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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

Oct 30, 2025 NFPA 855 (2026) Taylor Swift dropped her new album, but the NFPA dropped the 2026 edition of 855: Camelot is reviewing the standards and there will be a dedicated post about this in the coming weeks – stay tuned! Please reach out to us if you require guidance on the ensuring your systems are code compliant and you have the best resources to complete fire safety engineering General Scoping: The latest edition has reorganized things which reduce ambiguity and cross references that existed across chapters in prior editions General requirements have been moved into a single chapter; technology specific chapters with tailored rules which should create fewer conflicts and clearer applications during code reviews Large-Scale Fire Testing (LSFT): The latest edition puts a stronger emphasis on LSFT but creates an anchor to UL 9540A. The most significant single change is the introduction of full-scale burn testing with flammable gas ignition. In the short-term, this puts the 2026 NFPA 855 ahead of UL 9540A, as the 4 th edition does not provide a procedure for this gas ignition process. This is expected to be addressed in the upcoming 5 th edition of UL9540A, to be released in March, but in the meantime, specifics of new LSFT procedures are a bit of a gap in the new edition of NFPA 855. Conceptually, the new LSFT is considered an alternative unit-level test, adding to the typical number of UL 9540A tests that need to be reviewed as part of typical due diligence. Engineers, like Camelot, will now need to review cell, module, unit, and LSFT test reports to validate system design and code compliance but, overall, this added testing is expected to result in improved safety. Source: UL For larger, denser designs, the 2026 edition elevates LSFT to an expected component to demonstrate containment, adjacent to unit impacts and realistic configurations (multiple racks, aisle spacing, ceiling effects, heat flux, etc.) Source: Hithium It is important for engineers to budget for real estate when proposing dense BESS layouts with tight clustering. Camelot expects AHJs will ask for both UL 9540A and system-scale LSFT evidence in permitting packages Explosion control: While previous editions allowed owners to comply via either passive (e.g., deflagration panels) or active (e.g., gas detection and ventilation), the 2026 edition will now require manufacturers to use active ventilation measures complying with NFPA 69. Manufacturers may still use passive measures if desired but these, alone, will no longer be compliant with NFPA 855. The new standard also increases the requirements for documentation around explosion control and the rigor of hazard mitigation analyses (HMA). The new edition also provides more specific requirements for supplying backup power to explosion control systems, allowing them to remain operational when grid power is disconnected. Enhanced documentation requirements: The 2026 cycle clarifies HMA expectations (inputs, scenarios, outcomes) and pushes better correlation between detection technologies and mitigation strategies (e.g., clean agent vs water, deflagration prevention vs passive venting). This is a direct response to inconsistent submittals in prior cycles. Camelot expects AHJ to scrutinize HMAs and modeling assumptions, so it is important to be explicit about gas evolution triggers, alarm setpoints, failure modes, fan curves, agent hold times, ventilation rates, fail-safe logic, etc. Owners will need to be ready to work closely with suppliers to provide AHJs with more test data, modeling results, and similar technical information going forward. NFPA 855 also draws a distinction between Emergency Response Plans (ERPs) and Emergency Operations Plans (EOP). Much of this content was previously merged into a single document but going forward, ERPs will focus on firefighter and emergency personnel information, whilst the EOP will provide key information for the owner/operator. The result should be two more targeted and accessible documents replacing a single broad document, but developers will need to plan on refreshing previous templates and some additional time to coordinate separately on these key documents. Technology coverage has been expanded in the 2026 edition which intends to reduce overapplication of Li-specific requirements to chemistries with different risk profiles, like lead-acid, aqueous Nickel, etc. Operations and Maintenance: Since testing expectations have been made explicit, field-based modifications like augmentation may potentially invalidate test representativeness. It is expected that the AHJs will trigger re-evaluations to ensure everything is up to code The latest edition also states that the project owners schedule annual ERP reviews and training for first responders to maintain compliance. This has been the best practice for some time but jurisdictions adopting NFPA 855 will now have grounds to make this a requirement. It is also worth putting this new edition of NFPA 855 into a broader context, as things are moving fast on the ESS codes and standards front. Camelot is closely tracking several related codes and standards efforts, including: NFPA 800 (Battery Safety Code) is a new standard with far more breadth than previous codes, covering all aspects of battery safety from manufacturing and storage to operations and disposal. It goes beyond stationary ESS, as well. The code is still in its first draft, but the Technical Committee is actively working on updates. UL 9540A 5 th Edition: As noted above, the new edition of this critical testing standard will likely provide updated guidance to better address the LSFT requirements put forth in NFPA 855 (2026) and this should be released in March. Camelot’s CEO, Shawn Shaw, is working on an update to the 2022 Energy Storage Systems and the IBC, IFC, IRC, and NEC published by the International Code Council. Stay tuned for more updates and a final publication date soon. Raafe Khan, Shawn Shaw < Back Back

Nov 7, 2024 Part 2: VDER Revenue Stack As discussed in Part 1: VDER Revenue Stack for Standalone Storage Projects , while the Value of Distributed Energy Resources (VDER) Calculator is a freely accessible tool for estimating expected VDER revenues, it can fall short in accurately modeling certain revenue streams. Therefore, when evaluating investments in Battery Energy Storage System (BESS) or hybrid (solar + storage) projects, it’s crucial to supplement this initial analysis with a more detailed revenue forecast that considers additional variables encountered in real-world operations. Like other leading market analytics providers, Camelot uses an optimized dispatch model to project future revenues for BESS and hybrid projects participating in merchant energy and ancillary services markets. However, projects with substantial programmatic revenues—such as NY VDER projects—often require a more customized approach to accurately validate revenue streams and financial model inputs. To address this need, Camelot has developed additional tools and capabilities that seamlessly integrate these programmatic revenue streams with relevant merchant market opportunities. You can find more background on the VDER program here to help developers and investors understand this critical framework. For our analysis, we modeled the revenue stack of a hybrid system with a 5 MWDC solar array and a 5 MW, 4-hour BESS under the VDER program across various utilities. We estimated the Locational System Relief Value (LSRV) manually, while our optimized dispatch model calculated LBMP, ICAP Alt 1, ICAP Alt 2, and DRV values. Additionally, we created four scenarios based on the following configurations: Hybrid Systems – PV Charging Only PV Charging Only (Alt 1) PV Charging Only (Alt 2) Hybrid Systems – PV & Grid Charging PV & Grid Charging (Alt 1) PV & Grid Charging (Alt 2) Key Trends and Insights from the PV Charging Only Results Figure 1 Excerpt from Camelot Q4 2024 NY Market Outlook Report Figure 2 Excerpt from Camelot Q4 2024 NY Market Outlook Report Energy Component (LBMP): The combined energy (LBMP) values from both BESS and solar in PV Charging Only projects are not the lowest among VDER components when compared to standalone BESS projects. This is largely because there are no charging costs—BESS charges from PV rather than the grid. Installed Capacity (ICAP) Value: Capacity prices vary significantly by NYISO load zones, making capacity revenue forecasts challenging due to price volatility across zones. These prices may decline as offshore wind is integrated, which contributes both energy and capacity. ICAP Alt 2 yields higher revenue than ICAP Alt 1 across all zones, primarily due to the rate structure of ICAP Alt 2. Similar to ICAP Alt 3 (applicable only to standalone BESS), ICAP Alt 2 prices have historically been higher, especially in Zone J (NYC – ConEd Group A) and Zone K (PSEG LI). Zone J prices average 3.04 times higher than other zones due to anticipated thermal retirements and land constraints that limit new renewable integration. Demand Reduction Value (DRV): Like standalone BESS projects in areas with 2 PM to 7 PM DRV windows, PV Charging Only projects also achieve strong DRV results as these hours often align with system peak windows. In ConEd Group B (Westchester), projects within the 2 PM to 6 PM DRV window produce significantly higher DRV revenues compared to those in the 2 PM to 7 PM window, as the former aligns more closely with potential peak periods. For instance, DRV revenue in ConEd Group B is 6.36 times higher than the utility average within the 2 PM to 7 PM window and 5.82 times higher than the state average. Locational System Relief Value (LSRV): In Central Hudson’s territory, LSRV does not apply. However, the highest LSRV revenues are seen in ConEd (Zones A to C) and PSEG territories, where LSRV revenues are 2.60 times higher than the state average. Environmental Value: The environmental value remains constant across all utilities and is locked in for 25 years. This revenue stream applies only to PV Charging Only cases in VDER, making these configurations more attractive than PV & Grid Charging due to the additional revenue stream. Key Trends and Insights from the PV and Grid Charging Results Figure 3 Excerpt from Camelot Q4 2024 NY Market Outlook Report Figure 4 Excerpt from Camelot Q4 2024 NY Market Outlook Report Energy Component (LBMP): In PV & Grid Charging projects, the combined energy (LBMP) components from both BESS and solar, including charging costs, are the lowest revenue component when compared to PV Charging Only projects in VDER. This is largely because PV Charging Only projects incur no charging costs, as BESS charges directly from PV rather than the grid. Installed Capacity (ICAP) Value : Capacity prices vary significantly by NYISO load zones, making capacity revenue forecasting challenging due to price volatility across zones. These prices could decrease with the addition of offshore wind, which contributes both energy and capacity. Like PV Charging Only projects, PV & Grid Charging projects see higher revenues under ICAP Alt 2 compared to ICAP Alt 1 across all zones, primarily due to the higher rate structure of ICAP Alt 2. Like ICAP Alt 3, which applies only to standalone BESS projects, ICAP Alt 2 prices have historically been highest in Zone J (NYC – ConEd Group A), followed by Zone K (PSEG LI). Zone J averages 3.06 times higher than other zones, driven by anticipated thermal retirements and land constraints that hinder new renewable integration. Demand Reduction Value (DRV): Similar to standalone BESS projects in regions with 2 PM to 7 PM DRV windows, PV & Grid Charging projects also achieve strong DRV results as these times often align with system peak periods. However, as with PV Charging Only projects, PV & Grid Charging projects in ConEd Group B (Westchester) within the 2 PM to 6 PM DRV window yield much higher DRV revenues than those in the 2 PM to 7 PM window, as the former more closely overlaps with system peaks. For example, DRV revenue in ConEd Group B is 5.95 times higher than the utility average within the 2 PM to 7 PM window and 4.87 times higher than the state average. Locational System Relief Value (LSRV): In the Central Hudson territory, LSRV does not apply. Similar to PV Charging Only projects, the highest LSRV revenues are observed in ConEd (Zones A to C) and PSEG, where LSRV revenues are 2.73 times higher than the state average. Environmental Value: The environmental value applies exclusively to PV Charging Only cases within VDER, making PV & Grid Charging cases less favorable in the VDER revenue stack due to the lack of this additional revenue component. Conclusions The VDER revenue stack significantly diminishes for projects located outside of ConEd and PSEG territories. Although CAPEX and OPEX costs for upstate projects may generally be lower, this advantage is offset by the more lucrative revenue streams available in ConEd and PSEG regions, as highlighted in this article. When calculating these revenue streams, it’s essential to account for the various market nuances specific to the VDER revenue stack, as discussed in Part 1: VDER Revenue Stack for Standalone Storage Projects. While the VDER Value Stack Calculator is a useful tool for preliminary analysis, it may not always provide accurate forward revenue estimates. Our team recommends conducting a more detailed analysis to support the development and financing of energy storage and hybrid projects in New York State. In summary, when comparing the VDER value stack for hybrid projects under ICAP Alt 1 and Alt 2, as well as the PV Charging Only and PV & Grid Charging options, we find that PV Charging Only (Alt 2) projects generate higher revenues than PV & Grid Charging projects. This is primarily due to the Environmental value, which is locked in for 25 years at a fixed rate of $31.03/MWh, and the increased revenue potential that ICAP Alt 2 offers over Alt 1. To accurately assess the benefits of PV Charging Only versus PV & Grid Charging, Camelot can assist you in determining the optimal storage system size to co-locate with your solar system, helping you maximize returns for hybrid projects. If you're interested in assessing energy storage and/or hybrid projects in NYISO’s VDER 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

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

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

< Back Mark Warner Project Manager Mark Warner, a Project Manager at Camelot Energy Group, has over 5 years of experience in the renewable energy development and EPC contractor space. Mark has extensive background in project development, siting, energy analysis, design, construction planning, and permitting for commercial and utility-scale solar projects. Mark holds a Bachelor of Science Degree in Mechanical Engineering Technology from the University of Maine. mark.warner@camelotenergygroup.com

Feb 12, 2025 MA SMART Part 2 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

< 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

< Back Taylor Parsons Director, Technical Advisory Taylor is Camelot’s Director of Technical Advisory, and has over 10 years of experience in the energy industry. His primary focuses have been in technical due diligence, energy modeling, and analytics for solar, wind, and energy storage assets. Taylor has led some of the largest due diligence engagements for M&A on projects, platforms, and portfolios. Prior to joining Camelot, Taylor was a Team Lead and Project Manager in DNV's M&A and Energy Assessment Teams. He also supported the National Renewable Energy Laboratory's Systems Engineering team engineering and analysis for wind turbines. He has a Bachelor’s Degree in Mechanical Engineering from the Colorado School of Mines, and is actively pursuing his Executive MBA in Energy (renewables focus) from the University of Oklahoma. taylor.parsons@camelotenergygroup.com

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

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

Camelot Energy Group is a technical & strategic advisor to owners and investors in clean energy & energy storage projects, programs & infrastructure. We specialise in Solar, Energy Storage, Consulting, Engineering, Batteries, Due Diligence, Energy Access, Strategy, Owner’s Engineering & Advisory. GET IN TOUCH Contact Us Boston, Massachusetts hello@camelotenergygroup.com First Name Last Name Email Phone Leave us a message... Submit Thanks for submitting!