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

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

May 4, 2026 Midcontinent Independent System Operator [MISO] Executive Summary All zones met resource adequacy requirements across all four seasons Summer price fell 36% YoY from $666.50(2025/26) to $424.30 as new capacity additions (+5.6 GW) outpaced retirements Summer surplus recovered from 2.6 GW to4.6 GW, even as PRMR increased by 2.7 GW RBDC in year 2 performed as designed as evidenced by the fact that all seasons cleared above reliability targets. Total Offered Capacity Surplus above Initial PRMR grew 2.0 GW YoY despite PRMR rising 2.7 GW, confirming that new additions outpaced both retirements and higher requirements OMS-MISO survey had projected 1.4–6.1 GW range; actual 4.6 GW (total) / 4.7 GW(waterfall chart) fell within range All Seasons Above Target The sloped demand curve priced incremental reliability value above the minimum instead of collapsing to zero — a fundamental improvement over the prior vertical demand curve design N/C effective summer margin: 12.0%; South:9.7%. Zonal Pricing Dynamics N/C (Z1–Z7): $424.30. South Z8 & Z10:$384.10. South Z9: $412.10 (binding LCR needed more local capacity) Fall, Winter, Spring cleared at uniform system-wide prices No transmission congestion binding outside summer was observed LRZ 9 cleared at $412.10, a $28/MW-day premium over the rest of the South because it faced a binding Local Clearing Requirement, not just a PRMR shortfall This signals insufficient locally deliverable capacity and is a developer siting signal Wind and Solar are Growing But Concerns Mount in the Winter Solar is now 8.6% of summer cleared SAC Accreditation: 50% for Summer/Fall/Spring,5% for Winter. The 5% winter cap is the binding seasonal constraint - solar contributes only 0.8 GW in winter vs 12.2 GW in the summer Wind summer ELCC fell from 20.8% to 18.2%per the LOLE study - a methodology-driven decline, not a fleet reduction. Wind remains critical in winter (7.0% of winter SAC vs. 3.9% summer), filling the gap left by Solar's 5% winter accreditation. Load Growth Summer CPF rose from 122.6 GW (2025) to125.1 GW (2026) - the largest single-year jump in the dataset. PRM held flat at 7.9%; the full 2.5 GW CPF rise translated directly into a 4.8 GW increase in Final PRMR. Member submissions escalated across each survey cycle. High scenario: +7 GW by 2030(2.1% CAGR). Low: +5.5 GW (0.9% CAGR).2025 summer peak was 121 GW. Drivers: data centers, re-shore manufacturing, electrification. Without accelerating additions, 2027/28 risks scarcity-level pricing . Resource Mix Winter PRMR is 6.6 GW (4.8%) below summer. Solar's 5% winter accreditation drops its contribution from 12.2 GW(summer) to 0.8 GW (winter). Gas rises from 38.9% to 41.8% of cleared SAC Coal/Nuclear/Hydro/Oil combined has fallen30% since Summer 2016. Batteries cleared 893.8 MW in summer,870.4 MW in winter. Year-over-year trend:~50 MW (2024/25) → ~500 MW (2025/26) →893.8 MW (2026/27). Summer capacity revenue: $424.30/MW-day × 92 days × 0.95 ≈$37,084/MW-year ($37.08/kW-year). Updated GVTC hourly-discharge methodology in effect for 2026/27. Price Relief, But Still Elevated Annualized prices fell from ~$217/MW-day(2025/26) to $126.19/MW-day (2026/27 N/C) a~42% decline: 2022/23: ~$17/MW-day 2023/24: ~$6/MW-day 2024/25: ~$8/MW-day 2025/26: ~$217/MW-day ← spike 2026/27: $126.19/MW-day ← relief Still ~15x above the 2023-2025 average LSEs and retail customers will see meaningful relief but no return to pre-2025norms CONE Still Far Above Clearing Summer cleared at $424.30 vs. N/C seasonal CONE of $1,453.99/MW-day (29.2%). South CONE: $1,348.59. Annual CONE by zone:$123,250–$142,970/MW-yr New dispatchable thermal cannot be financed on capacity revenue alone Bilateral contracts and ERAS fast-track approvals remain essential ~92% of load was self-supplied or bilaterally contracted before the auction. Only 11,305.4MW of non-self-scheduled capacity cleared in summer out of 142,374.3 MW total committed Direct PRA price exposure is limited but not zero — particularly for retail-choice customers in IL, MI, OH, and other competitive states. Advantage BESSt Solar cleared 12.2 GW in summer but only 0.8 GW in winter (5% accreditation vs. 50%). Summer/winter accreditation gap creates a 15:1 capacity value imbalance. Hybrid solar + BESS structures are commercially advantaged. Future DLOL-based accreditation (in development) may shift these values At $424.30/MW-day × 92 summer days × 0.95 (four-hour credit) = $37,084/MW-year ($37.08/kW-year) in summer capacity revenue alone. Combined with energy arbitrage and ancillary services, this increasingly anchors BESS project economics DR cleared 9,099.5 MW in summer (up from 9,004.4MW) and 7,789.6 MW in winter. Cleared Load Modifying Resources (including BTMG) total 9.1 GW in summer, 7.7 GW in winter MISO's tightened DR compliance means that performance tests will be required, not mock drills. This raises the bar but rewards credible programs 2026 PRA RDBC Offer Curves Things to Watch Thank you for Reading! Kindly contact us 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

Jan 15, 2025 MA SMART Part 1 Massachusetts continues to establish itself as a leader in state-level clean energy programs, and Camelot is staying closely aligned on the latest developments in the region. Developers and other players take note: Through the Solar Massachusetts Renewable Target (SMART) Program and the Clean Peak Energy Standard, the state has introduced dynamic frameworks designed to accelerate renewable energy adoption while addressing grid reliability and peak demand challenges. Here, in part 1 of our two-part series on the Massachusetts programs, we’ll set the scene with what you need to know about the programs, and will dive more deeply into the key financial implications in part 2. Massachusetts SMART Program Overview The Solar Massachusetts Renewable Target (SMART) Program is a pioneering initiative aimed at promoting solar energy adoption across the state. Managed by the Massachusetts Department of Energy Resources (DOER), the program provides long-term incentives for solar photovoltaic (PV) projects, encouraging residential, commercial and small utility scale installations up to 5MW AC. Here’s an in-depth look at its objectives, structure, and benefits. The SMART program is a feed-in-tariff program that assigns a unique energy rate to different qualifying solar projects based on system size, system type, system location, offtaker type, and associated energy storage system size. The SMART program has a total capacity of 3,200 MW AC, which is distributed among Massachusetts' three investor-owned electric distribution companies: National Grid , Eversource Energy , and Unitil . The capacity assigned to each utility is proportional to the number of customers in their service area. Generally, sites serviced by municipally-owned electric utilities are not eligible for the SMART program. Each utility’s allocated capacity is further divided into two categories: one for systems larger than 25kW AC and one for systems smaller than 25kW AC. These categories are then subdivided into 16 "capacity blocks." As SMART applications are approved, these blocks gradually fill up. Once a block is fully subscribed, it is considered at capacity, and the program advances to the next block. The incentive rate for the new block is lower than that of the previous one, declining by 4% each block. Figure 1: Summary of Capacity Blocks as of 1/9/2025. SMART Capacity Block updates are posted at www.masmartsolar.com for each utility company To determine the exact SMART tariff rate that a project is granted, the DOER determines a base compensation rate based on the system size and the current utility capacity block. Then adders are applied based on system location, off-taker type, energy storage and racking (see Figure 1). Similar to the declining capacity blocks, the adders have declining “tranches”, and as each tranche is filled at the state level, the incentive rate declines by 4%. However, the adder rates for the Agricultural, Brownfield, Canopy, Floating and Landfill Adders will be locked in at their Tranche 1 rates for the duration of the SMART program and the adder rate for the Building Mounted Adder will be locked in at the Tranche 2 rate for the duration of the SMART program as modified by order 20-145-B released by the Department of Public Utilities on 12/30/2021. Figure 2: Previous Adder Values Massachusetts DOER SMART Program – Initial Release 2018 *Significant adjustments to this table are proposed in the Straw proposal: Figure 3: Straw proposal for new adders Massachusetts DOER SMART Updates – Straw Proposal 2024 SMART and Energy Storage Under the current SMART regulations, all projects over 500kW must be coupled with an Energy Storage System (ESS).* SMART projects coupled with ESS are provided with an “energy storage adder” that ranges between 0.025 – 0.077 $/kWh. The exact adder value is dependent on the max power output of the ESS and the duration, with the maximum adder being granted to projects with 100% of the max power of the PV system and 6 hours duration and the minimum adder being granted to projects with max 25% of max PV power and 2 hour duration. The incentive of the Energy Storage adder is applied to all power generated by the system, independent of the use case of the ESS. There is a requirement that each year the ESS must be cycled a minimum of 52 times to maintain eligibility for this adder.** * The new straw proposal published 7/29/24 specifies only projects over 1MW AC will require ESS ** The new straw proposal published 7/29/24 increases this requirement to 156 cycles per year and adds the requirement that the ESS is online and able to discharge 85% of the time during summer and winter months. Figure 4: Energy Storage Adder Matrix Massachusetts Clean Peak Energy Program Overview The Massachusetts Clean Peak Energy Standard (CPS) is a first-of-its-kind program designed to encourage the use of clean energy during peak electricity demand periods. Managed by the Massachusetts DOER, the program incentivizes renewable energy systems and energy storage solutions that contribute to grid stability and reduce reliance on fossil fuel-based power during high-demand hours. How the Program Works Clean Peak Energy Certificates (CPECs): Eligible resources earn Clean Peak Energy Certificates (CPECs) by generating or dispatching energy during defined Seasonal Peak Periods and the Actual Monthly System Peak, as specified by the Massachusetts Department of Energy Resources (MA DOER). CPECs can be traded in the market to electricity suppliers required to meet clean peak compliance obligations. Various applicable multipliers align CPEC generation with time periods and resource attributes that have the highest impact. For instance, higher multipliers are assigned for summer and winter months (4x) compared to other season months (1x). The Actual Monthly System Peak is weighted disproportionately to incentivize project owners to optimize performance during the peak hour of a given month, which determines the infrastructure sizing requirements. Hybrid Solar + ESS projects that are enrolled in the SMART program can also participate in the Clean Peak program and generate CPECs. However, these projects are awarded a 0.3 multiplier for all CPECs generated, effectively derating the value of their incentive by 70%. Eligible Resources: Wind turbines with storage. Solar PV systems paired with energy storage. Standalone storage systems charged with renewable energy. Demand response resources that reduce load during peak periods. Figure 5 – Energy Storage Charging Windows for Solar-Based Charging Hours Defined Peak Periods: Peak hours are established seasonally to reflect times of highest grid demand. These periods typically occur during late afternoon to early evening hour Figure 6 – Clean Peak Season (CPS) Windows Market-Driven Prices: The value of CPECs fluctuates based on market supply and demand, providing financial incentives for participating resources. Things To Note CPEC Revenues CPEC revenues are designed to incentivize clean energy generation during peak demand periods and can apply to projects that include solar paired with energy storage systems (solar + storage), as these systems are particularly effective at delivering energy during peak periods. Standalone solar projects can still qualify for CPEC revenues, but their ability to maximize these revenues is typically limited compared to solar-plus-storage systems, which offers greater flexibility in aligning energy delivery with peak periods because storage enhances the ability to participate in the Clean Peak Standard (CPS) program. By storing solar energy and dispatching it during peak demand hours, hybrid systems can generate additional CPEC revenues, making them a financially attractive option. ACP Rate Changes The DOER has implemented significant updates to the Alternative Compliance Payment (ACP) rate as part of its emergency rulemaking. The ACP rate will remain at $45/MWh through Compliance Year 2025. However, 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 through 2050. This marks a major departure from the original regulations, which planned for a declining ACP rate, dropping to $4.96 by the end of the policy period. While the higher ACP rate is expected to boost market prices, there is still a risk of steep price drops if surpluses exceed the banking limits of load-serving entities. Figure 7 – CPS Alternative Compliance Payment (ACP) Rates Near-Term Resource Multiplier (NTRM) DOER has also introduced a new NTRM under the CPS. The NTRM will provide a 2x multiplier on CPECs for up to 50 MW of qualified energy storage systems for a duration of 10 years. To qualify, the QESS must be a standalone, front-of-the-meter system interconnected to the distribution system, with a commercial operation date between January 1, 2019, and January 1, 2027. Additionally, it must not have received a Statement of Qualification before January 1, 2025, or the Distribution Credit Multiplier. Ownership is restricted to prevent any single entity from controlling more than 50% (25 MW) of the program’s capacity. DOER released the NTRM application on January 7, 2025[SS3] . Applications submitted by January 21, 2025, will be prioritized based on interconnection service agreement dates. Any applications received after this deadline will be reviewed on a first-come, first-served basis. These updates aim to encourage the development of energy storage systems while addressing previous concerns about market pricing and resource deployment under the CPS. Conclusions Looking forward, Massachusetts aims to expand and refine the SMART & Clean Peak Program to adapt to emerging technologies and evolving market conditions. By integrating solar energy with battery storage and enhancing equitable access, the program continues to serve as a model for other states aiming to transition to a clean energy future. For those considering solar or hybrid projects in the state, the program offers a valuable opportunity to contribute to sustainability while enjoying financial benefits. Stay tuned for Part 2, where we will discuss the revenue stack for hybrid projects, containing a combination of the SMART Program & Clean Peak Program. If you're interested in assessing solar, energy storage, and/or hybrid projects in ISO-NE’s MA SMART Program, feel free to reach out to us 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

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

Oct 31, 2024 U.S. ISO/RTO Regions The energy storage market, driven in large part by the Inflation Reduction Act, is hot and active, with many developers and investors making new investments and growing their storage portfolios. Unfortunately, overall market growth does not mean low risk for developers and the cost of picking the wrong market, revenue stack, contracting structure, or technology could spell disappointment for investors as they watch others pass them by. Sound and informed guidance on energy storage development is absolutely critical to capitalizing on this important growth area. At Camelot, we provide comprehensive market analyses across all U.S. Independent System Operator (ISO) and Regional Transmission Organization (RTO) regions. Our team analyzes each market’s unique characteristics, helping solar and energy storage developers identify the best opportunities for deploying Battery Energy Storage Systems (BESS) and hybrid projects. Here are some key points for each region: ERCOT (Electric Reliability Council of Texas) ERCOT doesn't have a firm real-time ancillary service market, relying sporadically on Supplemental Ancillary Service Market (SASM) auctions to make up for gaps in day-ahead obligations. However, by 2026, ERCOT aims to roll out a real-time co-optimization system for energy and ancillary services. Moreover, as storage saturates the market and as real-time co-optimization between energy and ancillary services gets implemented, ancillary services prices are expected to decline in the near term. Despite the potential saturation of ancillary services in ERCOT, the ongoing deployment of non-dispatchable renewable energy there, and the potential for new load growth, is helping the Lone Star State retain center stage for energy storage developers. However, many developers that come to Camelot for guidance make the mistake of thinking any Texas ESS project is likely to be successful. In reality, identifying the optimal placement and technology mix means all the difference between a profitable ESS project and one that struggles to pencil. Overall, the Houston Hub faces a lower risk of ERCOT related issues, including curtailment, compared to the South hub, which is likely to experience increasing challenges. CAISO (California Independent System Operator) Energy price volatility in CAISO increased significantly in 2022 and is projected to remain elevated in upcoming years, driven by higher gas prices and concerns over system reliability, creates a strong opportunity for BESS. Gas Pricing: Despite less expensive generation from solar and wind, elevated gas prices, impacted by supply constraints and global market dynamics, contribute to higher electricity prices. The availability of cheap electricity from renewables, combined with relatively expensive electricity from gas turbines during periods of low solar and wind resource, create a strong economic opportunity for energy storage. In addition to daily arbitrage, the combination of renewables generating under long-term fixed price contracts and flexible energy storage assets creates a valuable price hedge against fluctuating natural gas prices. System Reliability: CAISO’s grid faces reliability challenges due to increasing reliance on non-dispatchable renewable energy sources like solar, coupled with aging infrastructure, severe weather, and peak demand spikes, especially during summer heatwaves. BESS can mitigate these issues by providing grid stability, fast-acting reserves, and ancillary services to maintain balance. This growing demand for reliability services, along with capacity payments, offers BESS projects multiple revenue streams and a strategic edge in this volatile market. Moreover, California’s aggressive renewable energy targets make it a prime market for BESS projects. Our market overview highlights CAISO’s resource adequacy and ancillary services market changes, helping you understand how to optimize project returns. SPP (Southwest Power Pool) SPP offers significant wind energy potential and continues to expand its transmission network. The surge in renewable energy within SPP is causing a downturn in electricity prices, especially during periods of strong winds, which places intense financial stress on thermal power sources and underscores the importance of adaptable capacity and presents an opportunity for Long Duration Energy Storage (LDES). Our insights into SPP’s market dynamics focus on strategies to capture ancillary service revenues and enhance renewable energy integration through storage solutions. In addition, our team has demonstrated experience in deploying LDES solutions for BTM and FTM projects, putting us in a position to provide strategic insights in this space. PJM (Pennsylvania-New Jersey-Maryland) Interconnection PJM is undergoing rapid data center expansion, especially in Northern Virginia which has put pressure on the grid, causing congestion and high nodal power prices in the Dominion territory. As one of the largest RTOs, PJM presents a strong market with various revenue streams, including capacity and ancillary services. We provide clients with analysis of PJM’s capacity market changes, ensuring projects align with this highly competitive landscape. MISO (Midcontinent Independent System Operator) MISO is currently experiencing a significant transformation in its energy landscape. This shift is characterized by an accelerated adoption of renewable energy sources, alongside a concurrent phase-out of thermal generation plants. Key drivers behind this transition include elevated prices for natural gas and electricity, legislative actions at federal and state levels, demand from energy off-takers, and increasing pressure from stakeholders. MISO's vast geography and increasing renewable penetration create opportunities for BESS projects. Our team helps you understand the benefits of locating projects near congested nodes to optimize project returns. NYISO (New York Independent System Operator) New York is pioneering ambitious climate policies that prioritize storage development. With the recent update to the Energy Storage Roadmap by the New York PSC, storage deployments are expected to increase by 2030 to achieve 6 GW of energy storage. This includes the procurement of 3 GW of bulk storage through an Index Storage Credit (ISC) mechanism, 1.5 GW of retail (Community/C&I) storage, and 200 MW of residential energy storage through the VDER structure, marking a significant shift towards expanding utility-scale storage in the NYISO market to enhance grid reliability and support renewable energy integration. Our NYISO market overview covers key programs, including the Value Stack and Clean Energy Standard, providing guidance to help you understand program specifics and on to provide you with accurate project revenue estimates. We provided some background on the VDER program to help developers and investors better understand this critical framework, which you can view here . ISO-NE (ISO New England) ISO-NE is currently in the early stages of a major shift in market dynamics, transitioning into a period characterized by rapid renewable energy growth, concurrent retirement of thermal generation facilities, and a surge in storage deployment, all fueled by state policy objectives and incentives for clean energy. ISO-NE faces grid reliability challenges and peak demand concerns, making it ideal for storage solutions. We offer insights on ISO-NE’s capacity market changes and BESS opportunities in this renewable-rich region. With Camelot’s help, developers and investors can make confident investment decisions about target markets, project economics, and navigating the latest policy and regulation challenges. We work across all the major markets and developers rely on our market expertise for everything from negotiating tolling agreements to prioritizing their portfolios of merchant market ESS projects. If you're interested in any of the U.S. ISO/RTO market overviews, feel free to reach out to us at info@camelotenergygroup.com . < Back Back

Nov 11, 2025 ERCOT RTC + B ERCOT’s transition from Operating Reserve Demand Curve (ORDC) scarcity pricing to the new RTC+B framework marks a fundamental shift in how batteries and other resources will earn value in Texas’ evolving ancillary services market. ERCOT’s ORDC scarcity pricing is being replaced with a more balanced, data-driven framework. TB-2 valuations have been trending over the last 6-9 months. The composite TB-2 is up by more than 20% (7-year term, Q1 2027 PIS) According to E3, after the passage of the Budget Reconciliation Bill, the phase out of tax credits for solar and wind result in lower deployments and a roughly $15/MWh increase in average annual energy prices from 2026 to 2035. RTC-B is going to be implemented by the end of the year by retiring ORDC scarcity adder. This means that asset owners must prepare for lower ancillary service revenues, higher arbitrage shared, and upside tied to scarcity frequency post implementation This also required four (4) new telemetry points: Frequency Responsive Capacity High Limit (HFRL in MW) High limit of the resources’ capacity that is frequency responsive Frequency Responsive Capacity Low Limit (LFRL in MW) Frequency Responsive Capacity Factor (FRQF) Maximum amount of total base point provided by the frequency responsive capacity of the resource Inactive Power Augmentation Capacity (PAUG in MW) Power augmentation capacity that is not on-line in HSL. This is used in SCED to determine the portion of the non-spin award that will be provided by power augmentation capacity that is not active and deployed as offline non-spin The new telemetry points are intended to inform Security Constraint Economic Dispatch (SCED) the Frequency Responsive Capacity of the resource to ensure that the Regulation and RRS-PFR awards are within the frequency responsive capacity. There are no frequency responsive capacity limitations when providing Non-Spin and ECRS The new demand curve will increase the ancillary service prices under scarcity conditions; however, we note that the scarcity adder will kick in first for RRS and ECRS before RegUp Currently, the onus is on the QSEs to ensure that Regulation and/or RRS-PFR are not coming from the steamer capacity and preserve sufficient headroom on GTs. ERCOT also enforces real-time and post-hoc compliance checks. The improved telemetry will eliminate this burden on QSEs and ERCOT. In practice, the optimization process ensures that resources are not incentivized by prices to deviate from their awards, i.e., a BESS will receive the same operating profit it would have received from the energy market, making it indifferent to the scheduling of its capacity for energy or ancillaries. For ERCOT Contingency Reserve Service (ECRS) it states that batteries can only qualify to provide a quantity that they can sustain for two consecutive hours. Essentially, a two-hour battery can qualify for up to 100% of its rated power as ECRS in any interval. However, a one-hour battery would only be eligible to provide up to 50% of its rated power as ECRS. However, this is changing…ECRS is transitioning from a 2-hour requirement to a 1-hour requirement. RRS and Regulation are being reduced from 1 hour to 30 minutes. Non-spin remains at 4 hours. Since most batteries in ERCOT are at least one hour in duration, the change in duration requirements for RRS and Regulation has minimal bearing on how much capacity is eligible to qualify to provide each of these services. However, the shift to a 1-hour requirement results in a 29% increase in eligible battery capacity for ECRS. This is because RTC+B shifts ECRS to a 1-hour requirement. A 100 MW / 120 MWh battery that was limited to 60 MW under the 2-hour rule can now offer its full 100 MW. It isn’t actually clear how revenues will be impacted as RTC procures ancillaries in real time. However, according to Modo Energy, using Day-Ahead prices as a proxy, batteries would earn about 14% less (or ~ $66 per MW less) under RTC+B on this high-priced day with this operational profile, assuming all RTC+B awards were made exclusively in the Real-Time Market. The reduced revenues reflect limits from SoC checks and the inability to capture extreme Non-Spin pricing. As ERCOT phases out ORDC scarcity pricing and implements RTC+B, asset owners and operators should expect a new balance of risks and opportunities—reduced reliance on scarcity adders, more precise telemetry requirements, evolving duration thresholds, and real-time procurement dynamics that reshape revenue profiles. While uncertainty remains around long-term impacts, it’s clear that operational flexibility, accurate dispatch data, and strategic bidding will play a larger role than ever in capturing value. Raafe Khan, Shawn Shaw < 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

Jan 14, 2025 New Acquisition Opportunity in ERCOT 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 one hybrid (Solar + BESS) project in ERCOT – a region where many folks have had development and acquisition interests. A few details to highlight: Project located in Reeves County (West Hub) Point of Interconnect PV Capacity is 16.1 MWdc and BESS Capacity is 28.2 MWh (Assumed to be a 2-hour battery with an overbuild). It’s designed to participate in ERCOT as a Settlement-Only Distribution Generator (SODG) with Clip Charge and Energy Arbitrage. Solar PV will employ bifacial modules with single-axis tracker and the BESS equipment will use Li-ion technology. Interconnection is planned with Texas New Mexico Powe Company (TNMP), with a 12.47 kV voltage specification, connected to a substation, which is 0.3 miles from project to Point of interconnect. Key milestones such as the completion of Initial Assessment (IA) studies and Phase I ESA have been achieved for both sites. Due to its location, there are no county requirements for environmental permitting. Given the project size, state permitting requirements are also favorable. Lease agreements for 30+ years have been secured Approx. 70 Acres secured, possibly allowing future additional buildout Anticipated COD in Q4 2025. Camelot has recently performed diligence on, and supported the development of, several projects in ERCOT (“TX 10’s”) and we find that revenues can vary widely based on the specific node, though volatility in the region is moderate and favorable to BESS project economics. The DC-coupled configuration is somewhat unique to the market, allowing clipping capture from the solar side, but making market participation more difficult; In ERCOT, regardless of the coupling configuration, the solar and the BESS systems apply for interconnection separately. 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 good opportunities in an active market. If you are new to the ERCOT market and/or BESS considerations, feel free to check out our relevant articles: www.linkedin.com Ahead of the Curve: How to Choose Forward Curves for BESS Projects Tips For Selecting Optimal Forward Curves for Energy Storage Projects with Mina M. Hanna Last week we introduced why accurate forward curves are critical. www.linkedin.com ERCOT Auxiliary Services for Energy Storage Systems Overview ERCOT purchases ancillary services in the day-ahead market to balance the forthcoming day's electricity supply and demand on the grid and address real-time operational challenges. These services, which can be offered by either generators or consumers, allow for rapid adjustments to the electricity s www.linkedin.com Understanding BESS Augmentation in the Renewable Energy Landscape Modern Battery Energy Storage Systems (BESS) lose available energy capacity as they age and are used to store and discharge energy. As such, many asset owners must carefully consider their approach to maintaining energy capacity throughout the useful life of the BESS. 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. < Back Back

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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