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< Back Raafe Khan Head of Energy Storage and Emerging Markets Raafe is Camelot's Head of Energy Storage and Emerging Markets at Camelot Energy Group. He brings a great depth of knowledge across the energy storage project lifecycle having held tactical and leadership positions at TATA Power (public utility), Mortenson Construction (EPC), Sunnova Energy Corporation (finance + asset management), Pine Gate Renewables (project development), and Visteon Corporation (product development). His interdisciplinary approach has resulted in over 5 GW of operating projects (wind + solar + storage) and over 25 GWh (storage) across the United States. He is a recipient of several national and international awards, including being a Forbes Under 30 honoree in the field of energy. An ardent advocate for energy access and equity, he is an accredited lecturer for the Battery MBA program and devotes his time to educating stakeholders in the energy storage space about technical and commercial challenges from the cell to a fully functional container system. Raafe has a Bachelor's in Electrical & Electronics Engineering degree from Manipal University and a Master's in Energy Science, Technology & Public Policy from Carnegie Mellon University. raafe.khan@camelotenergygroup.com

Jan 30, 2024 On VDER New York has long been an active market for distributed energy resources (DERs) and community-scale clean energy projects. Camelot has supported numerous community solar projects, as well as a variety of energy storage projects and despite strong policy support for clean energy, the New York market remains one of the most complex for developers and investors. The VDER program was established to simplify and streamline the economics of smaller projects but we still find that many developers struggle with some of the nuances. In our due diligence reviews of VDER projects, we typically find a few common points of discussion: How to project some revenue streams forward past the end of VDER value streams like LSRV and DRV Forecast and assumptions for ICAP revenues Coincidence of energy arbitrage and DRV time periods Approach to modeling charging costs When modeling the revenues for purely merchant projects, Camelot uses a sophisticated toolset including an optimized dispatch model but projects with significant programmatic revenues, such as NY VDER projects, often require a more customized approach to validating revenue streams and financial model inputs. Below, we provide some background on the VDER program to help developers and investors better understand this important program. Background on VDER The “Value of Distributed Energy Resources” (VDER) program, implemented by the New York Independent System Operator (NYISO), is a novel pricing mechanism designed to value and compensate distributed energy resources (DERs), including solar, wind, and energy storage systems. This program marks a shift from the traditional net metering system, specifically for certain DERs in NYISO. Unlike its predecessor, VDER is a more intricate system that considers various factors such as the location of the resource, the timing of energy production and storage, as well as the impact on the grid and the environment. This comprehensive approach aims to provide a more precise and potentially more advantageous form of compensation for owners of DERs. The introduction of VDER is a key element in New York's broader strategy to revamp its energy system. It supports the state's efforts to increase the use of renewable energy and reduce greenhouse gas emissions, thereby aligning with state-level policies such as the Reforming the Energy Vision (REV) initiative. This initiative reflects New York's commitment to modernizing its energy infrastructure, promoting sustainable practices, and moving towards a more environmentally conscious energy landscape. Projects under the VDER program can be as large as 5 MW-AC in capacity. The value of these projects is determined by several factors, including their geographical location and the time of day or year they operate. This valuation is determined through the VDER's Value Stack, which is composed of several key components for energy storage projects: Energy Value (LBMP): This component is primarily based on the zonal day-ahead hourly location-based marginal pricing (LBMP) set by NYISO. The LBMP is influenced by several factors: Market Dynamics: The LBMP is affected by the number of generators bidding into the market. This includes the cost of fuels such as natural gas and oil, which play a significant role in setting the price. Renewable Energy Integration: The integration of renewable energy sources like solar and wind power into the grid also affects the LBMP. Typically, a higher presence of these renewable sources tends to drive down energy costs. Demand Fluctuations: Another significant factor is the fluctuation in energy demand, which varies hourly across different zones in NYISO. This demand is particularly sensitive to weather conditions, as the usage of air conditioning and electric heating systems can dramatically increase energy demand. Impact of External Factors: External factors also play a role in shaping LBMP. For instance, in 2019 and 2020, there was a notable decrease in the pricing for capacity and energy. This trend was attributed to an abundance of generating facilities, lower natural gas prices, relatively mild peak demand periods, and a reduction in energy consumption due to the COVID-19 pandemic. Within the VDER framework, a critical element impacting the Energy Value is the Charging Costs, which differ across utility territories and significantly influence net energy revenues. In regions like the ConEd Territory, encompassing New York City and Westchester, these Charging Costs are particularly variable and can change monthly. As a result, net energy revenues in these areas are often higher, but these fluctuations also present a substantial risk by potentially reducing net revenues. To optimize the financial performance of a Battery Energy Storage System (BESS) in these areas, it is essential to identify and utilize periods when charging costs are at their lowest. By charging the BESS during these optimal times, project operators can minimize charging costs and thereby maximize net energy revenues. This strategy is particularly relevant in territories like ConEd, where the impact of these charging costs is more pronounced. Capacity Value (ICAP): Known as Installed Capacity, which is an essential factor in evaluating how effectively a project mitigates energy usage in New York during the most energy-demanding days of the year. This value is closely linked to the NYISO wholesale capacity markets. The rates for ICAP are subject to fluctuations based on several factors: Increase in ICAP Rates: These rates can rise in scenarios where power plants retire or when the State experiences a high annual peak load, indicating increased demand for energy. Decrease in ICAP Rates: Conversely, ICAP rates may decline if there's an excess in power generation, such as when new power plants come online, or if the annual peak load is lower than expected, indicating a surplus in energy availability. ICAP Alt 3 rates change monthly and vary based on NYISO Load Zones. For standalone energy storage projects, the only applicable ICAP payout option is known as Alternative 3 (Alt 3). Under Alt 3, project compensation is calculated and awarded each month throughout the year. This is based on the energy injections from the peak hour of the previous summer, which are then multiplied by the monthly ICAP Alt 3 rate, expressed in dollars per kilowatt ($/kW). This approach ensures that the compensation is reflective of the actual contribution of the project to reducing peak demand, thus aligning with the core objective of ICAP in the VDER framework. Demand Reduction Value (DRV): This aspect of the Value Stack quantifies the impact of DERs on reducing the need for future grid upgrades by utilities. This value is essentially determined by assessing how much a DER project can lessen the necessity for utilities to enhance their distribution networks to handle new peak load demands. The DRV value and is locked in for 10 years and Based on Several Factors: These rates are derived from the utilities' estimated costs associated with upgrading their distribution networks to accommodate increasing peak loads. Decrease in DRV Rates: Peaks can be lowered by factors such as enhanced energy efficiency measures and declining populations. These developments could lead to a reduction in DRV rates. Increase in DRV Rates: Conversely, factors that contribute to higher peak loads, such as population growth and increased electric consumption during peak times (e.g., due to the adoption of heat pumps and electric vehicles), can lead to an increase in DRV rates. Compensation and Performance: The compensation for the DRV value is closely tied to the performance of the BESS during a predefined DRV Window. The DRV value, expressed in $/kW-yr, is calculated with the assumption that the BESS is capable of discharging at its full capacity during all the hours within the DRV Window. Variation by Utility and Region: It's important to note that both the DRV Window and the associated value can vary depending on the specific utility and the region in question. This variation reflects the differing needs and characteristics of each utility's grid and the regional differences in peak load patterns. Therefore, in the VDER framework, the DRV is a dynamic component that reflects the evolving landscape of electricity demand and supply, as well as the regional characteristics of utility grids. It plays a vital role in incentivizing DER projects that can effectively reduce the need for costly grid upgrades. Locational System Relief Value (LSRV): This value recognizes the additional benefits DERs can provide to the grid in specific utility-designated locations. Here are the key aspects of the LSRV: Project Location Requirements: To qualify for LSRV, a project must be situated in a utility-specified substation or location. Some projects might also be eligible for a Location Adder, which provides additional incentives for being in specific areas deemed crucial for grid support. Availability in Designated Locations: LSRV is accessible only in certain areas designated by utilities where DERs can offer extra benefits to the electrical grid. These areas are typically identified based on their potential for grid relief or congestion reduction. Capacity Limitations: Each designated location for LSRV has a finite amount of capacity available, measured in megawatts (MW). This means that there's a limit to the amount of DER capacity that can qualify for LSRV benefits in any given area. Minimum Call Events: Each utility is required to have a minimum of 10 call events per year. These events are opportunities for DERs to demonstrate their capacity to provide grid relief. Advance Notice: A notice of 21 hours prior will be given for these call events, and they are scheduled to occur during the DRV window. Duration of Calls: The duration of these calls will range from 1 to 4 hours. Compensation Structure: Compensation for participating in these call events is based on the lowest hourly kilowatt (kW) injection during a call window. This method ensures that DERs are rewarded based on their actual contribution to grid relief during these critical periods. The LSRV is thus an integral part of the VDER framework, incentivizing projects that are strategically located to provide maximum benefits to the grid. Through this component, the VDER program aims to encourage the deployment of DERs in areas where they can significantly contribute to grid stability and efficiency. Conclusions To conclude, each of these components plays a role in determining the overall worth of an energy storage project within NYISO’s VDER framework, reflecting its multifaceted approach to valuing DERs. If you're interested in evaluating energy storage projects in NYISO’s VDER Program, don't hesitate to reach out and say hello at info@camelotenergygroup.com . < Back Back

< Back Nimisha Shah Associate Analyst Nimisha Shah is an Associate Analyst at Camelot Energy Group, where she focuses on researching energy markets, analyzing industry trends, and building analytical models that help support strategic and clean energy decisions. Her work involves translating complex financial, operational, and market data into clear insights that guide market positioning, business strategy, and decision-making within the evolving energy sector. She is particularly interested in how data and analytics can drive more informed and sustainable energy solutions in a rapidly changing industry. She recently earned her Master’s in Business Analytics from University of Massachusetts Amherst and holds a Bachelor’s degree in Financial Management from United States International University Africa. Her background in analytics and finance allows her to approach energy markets with both a strategic and data-driven perspective. Outside of work, she enjoys spending time in nature, exploring new food spots, and experiencing different cultures through travel and cuisine. Growing up in Nairobi gave her a strong appreciation for staying connected to nature and finding balance outside of work. nimisha.shah@camelotenergygroup.com

Apr 27, 2026 Round-Trip Efficiency Is Not a Spec Sheet Number - It's a System Behavior Under Load When we started looking at the data from ERCOT more closely, we couldn't help but notice that the AC RTE across the fleet is in the low-80s or high 70s, underscoring that RTE isn't a fixed property - it's an operating point. Here's what actually determines it: Cell/Module/Pack: I²R losses scale quadratically with current — high C-rate dispatch is inherently less efficient Internal resistance rises with decreasing temperature and SOH degradation Efficiency varies non-monotonically across SOC; mid-SOC operation generally minimizes losses Power Conversion System (PCS): Inverter efficiency is load-dependent — partial load (frequency regulation) can drop well below 90%; high load (energy arbitrage) approaches 97–98% Switching losses scale linearly with power; conduction losses scale quadratically — distinct mechanisms, distinct mitigation strategies Reactive power dispatch increases apparent power through the PCS without contributing to metered real energy output — a direct RTE penaltyFixed standby draw amortizes poorly over short or infrequent cycles Thermal Management: HVAC auxiliary load is a direct RTE deduction, highly climate- and architecture-dependent, and routinely underestimated in project models Liquid cooling typically carries a lower parasitic load than air-cooled equivalents while providing tighter thermal control Balance of Plant: Transformer no-load (core) losses are present even at zero throughput — continuous and unavoidable Conductor losses, site auxiliaries (BMS, EMS, SCADA, fire suppression) add a persistent baseline draw often excluded from headline RTE figures Dispatch Profile: RTE is path-dependent: same energy, different C-rate profiles → different losses Low average utilization (peakers, ancillary services) amplifies the relative weight of standby and self-discharge losses Cell-terminal, DC-meter, and AC-meter RTE can differ materially on identical hardware. This single variable explains most vendor datasheet discrepancies. A quoted AC RTE without a defined C-rate, SOC window, ambient temperature, dispatch profile, and metering boundary is a marketing number. What assumptions do you see most often buried in BESS efficiency specs? Email us at hello@camelotenergygroup.com for any questions! Raafe Khan < 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

Mar 14, 2025 New Acquisition Opportunity in ISO-NE 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 this opportunity with our network. It’s for a portfolio of three hybrid (Solar + BESS) project in ISO-NE, a region where many folks have had development and acquisition interests in the MA SMART + Clean peak programs. A few details to highlight: This portfolio comprises three hybrid projects totaling 15 MW of solar + 6.72 MW of BESS , available for sale in Massachusetts, USA . Each project is for sale at the Notice to Proceed (NTP) stage, with land, permits, and interconnection already secured . The projects are expected to achieve Commercial Operation Date (COD) between Q3 and Q4 of 2026 . They participate in the MA SMART and Clean Peak programs , with potential eligibility under MA SMART 3.0 . The projects qualify for the 30% federal Investment Tax Credit (ITC) and offer strong revenue potential through offtake strategies and ancillary services in ISO-NE . Offers are welcome for the entire portfolio or individual projects , with transaction closing anticipated in Q2 2025 . Camelot has recently performed diligence on, and supported the development of, several projects in MA SMART + Clean Peak Programs and we find that revenues can vary widely based on the revenue stack, BESS system sizing, and offtake strategy. Similar hybrid projects present a great opportunity and favorable economics, especially with the significant adjustments made to the adders proposed in the Massachusetts Department of Energy Resources (MA DOER) straw proposal. This is in addition to the changes made to the Alternative Compliance Payment (ACP) rate, where starting in 2026, the rate will increase to $65/MWh and stay at this level until 2032. After 2032, the ACP will return to $45/MWh, where it will remain until 2050. Camelot also has recent data on CAPEX and OPEX applicable to the region and can perform a wholistic economic analysis of the projects to verify the seller’s assumptions. Overall, depending on the quality of the development of course, this could be a good opportunity in an active market. If you are new to the MA SMART + Clean Peak Programs, we encourage you to to check out our relevant articles: Massachusetts SMART and Clean Peak Overview MA SMART Part 2: Key Financial Implications for Hybrid Systems If you are interested, we would be glad to put you in touch with our friends at Enerdatics who are tracking the deal and, of course, if you decide to pursue and need any help on the due diligence side of things, please reach out to Taylor Parsons or Shawn Shaw, PE . The Enerdatics team will also be at #Infocast2025 next week and will have other exclusive deals and insights to share. Be sure to reach out to Mohit Kaul or Kshitij N R to connect! < Back Back

< Back Michelle Aguirre Project Manager Michelle Aguirre is a Project Manager with over 4 years of experience in managing engineering projects. Michelle has expertise in electrical safety, quality assurance, technical report writing, and project management. Michelle has supported with Technical Advisory, Owner’s Engineering, and Supply Chain services on commercial to utility-scale PV and BESS projects with construction monitoring, technology reviews, and managing the quality assurance and traceability of major equipment. Prior to joining Camelot, Michelle was a Product Safety Engineer at TUV SUD. Michelle is a registered Engineer-in-Training in the state of California and holds a B.S. in Environmental Engineering from the University of California-San Diego. She is actively pursuing the NABCEP PV Installation Professional certification. michelle.aguirre@camelotenergygroup.com

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

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

Aug 8, 2025 Camelot Unpacks UL 9540 – Part 1 At Camelot, reviewing the UL Listing status of battery energy storage systems (BESS) for the projects we are overseeing as an Owner’s Engineer (OE) or Independent Engineer (IE) is something our team considers a good starting place in the due diligence process. This Listing is so foundational to a successful and code-compliant BESS project that we often take it for granted that everyone understands what this important Standard entails.   Unfortunately, there is a great deal of misunderstanding about the UL 9540 Listing process, even among some engineers who are otherwise pretty familiar with BESS technologies. Missing a step in verifying the proper UL listing of the BESS on a project can have large implications. For instance, an astute authority having jurisdiction (AHJ) that notices your BESS is not properly Listed may find it is not code-compliant, causing significant delays in permitting and significant costs in addressing deficiencies with the BESS manufacturer. Moreover, a UL 9540 Listing represents the successful completion of a battery (we could not resist, of course) of tests related to safety, reliability, and performance.   Understanding Standards Most folks involved in BESS projects think they know what a Standard is, as it seems pretty self-explanatory, right? Perhaps, but once you move beyond the surface level and try to parse the difference between a “Listed”, “Certified”, and “Recognized” product, it can quickly get confusing. So, let’s address a few common misconceptions.   Misconception 1: Projects Have to Comply with Standards The rollout of new standards, like NFPA 855 and UL 9540, have undoubtedly made BESS projects safer. However, complying with these Standards is not required. Organizations like NFPA or UL have no legal authority to provide, or deny, any project a permit. Permits are issued, rather, based on Codes (e.g., Electrical Code, Building Code, Fire Code) and if the Code for your project’s jurisdiction does not incorporate one of these Standards, then the AHJ may not be able to enforce the requirement. This can happen, for instance, when a local Code has not been updated recently enough to incorporate the latest versions of relevant Standards. So, unless the Code references a particular Standard, the project does not have to comply with the Standard, at least from a permitting perspective. Fortunately, many savvy asset owners have developed their own BESS technical criteria. While these criteria are unrelated to permitting, they can be used as a condition of financing. In this way, the investment community can drive better and safer installations by holding developers to the highest current Standards (literally). Misconception 2: Standards Represent the Gold Standard of Safety and Quality Given all the time taken, and the expertise of the dozens of industry experts applied, in crafting Standards it is natural to assume that each one represents the pinnacle of current thinking in design, safety, and quality. Not so. It is best to think of a Standard as the lowest common denominator that a bunch of technical folks with often-competing priorities can agree on. Anyone that has ever got more than one engineer in a room to talk about BESS likely knows that we can be an opinionated bunch, so imagine what a room with fifty engineers is like when coming up with a new technical Standard. The results are incredible acts of service to the industry, but they are only a starting place. Complying with Standards should be a bare minimum, not a stretch goal.   Misconception 3: A BESS can “Pass” or be Listed to UL 9540A Most folks understand a Standard as something that can be “passed” or “failed”. This is an understandable interpretation, as it applies to everything from everyday household appliances to BESS equipment. Unfortunately, UL 9540A is a little different. UL 9540A is actually a testing Standard that describes how a testing laboratory is to initiate and measure the impacts of thermal runaway . In completing the tests, it is literally impossible to not destroy the BESS (/ the BESS is intentionally destroyed). If thermal runaway is not initiated through one initiation method (e.g., heating), then the test continues using other methods until thermal runaway occurs (e.g., nail penetration, overcharging). There are non-lithium-ion BESS that are not subject to thermal runaway but even these do not “pass”. Instead, at each level of testing, a higher level of testing is required unless the test results fall within a particular range . For example, if a cell is tested and does not exhibit thermal runaway, it is not required to test at the module or unit level.   Misconception 4: UL 9540 Replaces Other Battery Standards In fact, UL 9540 is carefully crafted to build on other key standards, not replace them. Though many spec sheets will list UL 9540 alongside UL 1973 or UL 1741, compliance with UL 9540 already includes many of these relevant equipment-specific Standards , such as: UL 1973 for battery cells and modules UL 1741 for inverters (such as in AC block BESS products) UL 9540A for testing thermal runaway propagation risks   Wrapping Up Part 1 Misunderstandings about UL 9540 aren’t just academic - they can cause costly delays, strained relationships with AHJs, and headaches during financing or commissioning. Clearing up the myths is the first step, but knowing exactly what UL 9540 covers, when it’s required, and how to navigate the Listing or Field Listing process is where the real project-saving insight comes in. In Part 2, we’ll take that next step: unpacking the key requirements baked into UL 9540, explaining how they connect to other Codes and Standards, and clarifying the often-misunderstood Field Listing process. If Part 1 was about avoiding the traps, Part 2 is about charting the course to a compliant, bankable BESS installation. < Back Back

Aug 23, 2024 Solar Availability Series Part 2 Welcome back for Part 2 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, Part 1 can be found here , and it includes some background on the current state of industry assumptions. Today we’ll cover the not-so-simple task of calculating and reporting downtime, along with some implications. Subsequent parts will describe ways of maximizing availabilities and Camelot’s official stance as an IE. Thank you for joining us! Introduction As expressed in Part 1 , availability is a way of quantifying lost generation potential due to outages; it measures whether a component or system is operating when it ought 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 component or system is offline. The plot below illustrates a case where the entire site stopped producing power and was restored the following day. There will be more on this figure later. SCADA Data Collected at a Utility-Scale Solar Project Over Two Summer Days To better summarize the operations at a project based on high-resolution data collected at a site, production and availability data are typically aggregated and reported into monthly operating reports (MORs) which are shared with key stakeholders on a project. Monthly numbers are also aggregated into quarterly and annual reports. Because there is typically some seasonal variation in downtime, most folks will refer to annual availability numbers when benchmarking against expectations, and so when we talk about availability assumptions, we are referring to annual averages . A Deeper Dive Into Metrics The simplest but less useful measure of availability is time-based. It’s calculated as Uptime/(Uptime+Downtime) , so it only considers the time it takes to bring the system back online over the period. However, the most useful measure of availability in most contexts is energy-based . It uses an estimate of the energy lost during the period, and is calculated as Actual Production/(Actual Production+Lost Production) . We care more about lost production than anything; when building out a financial model, we multiply pre-downtime production by the assumed availability to arrive at post-downtime production, so we want to use energy-based availability if possible. This is often why, despite PVSYST’s ability to model downtime, the loss factor is most commonly applied outside of PVSYST; the software interprets the loss as time-based and will apply random downtime throughout the modeled year, resulting in an unintended energy-based loss. Time-based availabilities are not well suited for financial modeling, and we recommend time-based metrics only be used if they are defined and used in O&M contracts, as we’ll touch on below. How are uptime, downtime, actual production, and lost production determined? Uptime and downtime are relatively easily defined on a site-level. SCADA systems will typically flag periods when the site or major components are down, and the duration of these events will sum to be the downtime for the site. In cases when a portion of the site is offline, uptime is often weighted by the portion of the affected site (ideally on a production-potential basis). Actual production comes directly from the power meter, typically at the point of interconnect (POI). Calculating lost production usually involves several steps which are all built into the software used to log and report operational data: Determine “expected production” for each timestep based on the energy model for the site and the existing, measured site conditions (eg irradiance). The model should be validated as an accurate representation of the relationship between measured inputs and production. Referring to the plot above, expected production is the red line, which is based primarily on the plane-of-array irradiance (green line). Calculate the energy lost for each timestep, which is represented by the “Δ” in the plot above. Sum energy lost at each timestep across the entire reporting period. The same calculations hold for any reporting period. To calculate an annual availability number based on monthly data, you can sum the monthly time or production values before doing the same math, or take an energy-weighted average of the monthly availability numbers. What about data gaps or QC? Unfortunately, we see data concerns very often at operating sites, and garbage in equals garbage out. Some meters and sensors will have redundancy onsite in case one fails, but if we run into data concerns due to whatever issues arise, all may not be lost. Even in a system-wide SCADA outage or memory failure, some form of data are always being collected or modeled onsite, and inferences can be made. As a couple examples: If an inverter power meter at a site with 5 central inverters starts to fail, but the inverter should still be online, an operator can verify the inverter’s availability using the POI (revenue) meter. The total power at the POI meter minus the power from the other inverters should roughly equal the power from the fifth inverter (“roughly” because of electrical losses and measurement uncertainties, which can generally be determined from operational data anyways). Even if the entire site goes offline for a period of time and no actual measured data is available, besides the power flowing to the grid at the POI, high-resolution meteorological satellite data can be used. Operators can observe the relationship between the solar resource and production during a fully-operational period to fill in the gaps and define expected production. Admittedly, many O&M providers will not go to the effort to fill in data gaps when they occur, which can lead to missing or inaccurate data. This, in turn, can lead to an inaccurate understanding of overall system performance, which in some cases can even impact a project’s valuation: availability is a key factor when reforecasting a project’s future production, and we have seen cases where missing data makes a significant difference in the uncertainty (leading to lower P99s). This is where Technical Advisors such as Camelot Energy Group can help ensure you are working with the most accurate data you can. Not only can availability be calculated based on a fundamentally different basis (time vs energy), but we need to be careful to scrutinize what is included in the definition as well. Until now, we’ve focused on System Availability, but you might find other metrics floating around and serving other purposes. A few common terms and measures are: System Availability - Captures all quantifiable downtime over the entire site for the entire period, with no carveouts. The following is a list of possible synonyms, noting that the definition of every availability metric should be scrutinized because they can be inconsistent: Plant Availability Project Availability Operational Availability Total Availability Overall System Availability (OSA) An inverter fire which caused system-wide availabilities to drop for a significant period of time Component Availability – Captures only the availability of an individual component over a given time. These commonly include inverter availability or module availability , but can be broken into any components, including trackers. Sometimes referred to as Manufacturer Availability . Contractual Availability – Sometimes also referred to as Guaranteed Availability, this metric is the most commonly-confused one of them all. It should be clearly defined in an O&M agreement, and the downtime it includes can vary. The denominator in the calculation is often more complicated than simple “total time” or “total production” during the period, and both parts of the equation can include carveouts for periods which are often deemed outside of the operator’s control. This is the most commonly-reported time-based availability, but we are seeing an increase in contracts which define Contractual Availability on an energy basis. This incentivizes operators to perform maintenance at more optimal (lower resource) times. Balance of System (BOS) Availability – Includes the availability of all components other than the modules and inverters, such as wiring, mounting structures, and monitoring equipment. Sometimes also termed Balance of Plant (BOP) Availability, but as always, the definitions must be scrutinized. Grid Availability – Captures downtime when the grid is not available to accept power generated by the project. This is the most common carveout for contractual availabilities, as it is almost always outside the control of the operator. We hope this moderately deep dive into solar availabilities helps to put the numbers into perspective and emphasize the importance of understanding what metrics you are looking at when evaluating a project’s uptime. We can always go deeper into the topic, and we’d be happy to support with any questions you may have. The next article in this series will cover a number of ways of maximizing availability and improving your metrics. 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

< Back Bill Atkinson, CEM Senior Project Engineer Bill is a Senior Engineer with over 17 years of experience in the renewable energy and energy storage industry. During that time, Bill has worked extensively developing and implementing rigorous quality assurance and inspection processes for clean energy incentive programs and Bill has inspected more than 530MW of PV and energy storage systems. Bill has performed hundreds of design reviews, technology evaluations, major agreement reviews, and site assessments. Bill is a Certified Energy Manager, Certified PV System Inspector, and holds a B.S. in Community and Regional Planning and Sustainable Technology from Appalachian State University. bill.atkinson@camelotenergygroup.com