a variety of energy related technologies, from solar modules produced in Vietnam to wind turbines made with foreign components. FERC recently released their Energy Infrastructure Update for January 2025, in which they noted that the vast majority of new generating capacity will be in solar and wind . Other equipment necessary for bringing power plants online, like switchgear, transformers, and substation equipment is largely imported and will see costs increase. The fossil fuel industry is not exempt, either. Thermal generation equipment, like natural gas combined cycle (NGCC) turbines. Supply is already constrained, and capacity is tied up until about 2029-2031 from Tier 1 suppliers, so added costs will add even more strain. The broad application of new tariffs is expected to have an impact across the energy sector, from gas turbines to solar modules, just as energy demand is growing nationwide to fuel the growth of the AI sector. Impacts on the Energy Storage Supply Chain Many of the countries that supply battery energy storage systems (BESS) to the US market are heavily impacted by the new tariffs. As it currently stands, assuming no other changes, by January 2026, BESS from China will be subject to a total tariff of about 82.4%, as shown below. Clearly, juggling all of the relevant tariffs and duties is a significant exercise with many moving parts. *HTSUS = The Harmonized Tariff Schedule of the United States Tariff Rate Base Tariff, applied March 2025 20.0% HTSUS* Tariff (2012) 3.4.0% Section 301 Tariff 7.5% (2025), 25.0% (2026) Reciprocal Tariff 34.0% Total 64.9% (2025), 82.4% (2026) A summary of the major BESS exporting countries to the US and their new tariffs is shown below. Imported BESS from China have a significantly higher expected tariff than most other countries exporting BESS into the US market. The final tariffs on any product, however, will be complicated to determine as the underlying components may, themselves, be subject to additional tariffs (e.g., an Indonesian BESS made with Chinese inputs). This will be most impactful to the lithium iron phosphate (LFP) BESS suppliers in the near term but with no country being exempt from at least some sort of tariff, we can expect a great deal of supply chain adjustment in the months ahead. Country HTSUS Tariff Base Tariff Section 301 Tariff (Before 1/1/26) Section 301 Tariff (After 1/1/26) US Reciprocal Tariff Total New Tarriff Rate in 2025 Total New Tariff Rate in 2026 China 3.4% 20.0% 7.5% 25.0% 34.0% 64.9% 82.4% Indonesia 3.4% 10.0% 0.0% 0.0% 32.0% 45.4% 45.4% South Korea 3.4% 10.0% 0.0% 0.0% 25.0% 38.4% 38.4% Japan 3.4% 10.0% 0.0% 0.0% 24.0% 37.4% 37.4% Impacts on Battery Storage Pricing Based on our tariff tracker, Chinese made DC blocks are now effectively between the $130 - $180 per kWh-dc range (DDP to site), whereas Non-Chinese DC blocks (manufactured in let’s say Indonesia) are between the $115 - $165 per kWh-dc range (DDP to site). Baseline costs are expected to shift in the near term so this gap may narrow or widen further based on macroeconomic conditions. The gap between domestically manufactured non-LFP DC blocks and Chinese made LFP blocks is expected to narrow by early next year to about $50-$60 per kWh-dc. This means, if OEMs in this category reduce their prices by about 25-30%, based on current capacity projects, then, domestically manufactured non-LFP BESS will be a more attractive option for buyers based on total cost of ownership, not inclusive of the domestic content adder under the IRA. It is to be noted that the American Active Anode Material Producers (AAAMP) filed an AD/CVD petition in 2024 seeking a tariff of up to 910%. This has not yet been adjudicated by the Department of Commerce; however, we expect some movement on this later this fiscal year. Chart from Camelot Energy Group – Impact of April 5 Tariff on DC Blocks International Reactions The scale of the current trade actions is highly likely to elicit stiff responses from the international community. As of this morning of 4/4/25, China has announced a 34% tariff on all US imports, alongside increased export controls affecting rare earth minerals and other key materials exported to the US. While the US is a net importer of most clean energy technologies, US exports of biofuels and components for wind and hydropower systems may be impacted. Perhaps even more impactful, however, would be an increase in export controls that reduce the availability of key input materials. Efforts to onshore lithium-ion battery production, for example, will struggle without a ready supply of high grade graphite for making suitable anodes (currently, despite recent AD/CVD claims, there are no domestic suppliers of graphite who can meet the battery industry’s purity requirements). Also, the majority of equipment used in manufacturing solar cells is currently sold by China, with one recent manufacturer Camelot spoke with indicating the only other option was to buy European equipment at “4x the cost and half the output” compared to the Chinese alternatives. If these trade actions are intended to spur a renaissance of domestic manufacturing, the US is highly vulnerable to interrupted supply chains and export controls from abroad that restrict the very tools we need to build and scale a domestic manufacturing industry. The global trade situation and its impacts on the clean energy sector are evolving quickly and this is a developing topic. Stay tuned for periodic updates from the Camelot team in the days ahead. Follow us on LinkedIn for the latest insights. Next Steps for Industry Stakeholders With growing pressure due to pricing, it is time to carefully evaluate projects and supply chain risks. The Camelot team can help asset owners, investors, and other key stakeholders: Perform due diligence on potential new projects, optimizing technology, revenue streams, and asset management strategy Establish, strengthen, and diversify supply chains to ensure you have flexibility to keep your projects on track Evaluate new technologies that may offer new opportunities, as well as new challenges The Camelot team combines technical, economic, procurement, and strategic insights to help our clients navigate the changing market. Reach out to Hello@CamelotEnergyGroup.com today. We look forward to hearing how the new tariffs affect your business- and ensuring you get the help you need. Bespoke technical and strategic advisory for a better world Raafe Khan, Shawn Shaw < Back Back

Mar 10, 2025 Constructability Part 1 Constructability refers to the overall ease and efficiency with which a project can be built. This directly influences both the speed of construction, and the cost required to complete the project. It encompasses various aspects of design, planning, procurement, and execution to ensure the project can be built effectively, safely, and within budget and timeline constraints. The Importance of Constructability in Solar and Battery Storage Projects When it comes to solar and battery storage projects, constructability should be considered as early as the site acquisition stage. Typically, during this phase, developers identify a potential land parcel and create a preliminary layout to assess site capacity, estimate annual energy production, and gauge interconnection feasibility using the limited information available. While this is a crucial first step, constructability concerns are often overlooked or insufficiently analyzed. This can lead to projects with critical constructability challenges advancing through the development process—resulting in wasted time and money on projects with a low likelihood of successful execution. The Camelot Energy team has extensive experience in development, engineering, procurement, and construction, allowing us to help owners and developers identify and address constructability concerns early in a project’s lifecycle. By doing so, we help mitigate late-stage issues, ensuring smoother project execution. This article is the first in a series on "Constructability," where the Camelot team will highlight common challenges and showcase solutions that enable seamless project development and construction. The Ups and Downs of Topography in Renewable Energy Projects One of the most common constructability issues we encounter during the development and construction phases is inadequate attention to topography . The terrain of a project site significantly impacts design feasibility, energy production estimates, and overall constructability. Why Topography Matters Most preliminary project layouts are created using publicly available data, which typically provides only 5’ or 10’ contour intervals. While this offers a rough idea of site conditions, it lacks the precision needed to fully de-risk a project. This limitation is particularly problematic for sites with complex terrain, dense forestation, or proximity to floodplains. For such projects, hiring a professional survey company to conduct a detailed topographic survey (with 2’ contour intervals or finer) is essential. This data enables developers and engineers to validate site conditions accurately and plan accordingly. Using Topography Data in Project Design and Development Once a detailed topographic survey is completed, the preliminary layout—including solar arrays, battery storage units, access roads, fencing, and equipment pads—should be incorporated into computer-aided design (CAD) software . By integrating this data into the design, engineers can assess site suitability and proactively address constructability challenges. At this stage, a slope analysis should be conducted to identify areas of concern. This analysis requires input from multiple disciplines, including civil, structural, and electrical engineers, construction professionals, and racking vendors . Collaboration ensures that all aspects of the project are evaluated, and risks are mitigated early. Key Topography Considerations for Constructability Civil Design Grading requirements to meet design standards Stormwater management and hydrology considerations Access road construction feasibility Equipment pad locations and elevation planning Structural Design Vendor-specific racking slope tolerances Structural calculations for stability and safety Accommodation of varying site elevations Electrical Design Trenching and underground conductor runs Placement of medium-voltage poles and guy wires for overhead lines Routing and protection of underground cables Construction Considerations Water management strategies during construction Temporary erosion control measures Site layout for construction staging areas Placement of office trailers and parking zones Operations & Maintenance (O&M) Planning Long-term vegetation management strategies Ongoing erosion control measures Why Early Topographic Analysis is Essential Topography sets the foundation for every aspect of a renewable energy project—it is the building block of successful development and project design. Identifying and addressing topographic challenges early minimizes risks, helps maintain budget and schedule discipline, and ensures that project goals are met. By taking a proactive approach, developers can avoid costly redesigns, permitting delays, and unexpected construction obstacles. Looking Ahead This article is just the beginning of our series on constructability. In upcoming articles, we will dive deeper into other critical factors affecting constructability, including geotechnical challenges, interconnection hurdles, and procurement risks. Stay tuned for more constructability insights from the Camelot Energy Group! < Back Back

< Back Sagar Bharadwaj, PMP Project Manager Sagar Bharadwaj is a Project Manager at Camelot Energy Group with experience in renewable energy, energy storage, and project management. His work spans battery energy storage systems (BESS), long-duration energy storage, hydrogen technologies, technical project management, and engineering coordination, supporting projects from early-stage development through execution. Prior to joining Camelot, Sagar worked across the energy storage and clean energy sectors, supporting the development of lithium-ion and non-lithium battery technologies, hydrogen-powered aviation systems, and utility-scale energy storage projects. He managed the development of a long-duration battery energy storage project at the University of Minnesota, leading technical evaluations, procurement strategy, financial analysis, and project planning. He also supported the development of hydrogen-powered aviation systems at ZeroAvia and contributed to the development of battery technologies at Aerosapien Technologies. Sagar holds a Master of Science in Energy Science, Technology & Policy from Carnegie Mellon University and a Bachelor of Technology in Mechanical Engineering from Vellore Institute of Technology (VIT). He is also a certified Project Management Professional (PMP®). Outside of work, Sagar enjoys producing music, experimenting with new recipes, traveling to national parks, and staying up to date on emerging technologies Sagar.Bharadwaj@camelotenergygroup.com

Aug 30, 2024 Solar Availability Series Part 3 Welcome back for Part 3 of Camelot’s series on solar availability, which is an appropriately-hot topic as the industry continues to mature. If you’re just joining us for the series, please checkout Part 1 and Part 2 of this series. We’ve set the groundwork with how availabilities are calculated and reported along with the current state of IE assumptions. Today we’ll touch on ways of maximizing availability (minimizing downtime). This topic could be its own series, so we’ll focus on the bigger picture. If you’re curious about Camelot’s stance on availability assumptions as an IE, be on the lookout for future parts in this series. Thank you for joining us! The most impactful sources of downtime come from major component failures such as from inverters, which put entire blocks of a system offline at the same time, although more minor events can still bring smaller portions of the site down. We’ll focus primarily on the most impactful contributors to downtime here. There are two broad, controllable factors which impact availability: The frequency of downtime events , driven by component failure rates and the need for planned maintenance. The quality of the engineering and proactive maintenance is important for this piece; and The duration of downtime events , driven by staffing, readiness of replacements, and other primarily-O&M considerations. Reducing the Frequency and Duration of Downtime Events During Operations Owners and O&M providers and can have a significant impact on both the frequency and duration of downtime events at an operational project once it’s been built. Here are a few recommendations for ensuring success: Follow a Robust O&M Agreement. The O&M agreement should be closely followed during operations, which unfortunately does not always occur. The agreement should be robust and include elements of the items below. More recommendations for O&M agreements are also included in the next section. Predictive Maintenance: Utilize data analytics to predict potential equipment failures before they occur. By analyzing trends and historical data, O&M teams can identify patterns that signal imminent issues, allowing for timely interventions. Sufficient Preventive Maintenance: Schedule regular maintenance based on equipment manufacturers' guidelines and site-specific conditions. This includes checking electrical connections and inspecting mechanical systems such as trackers. Of note, energy-based availabilities can be optimized by scheduling maintenance events during periods of expectedly-low production. The time-based availability metric might be the same, but the smaller energy loss means a higher energy-based availability. Spare Parts Management: Maintain a well-stocked inventory of critical spare parts on-site or at a nearby location. This ensures that replacements can be done swiftly without waiting for parts to be ordered and delivered. Follow manufacturer recommended list and review periodically as components may become less available over time. Strong Vendor Relationships: Collaborate closely with equipment manufacturers and vendors to gain access to the latest updates, best practices, and support services. This can also help in negotiating favorable terms for spare parts and service agreements. Third-Party Audits: Engage third-parties to review the performance of the O&M program periodically. External audits can provide fresh insights and identify areas for improvement that internal teams might overlook. Training: conduct regular staff training and testing to ensure readiness for major component failures and extreme weather events. An inverter fire which caused system-wide availabilities to drop for a significant period of time Reducing the Frequency and Duration of Downtime Events During Development O&M activities may be the most visible contributor to a Project’s operational success, but they are not everything. An ace car mechanic can still see more issues with an old, poorly-built junker than a novice will see with a durable, high-end car. Camelot encourages developers to have a mindset of ensuring long-term operational success, which leads to fewer issues and less-impactful downtime. For this, we offer a few broad suggestions: Environmental Impacts: Consider site suitability at an early stage. Evaluate potential environmental risks such as wildlife interference, extreme wind speeds, natural disasters, and erosion which could affect the project’s operation and maintenance. Durable Components : Select robust inverters, transformers, racking systems, and other components designed to withstand harsh environmental conditions and have low failure rates. This often means evaluating cost tradeoffs for more expensive components. Exceed Codes and Standards: At a minimum, ensure the project complies with all local, regional, and international standards for safety, performance, and environmental impact. Even more importantly, most EPC agreements only require code compliance, and code is not about longevity of the asset, it is about safety. As such, make sure your EPC Agreement reflects materials, methods, and design standards consistent with the planned (and financed) useful life. Access: Ensure the site has adequate access for maintenance personnel, which can impact the duration of downtime events. Make major equipment accessible near site roadways and ensure roads are wide enough to facilitate easy use of cranes and other heavy kit. Design the site to allow for spacing between components so that specialized equipment isn’t required for access and repair. Remote Monitoring Infrastructure : Deploy advanced SCADA (Supervisory Control and Data Acquisition) systems to monitor the performance of the solar farm in real-time. This allows for quick identification of issues before they lead to significant downtime. Contract with Reliable O&M providers : Developers will elect to engage with O&M providers during the later stages of development, and should do their due diligence on prospective providers to ensure they will have the right capabilities. The O&M contract should be comprehensive and include elements of the list in the prior section. A few of the most impactful items include: Availability Guarantees: The agreement should include specific availability targets. These targets set clear expectations for how often the solar plant should be operational, and should be tied to incentives to increase the chance of compliance and incentivize high availability. Maintenance Schedules and Protocols , including preventative maintenance schedules, corrective maintenance procedures, and component replacement protocols. Regular Reporting Requirements: The agreement should mandate regular performance reports, including availability, downtime events, maintenance activities, and any corrective actions taken. Transparency in reporting helps project owners monitor O&M effectiveness. For more details on ways of ensuring optimal operations at a solar project, Camelot has released a couple of related articles, including Navigating the Testing and Commissioning Process for Solar Projects , and Tips and Tricks for Procuring PV Modules in 2024 and Beyond . For quick examples of some of the more notable mistakes made in construction/operations which directly lead to lower availabilities, you can follow us on our ongoing Field Failure Series (FFS) . The next article in this series will cover Camelot’s balanced approach when advising our clients on availability expectations for our projects. In the meantime, for questions and more details about Camelot Energy Group and our distinct attitude towards these issues, please reach out at info@camelotenergygroup.com . About Camelot Energy Group is a technical and strategic advisor to owners and investors in clean energy and energy storage projects, programs, and infrastructure. Guided by our core values of courage, empathy, integrity, and service we seek to support the energy needs of a just, sustainable, and equitable future. Our team has experience in supporting 7+GW of solar PV and 10+ GWh of energy storage and offers expertise in technology, codes and standards, engineering, public programs, project finance, installation methods, quality assurance, safety, contract negotiation, and related topics. Our services are tailored to a providing a different kind of consulting experience that emphasizes the humanity of our clients and team members, resulting in a high quality bespoke service, delivered with focus, attention, and purpose. Key services include: -Technical due diligence of projects and technologies -Owner’s representative and engineer support -Strategic planning -Training and coaching -Codes and standards consulting -Contract negotiation and support < Back Back

Mar 20, 2025 New Acquisition Opportunity in MISO At Camelot, we always try to keep a finger on the pulse of the solar and energy storage M&A market, as many of our clients turn to us for technical and market due diligence on these sorts of engagements. We just had a noteworthy M&A opportunity come across our desk from our friends at Enerdatics and wanted to share another new opportunity with our network. It’s for a portfolio of ten hybrid (Solar + BESS) projects and one standalone BESS in MISO, a region where many folks have had development and acquisition interests in projects of these kinds. This unique opportunity comprises ten hybrid projects and one standalone BESS totaling 327 MW of solar with co-located BESS + 200 MW of standalone BESS , available for sale in Illinois, Indiana, Wisconsin, and Michigan, USA. Projects are in mid-stage development. Eight of the eleven projects belong to the DPP 2022 cluster and have received their DPP1 Interconnection Cost Estimates from MISO. Initial development, including CIAs, Wetland Delineations, and Phase 1 ESAs, has been completed. The Projects benefit from long option periods of up to 10 years, providing significant flexibility in development. Geographic diversification across four states helps mitigate idiosyncratic market risks of development. Additional details are provided below. The seller is targeting to receive non-binding offers by March 28th, 2025 – please reach out now if you are interested! The seller’s preference is to transfer the ownership of the entire portfolio but is open to considering proposals for a subset of the portfolio in the interest of maximizing the value and number of projects that achieve commercial operation. Camelot Insights Camelot has recently performed diligence on several projects in MISO and we find that revenues can vary widely based on the system sizing and offtake strategy. Similar hybrid projects present a great opportunity and favorable economics in MISO; the ISO took the lead in 2024 with the highest total hybrid capacity in asset level M&A transactions compared to other ISOs/RTOs. In MISO, both Energy and Capacity account for a significant portion of the total revenue stack. Camelot recommends a thorough review of the revenue stack assumptions for the projects in this portfolio. Capacity Market: As MISO transitions to the Direct Loss of Load (DLOL) accreditation method for its capacity market, the accreditation for certain renewable resources is in flux and should be considered. The DLOL accreditation method evaluates the contributions of different resources primarily based on the availability of class-wide resources during a select set of high-risk hours. This method serves as a practical approximation of marginal Effective Load Carrying Capability (ELCC), potentially affecting how renewable and storage assets are valued within the capacity market. Energy Market : The energy market in MISO plays a crucial role in project economics due to its inherent nodal volatility. The variability in Locational Marginal Pricing (LMP) across nodes can present both risks and opportunities. Projects sited near congested nodes may experience significant price swings, which can create arbitrage opportunities for storage assets, allowing them to capitalize on price spreads. Given these factors, strategic site selection and an in-depth nodal analysis are recommended for maximizing returns in the MISO energy market. Costs & Technical Insights : Camelot also has recent data on CAPEX and OPEX applicable to the region and can perform a wholistic economic analysis of the projects to vet the seller’s assumptions. This, together with an evaluation of technology, designs, and key agreements, can help to refine your valuation and de-risk the technical aspects of the transaction. Please Reach Out Overall, this is an attractive opportunity in a very active market. If you are interested, we would be glad to put you in touch with the seller, and if you decide to pursue and need any help on the due diligence side of things, please reach out to Michelle Aguirre or Shawn Shaw, PE . Upcoming Webinar with Enerdatics Finally, stay tuned for an invite to an upcoming webinar which will be co-hosted by Camelot Energy Group and Enerdatics covering key trends in the US M&A market in 2024, including the growth of BESS and hybrid projects, and the uptick in activity in MISO. < Back Back

Aug 8, 2025 Camelot Unpacks UL 9540 – Part 2 In Part 1 of our Camelot Unpacks UL 9540 series, we tackled some of the most common misconceptions about this critical Battery Energy Storage System (BESS) Standard - misconceptions that can easily derail schedules, inflate costs, or cause compliance headaches. Now, it’s time to move from myth-busting to the nuts and bolts. In Part 2, we’ll walk through some key questions regarding the requirements baked into UL 9540, highlight when and why it’s required, and shed light on the often-misunderstood Field Listing process. Whether you’re overseeing a project, supplying equipment, or working on the financing side, this is the knowledge that keeps your BESS project both compliant and bankable. What does UL 9540 include? While no product certification is ever a perfect guarantee of safety, the UL 9540 Standard is fairly broad in its scope as it's intended for an ESS as a whole, with key tests summarized below. These tests are additional to compliance requirements related to materials, construction, software, electrical design, fire safety design, noise levels, and more. These tests are also additional to any component-level tests required. For example, UL 1973 includes about 30 different tests on the battery modules alone, covering a range of potential risks, such as overcharging, over-temperature operation, external fire exposure, and physical impacts. Table 1: UL 9540 Key Tests Test Category Test Name Description   Electrical Safety Grounding & Bonding Ensures low resistance ground path to safely handle potential fault currents   Electrical Safety Electromagnetic Immunity Ensures safety sub-systems are not subject to electromagnetic interference and electrostatic discharge.   Electrical Safety Insulation Resistance Confirms insulation provides suitable impedance to prevent unintended current flow.   Electrical Safety Dielectric Voltage Withstand Confirms the suitability of dielectric materials to prevent current flow without breakdown.   Electrical Safety Impulse Test Assesses resistance to electrical surges. Fire & Thermal Safety Thermal Runaway Propagation Requires testing according to UL 9540A, with results incorporated into the system design. Mechanical Safety Leakage Confirms no leakage occurs when stress-testing liquid coolant systems with elevated pressure levels. Mechanical Safety Strength Confirms that elevated pressure in coolant systems does not cause damage to piping and equipment. Environmental Testing Seismic Confirms no major equipment damage after simulated seismic event. Environmental Testing Salt Fog Confirms resistance to marine environments. Environmental Testing Moisture Resistance Tests to confirm that enclosures properly resist water ingress. Other Operational Tests Normal Operating Verifies that ESS components do not exceed temperature ratings during normal charge/discharge behavior. Key Subordinate Standards Compliance with UL 1973 (Batteries) Ensures battery modules meet safety and performance standards. Key Subordinate Standards Compliance with UL 1741 (Inverters) Tests the safe integration of inverters in the system.   When is UL 9540 Listing Required? Compliance with UL 9540 is required under a number of major Codes, as summarized below. Note that, as of this writing, nearly all locations within the US require compliance with at least one of the Code editions noted below (or a more recent version). There are likely a few local jurisdictions not yet enforcing these Code editions but, essentially, Listing to UL 9540 is a Code requirement nearly anywhere in the US.     Referencing Code First Version Incorporating Listing for BESS Relevant Section(s) NFPA 70: National Electrical Code 2017 706.5 NFPA 1: Fire Code 2018 Chapter 52, which requires compliance with NFPA 855 which, in turn requires UL 9540 Listing in Section 9.2.1 (2023 Edition) IFC: International Fire Code 2018 1207.3.1   Is it Acceptable to Field List a BESS to UL 9540? Certainly, this is quite common and widely accepted. In practice (and in Code) an ESS is "one or more devices, assembled together, capable of storing energy to supply electrical energy at a future time". As you can see, this goes beyond simply the ESS enclosure to include the equipment facilitating connection to the broader electrical system, such as the inverter. Most ESS manufacturers will not have an infinite combination of their product listed with each possible DC converter, inverter, and transformer. As such, Field Listing is widely required to validate the "system" meets relevant Code requirements.   How does Field Listing Work? The term "Field Listing" is a slight misnomer, as the "field" portion is only a small part of the overall review. In fact, completing the Field Listing requires considerable review of documentation and generally requires that all the components of the ESS be Listed to their own respective Standards (see summary above). The Nationally Recognized Testing Laboratory (NRTL) doing the Field Listing will review the documentation and subordinate Listing status of all the major components in order to underpin their final Field Listing. As you can see, a successful Field Listing requires that the ESS uses high quality components that are properly Listed, and the Field Listing is really just validating the site-specific combination of those components (and that those components have been installed/used per their Listing). Once complete, the NRTL will issue a Field Listing that applies only to that specific project or installation. Even if the exact same equipment is used again at another site, a new Field Listing is still required. The pathway from Code requirement to (some of) the underlying Standards is summarized in the figure below. As you can see, a simple UL 9540 Listing has a lot behind it and is a critical element in having a high quality and bankable BESS. Figure 1: Compliance Pathway   Why do the Components Need to be Listed Separately for a Field Listing? Put simply, many of the required tests to List a BESS to UL 9540 are destructive in nature and you would not want them done to your commercial project. For example: UL 9540A testing requires initiating thermal runaway (aka making the system catch fire on purpose) Vibration and Impact Resistance tests may involve damaging your enclosures Overcurrent and overvoltage tests require exposing the BESS to electrical conditions beyond its design As you can imagine, few manufacturers would be willing to honor warranties after you abuse their system in such ways. So, since we can't deliberately set projects on fire in the field, the NRTL will have to rely on the test results used to obtain other component Listings. As shown above, the DC Block is already Listed to UL 9540. In these cases, all of the most strenuous tests have already been completed and found sufficient by a NRTL and the Field Listing can really focus on the combination of components. In some cases, NRTLs may be willing to issue Field Listings based on manufacturer test reports, engineering analyses, and similar documents but this is a very risky prospect and will take considerably longer and increase the cost to the owner. Also, if the NRTL finds they don’t have sufficient basis for granting the Field Listing, they may require additional testing from the manufacturer, leaving your project in a sort of Limbo state for months, if not longer. So, while any combination of ESS components can theoretically be granted a Field Listing, it is far safer to ensure your ESS is a combination of already-Listed components. In particular, using a DC block that is Listed to UL 9540 in its own right is a great way to reduce the risk of significant costs and/or delays in the final Field Listing process. < Back Back

Feb 4, 2026 Tired of BESS commissioning delays? Start the process earlier than you think Teams often treat the commissioning of battery energy storage systems (BESS) as a late-stage checkbox rather than a project-defining discipline. Projects can succeed or fail during commissioning. However, most commissioning failures stem from organizational, contractual, and procedural lapses rather than technical issues. While many engineers and project managers bring deep experience in solar and wind, you can’t apply the same approaches to energy storage. Energy storage systems are more complex — both technically and commercially — and require a higher degree of integration, training, and engineering discipline to commission a battery energy storage system successfully. A structured, phased commissioning plan brings every discipline together from the outset with clear tasks, ownership, dependencies in their sequential order, and minimizes surprises and delays. This approach not only safeguards project integrity and compliance but also establishes clear responsibilities, fosters ownership, collaboration, and accountability among project stakeholders. Ownership, transparency, and accountability are non-negotiable. Commissioning is not simply that final checkbox at the end of the project. Instead, effective commissioning begins at project initiation and continues as an ongoing process, overlapping with construction, through to acceptance testing. Risks from early decisions made in isolation are often overlooked. However, their impacts become evident later in the project — triggering delays and costly fixes precisely when the schedule can least absorb them. Commissioning problems often result from a lack of a cohesive, integrated plan that considers all stakeholders. While each contractor may have its own comprehensive Responsible, Accountable, Consulted, and Informed (RACI) matrix, minimizing commissioning risks requires a single, fully integrated RACI matrix that addresses all the project’s components and phases. Defining ownership, clear roles, responsibilities, accountabilities, and dependencies at the outset of the project ensures smooth handovers. EPCs, subcontractors, OEMs, owners, and other involved parties often identify scope gaps too late to avoid scheduling delays. These details, although small, are easily overlooked, yet can cause massive headaches and costs. A fully integrated commissioning may seem prohibitively long, detailed, and too complicated for practical use. However, the lack of a master plan often results in rework, confusion, back-and-forth, and ultimately, schedule delays and liquidated damages. Planning for the entire commissioning sequence from the beginning through to project final acceptance reduces surprises later in the project. A good rule of thumb is to plan for the worst and be pleasantly surprised at the end. From silos to signal: coordinating the whole commissioning team Facilitating communication across the entire team helps close gaps. While large calls with multiple parties may seem inefficient, so are commissioning delays! As painful as these calls may be, they remain a necessary investment of time to catch inconsistencies and miscommunication. Daily check-ins focused on commissioning and testing serve as essential touchpoints, breaking down silos, synchronizing activities, and clarifying accountability. At this stage, a third-party commissioning expert becomes invaluable. A seasoned facilitator knows which questions to ask, spots potential red flags long before they turn into schedule killers, and guides both live discussions and asynchronous communication to keep progress on track. Robust standards exist, but compliance doesn't always follow. A common misconception is that BESS is too new and lacks robust regulatory standards, especially for fire risk and safety compliance. In reality, the National Fire Protection Association (NFPA) and the National Electrical Code (NEC) have evolved in step with the industry, with meaningful updates such as UL9540A (5th edition), UL9540 (3rd edition), and new ESS-specific requirements in the upcoming 2026 NEC edition. Additionally, long-standing international standards, like IEC 62619 and the IEC 62933 Series, provide comprehensive safety and performance codes and standards that are well-established, vetted, and globally referenced for decades. The real issue with standards isn’t their existence — it lies in how seriously they are taken. It may be tempting to accelerate the design or testing process by selectively interpreting statutes and accepting the “minimum viable compliance” rather than delivering true industry best practices and high-quality adherence. This pressure often stems from the substantial financial incentives tied to the contractual completion milestones. When completion milestones trigger large contractor payments and give owners progress to report to investors, both sides feel the pull to “just get it done.” Under pressure, shortcuts can start to look appealing. Common shortcuts I’ve seen include incomplete test reports, missing serial numbers and calibration certificates, omitted verification steps, and insufficient photographic documentation. In the worst cases, critical equipment such as medium‑voltage transformers or battery modules — impacting system capacity — end up on the punch list. Once that happens, the finger-pointing begins, or worse, teams walk away assuming “someone else will deal with it.” Experienced contractors know the compliance standards. Shortcuts rarely result from ignorance — they come from gaps in structure, accountability, and oversight. A robust, well-designed commissioning plan is the strongest tool you have to minimize the opportunity for mistakes, both intentional and unintentional. Commissioning ultimately tests project leadership, and many projects stumble right at the final stages. Yours does not have to be one of them. Don’t let your project fall into these preventable pitfalls; develop a well-informed plan from the beginning. Lynn Appollis Laurent < Back Back

Mar 27, 2026 From lab to grid: making LDES bankable The grid already faces multi-hour and multi-day imbalances caused by transmission constraints, renewable intermittency, and extreme weather volatility. The rapid addition of data centers further complicates this situation, adding peak load to an already stressed grid. As the traditional 2-4 hour storage market tightens, and large-AI-based loads demand a higher degree of reliability and redundancy, long-duration energy storage (LDES) is gaining serious attention from developers, Independent Power Producers (IPPs), utilities, and investors. LDES matters now more than ever because: Renewable penetration is accelerating , leading to increased curtailment. Industrial electrification is increasing baseload demand , adding stress to transmission and distribution systems. Peak load is growing , leading to overbuilding of generation. Extreme weather is stressing grids globally , increasing the need for flexibility. Contrary to popular belief, LDES is not a future solution. The technologies exist today, but have yet to be successfully field-tested in long-term projects. When deploying LDES at scale, the deciding factors will be cost, performance, and commercial viability, which will all determine the market’s true winners and losers. The chemistry war: A distraction from the real issue Energy storage professionals have debated which chemistry or brand name is ideal for long-duration applications. This debate, while lively, is besides the point. Industry efforts should focus on technology-agnostic procurement – picking the technology that fits the use case. While most markets still anchor to the 4-hour lithium-ion benchmark, reflecting yesterday’s grid needs, intraday needs exceed 4 hours, and multi-day reliability events are increasing. Lithium currently wins on performance and experience, with ~90% round-trip efficiency, a mature bankability profile, and proven deployment at scale. However, lithium performs best for 4-hour use cases (or less) and 15-20 year technical life expectations. If efficiency, upfront capital outlay, and energy density are critical to the project, lithium-ion typically wins. But when fire safety, total cost of ownership, a fully or primarily domestic supply chain, or >8-hour discharge needs dominate, a non-lithium technology may be superior. “The longer the better” is the right answer for most LDES projects, but each deployment will have varying problems and solutions. Longer doesn’t just mean longer discharge duration, but also a longer calendar life. Duration should be defined by system need, not by lithium’s historical average, and the right chemistry cocktail should be tailored not to industry standard but to individual use cases. Scaling too fast will break things Despite record installation numbers, the long-term degradation performance of utility-scale storage remains uncertain. Most assets are underwritten on lab-based, accelerated testing, so we truly don’t understand how these systems are expected to perform between years 10 and 20 of their operating lives. The utility-scale storage industry is little more than a decade old, and no battery fleet has reached end-of-life. At this stage, decommissioning frameworks remain theoretical rather than concrete. Commissioning engineers and project managers currently rely on performance metrics documented by accelerated lab testing instead of real-world use cases and stressors. Furthermore, few asset owners of deployed projects possess true fleet-level transparency regarding battery health and key dispatch metrics. Taken together, these factors make project failure – or faster-than-promised degradation – highly likely. Depending on the project structure, some teams will catch and fix these issues over time. However, many won’t have a fix available to them due to the rapid evolution of cell form factors and subsystem hardware and software architecture. With storage remaining untested in long-term, real-world projects, industry skepticism remains a hurdle. Overcoming this will require LDES demonstrating real-world degradation performance, ease of integration, enhanced safety, lower lifecycle costs, and reliability comparable to lithium. Long-term financial viability also matters. Buyers need confidence that the supplier will be around for multiple decades to provide technical support, spare parts, and warranty response. We also need to ensure that we close the gap between economic forecasts and operational realities, and how risk is underwritten. Hopefully, with deployment and manufacturing scale, the economics will follow, making LDES the right choice for energy generation projects and facilities. Policy frameworks shape LDES deployment now, but they remain far behind Historically, ancillary service markets have been the early proving ground for energy storage around the world. Because these products reward fast response over short time windows—typically minutes to about an hour—short-duration batteries had a built-in advantage: they could follow rapid control signals and deliver frequent, shallow charge-and-discharge cycles that align well with today’s battery performance. But as growing renewable generation pushes fossil “thermal” plants further down the dispatch order and into a more backup role, the grid increasingly needs LDES to do what fast services can’t: capture excess clean energy that would otherwise be curtailed, provide resilience and flexibility during longer imbalances, and help keep the lowest-cost electricity available when it’s needed. That said, the current ancillary service market designs reward speed, not endurance. If fundamental price signals evolve to incentivize lower-cost, longer-duration assets that perform at a high reliability standard, the market will rise to the challenge. LDES needs clear market incentives. Those signals may show up over time, but capacity markets could help make long-term projects financeable now. The recent federal policy changes promoting domestic manufacturing now reshape the equation. Lithium-ion supply chains remain heavily dependent on both mining and processing outside the U.S.. With new FEOC guidance under the OBBB and tariff policy implementation, any critical mineral material that can be found domestically gains a huge homefield advantage in cost and tax credit eligibility. Many lithium alternatives in LDES, such as zinc and sodium, draw on U.S. deposits. While gaining traction, these technologies remain untested at a mass scale and still lack the affordability and performance of lithium-ion. Policy levers can accelerate innovation and encourage market adoption, and policymakers have many in the works. LDES provides essential infrastructure. As the grid incorporates more renewable energy sources and retires older fossil fuel facilities, only massive deployment and integration of LDES can guarantee grid reliability. The technology exists; companies are building it, and deployments are happening. Yet cost competitiveness, efficiency gaps, and operability at commercial scale remain real barriers. Companies that can combine cost discipline, bankability, and execution excellence will define the next era of grid infrastructure, and we need it sooner rather than later. As featured in ESS News. What's your take? Email us at hello@camelotenergygroup.com for any questions! Raafe Khan < Back Back

Aug 15, 2024 Solar Availability Series Part 1 Welcome to the first of Camelot’s series on solar availability, which is an appropriately-hot topic as the industry continues to mature. We’ll start with a bit of background on the current state of industry assumptions, and plan to cover other topics such as the not-so-simple task of calculating and reporting downtime, ways of maximizing availabilities, and Camelot’s stance as an IE. Thank you for joining us! Why we Care Accurate long-term energy yield analyses (EYAs) are key to understanding revenues for solar projects, and a fraction of a percentage point in underperformance vs these models can have a notable impact on a large project’s financials. For this reason, many folks in the industry are scrutinizing their EYA practices and performing much-needed validations to identify potential gaps in their modeling, but more often than not they exclude the impacts of downtime from their comparisons. This is for good reason. If pure model performance is most important to us, unexpected downtime events can skew their validation results. However, as the industry matures and more data becomes available to us, we find ourselves in a position where we can and should start scrutinizing our downtime assumptions as much as we do our other assumptions; a fraction of a percentage point in additional downtime has the same impact on a project’s financials as more traditionally-scrutinized underperformance. Let’s talk about the current state of the industry’s expectations and how we might improve them, since every little advancement can have a notable impact. A Bit of Background Availability is a measure of lost generation potential due to outages at a project; it answers the question of “is our system operating when it aught to be?” An availability of 100% at any given time means everything is operating when it should, whereas an availability of 0% means the entire site is offline. At an operating project, availability is aggregated and reported into monthly reports, which are then aggregated into annual availability numbers and compared to expected annual downtime levels. The most impactful sources of downtime come from major component failures such as from inverters, which put entire swaths of a system offline at the same time. We will dive into how availabilities are calculated, reported, and maximized in Part 2 of this series. Current State of Availability Assumptions: You Know What Happens When You Assume Several years ago, the industry didn’t have the kind of established history needed to accurately predict or validate what long-term average availabilities will be at newly-proposed solar projects. Engineers with experience with the sites might assume that entire sites would be offline for the equivalent of about 3-5 days per year, independent of how long they have been operating, leading towards expected availabilities of about 98.5% to 99.2%. For modeling simplicity, most everyone assumed a relatively consistent availability throughout a project’s lifetime. Sometimes engineering judgement turns out near-perfect, and in this case we can’t be all that far off; though as projects became operational, the industry started to question itself. Especially early in new projects’ operational lives, downtime was high and availabilities were lower than expected due to teething issues. Even after the initial startup period, many folks started seeing trends whereby their average availability levels below what they had hoped. Enter the validation: especially over the last year, availability assumptions have taken a seat at the validation table. There have been three IEs who have recently updated their assumptions from looking at real-world measured and reported availabilities at operating projects. ICF led the charge with its performance paper published by kWh Analytics in 2023. DNV and Natural Power followed suit with their own methodology updates in early 2024. Others with access to the data have weighed in as well, from NREL to kWh Analytics. Here, we focus in on the results of the IE validations, each of which took slightly different approaches and used different data sets. The table below summarizes the projects which went into the IEs’ comparisons, and some key comments from their results. Here is a summary of the IE’s post-validation default availability recommendations. As you can see, only DNV makes a distinction between different kinds of projects at this time, though every IE noted that they are open to changing their assumptions based on project-specific data such as operator or technology history. In general, DNV’s analysis used more data and resulted in recommendations which are more clearly tailored to the sites. Interestingly, despite every IE noting lower availabilities early in a project’s life, only DNV adjusted their recommendation to treat the first year differently from other years. No IE has taken a stance on availability changes later in a project’s life yet. Also of note, ICF found that fixed tilt systems showed lower availabilities than tracker systems while DNV found the opposite. From this, it should be clear that we as an industry don’t have all the answers yet, but that there’s hope of converging on more robust, data-backed opinions on future availability projections for solar projects. The industry is ever-evolving, and in some ways this may be a moving target, but we will only get better as more projects come online and we continue to focus on validating our key assumptions with the data. We look forward to expanding on this topic in future articles in the series. In the meantime, for questions and more details about Camelot Energy Group and our own approach to these issues, please reach out at info@camelotenergygroup.com . About Camelot Energy Group is a technical and strategic advisor to owners and investors in clean energy and energy storage projects, programs, and infrastructure. Guided by our core values of courage, empathy, integrity, and service we seek to support the energy needs of a just, sustainable, and equitable future. Our team has experience in supporting 7+GW of solar PV and 10+ GWh of energy storage and offers expertise in technology, codes and standards, engineering, public programs, project finance, installation methods, quality assurance, safety, contract negotiation, and related topics. Our services are tailored to a providing a different kind of consulting experience that emphasizes the humanity of our clients and team members, resulting in a high quality bespoke service, delivered with focus, attention, and purpose. Key services include: -Technical due diligence of projects and technologies -Owner’s representative and engineer support -Strategic planning -Training and coaching -Codes and standards consulting -Contract negotiation and support. < Back Back

Apr 20, 2026 The Container Problem in LFP Long-Duration Storage Will the LDES story for LFP be hamstrung by larger cells trying to sit in 20-foot containers? As we started to chart how cell form factors are evolving, there is an unmistakable artifact: the incremental change in usable system energy is not as much as it used to be, if these cells are to be housed in prototypical 20-foot ISO shipping containers For a typical 0.04 C use-case, we see that from 280 Ah to 314 Ah, the change in system energy is almost 45.80%; however, when we go from 1,175 Ah to 1,300 Ah, the change in system energy is only 10.40%. As OEMs push the limits from 314 Ah to 500 Ah+ form factors, they must also contend with real-estate constraints, especially because of how power and energy are coupled in Lithium-based systems. This tight coupling means cell geometry affects both thermal management footprint and C-rate flexibility. The energy density ceiling imposed by the container is increasingly the binding constraint, not the cell chemistry. We can see from the image below that, at 0.04 C, we're seeing only 287.50 kW per container at 1,300 Ah, assuming we can fit that in a 20-foot container for a typical 1,500 V architecture -looking ahead to 2,000 V architectures, the challenges compound further: higher bus voltages introduce insulation, switching, and safety certification hurdles that could slow adoption for LDES applications specifically. What's your take? Email us at hello@camelotenergygroup.com for any questions! Raafe Khan < Back Back

Feb 10, 2026 Foreign Entity of Concern (FEOC) Regulations for Battery Energy Storage Systems (BESS) Definitions Under §48E, BESS is treated as an ‘Energy Storage Technology’ or EST An EST is defined (by reference to §48 (c) (6) as property that: Receives, stores, and delivers energy for conversion to electricity Has a nameplate capacity ≥ 5 kWh Is not primarily used for transportation Includes thermal energy storage properties BESS qualifies for §48E Clean Electricity Investment Tax Credits if: It is placed in service after December 31, 2024 Construction begins after statutory termination dates It does not include material assistance from a Prohibited Foreign Entity (PFE) if construction begins after December 31, 2025 Determination is based on supplier's tax year at time of cost payments Material Assistance Cost Ratio For BESS eligibility depends on definitions under 7701 (a) (52): Total direct costs include direct material, direct labor cost of Manufactured Products (MPs) and components incorporated into the EST PFE direct costs are the portion attributable to MPS or Manufactured Product Components (MPCs) that are mined, manufactured and produced by a PFE. If MACR is below the applicable threshold, the EST includes material assistance from a PFE and is ineligible The threshold percentage are as follows: 55% in 2026 60% in 2027 65% in 2028 70% in 2029 75& in 2030 and beyond Technical Cost Components For MACR, only MPs and MPCs are included, some examples are: Battery modules Battery packs Battery cells Inverters Power conversion systems Control systems Thermal management systems Steel and iron-based structural components are excluded from MACR unless identified as MPs or MPCs Main power transformers can be ignored However, it is important to note that asset owners must focus only on a discrete number of MPs and MPCs for MACR calculations Tracking Methodologies Notice 2026-15 establishes three tracking methodologies: Individual component tracking , where each MP or MPCs is tracked to specific BESS units De-minimis assignment (10% rule), where each MP or MPCs representing < 10% of total direct costs may be assigned across facilities Averaging for small BESS (<1 MWAC) Must be of same type < 1 MWAC Placed in service same taxable year Taxpayers may average direct costs and PFE production percentage. This is especially relevant for Distributed Generation (DG)BESS portfolios Applicable Safe Harbors Two interim safe harbors apply as of the date of the notice: Identified safe harbor - Use 2023-2025 Safe Harbor Tables (Notice 2025-08) to identify and qualify and quantify MPs/MPCs Cost percentage safe harbor - Use assigned cost percentages instead of actual cost tracking (only if using identification safe harbor) It is important to note that safe harbor is: Not allowed for incremental production rule projects Excluding used property under 80/20 rule from MACR calculations Per Notice 2025-08, a grid-scale BESS is one with a name plate capacity greater than 1 MWh, where as distributed BESS shall have a nameplate capacity less than or equal to 1 MWh Qualified Interconnection Property If BESS includes qualified interconnection property: Separate MACR must be calculated If interconnection property fails MACR,BESS ITC can still be claimed but interconnection costs are excluded from qualified investment Qualified interconnection property could include network upgrade costs paid to the interconnecting utility – the IRS has recommended separate MACR calculations for these network upgrades It is imperative to work in concert with the utilities to determine cost and sourcing of equipment to accurately quantify and qualify an interconnection specific MACR The Risk of not Being Diligent If MACR is overstated, then: 20% accuracy penalty applies 1% understatement threshold instead of10% 6-year statute of limitations of MACR-related deficiencies Supplier misstatements subject to§6695B penalties That said, there is both economic and reputational risk of not being diligent about strategic sourcing The onus of traceability is solely on the developer's shoulders and goes beyond traditional checklists and CAPEX focused decision making Technical Implications Supply chain strategy Track origin of battery cells and modules carefully Avoid PFE-produced battery cells unless MACR remains above threshold Portfolio structuring Consider < 1 MW averaging rule for distributed projects Use the safe harbor cost tables where advantageous Contracting Ensure supplier certifications, but be diligent about reviewing these in detail due to potential penalties at play Avoid licensing arrangements that could trigger ‘effective control’ by PFEs Financial modeling Build MACR analysis into tax equity underwriting Model threshold compliance by construction year Future Guidance The IRS is still working on FEOC, so the current notice is one of many expected in the coming months FEOC also bans tax credits from being claimed on any project or product over a Specified Foreign Entity(SFE) has been effective control by contract Congress wrote into the statute 13 contract clauses that are leading signs of effective control to ensure non-circumvention Granting the rights to use Intellectual Property (IP) belonging to an SFE, or modifying an existing contract, on or after July 4, 2025, is automatically considered to give the SFE effective control and as such automatic disqualification from a tax-credit perspective FEOC explicitly bars any company that is a PFE from claiming federal tax credits The IRS is seeking comments on the current notice up until March 30, 2026 Reach out to us at @ hello.camelotenergygroup.com for any questions! Raafe Khan < Back Back