Sep 11, 2024 Solar Availability Series Part 4 Welcome back for Part 4 of Camelot’s series on solar availability. If you’re just joining us for the series, here are some links to parts 1 , 2 , and 3 . We’ve set the groundwork with a summary of the ongoing validation efforts from IEs, and the resulting changes the industry is making to their assumptions. We’ll revisit their reasoning here. We’ve also described how availabilities are calculated and reported, and touched on ways of maximizing availability by minimizing downtime. If you’ve followed along with the last few parts and you’ve been waiting for our own stance as an Independent Engineer (IE), look no further! Thank you for joining us. Re-Setting the Scene Until somewhat recently, the utility-scale solar 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 projects. Engineering judgement said that a relatively simple solar project would see the equivalent of about 3-5 days of total site outages per year, leading to expected availabilities of about 98.5% to 99.2%. For modeling simplicity, most everyone assumed a relatively consistent availability throughout a project’s lifetime. However, 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 with their average availability levels below what they had hoped. Over the last year we have started to see the beginnings of some robust data-backed approaches to redefining availability assumptions, aided by all the new operating data which is available to us. There have been three IEs who have recently updated their assumptions based on aggregated data from the projects they supported. 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. We’d like to highlight a few key findings from this comparison: Every IE relied on data from monthly operating reports produced by the operators, which are rarely independently calculated or verified. As described in part 2 of this series, there is no single, standard way that availabilities are defined or reported across the industry. The conclusions from these studies should be interpreted carefully, especially because the data QC processes have not been explicitly described. DNV’s analysis used more data and resulted in recommendations which are more clearly tailored to the sites. ICF found that fixed tilt systems showed lower availabilities than tracker systems while DNV found the opposite. 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. 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 practice, however, IEs are often reluctant to deviate from their standard assumptions, as this requires going out on a proverbial limb. While that conservatism is understandable, it may be producing unintended consequences. For instance, if an IE will not give “credit” for more robust technology choices or operating strategies, then owners have little incentive to consider any options but those that can be considered “bankable” at the lowest possible cost. This approach penalizes owners for considering better than baseline equipment, spending more on O&M, or otherwise looking for creative solutions to improve availability. The need for more data was a theme repeated by each company, and this will likely ring true for as long as we do this kind of work. Our availability assumptions will need to be updated regularly, just like we update our approaches to Energy Yield Analyses. Camelot’s Recommendations The Camelot team is compiling the data needed to supplement these studies and validate our conclusions, and we welcome the opportunity to work with industry partners on this effort. In the meantime, we base our own recommendations off the meta-study described above and in Part 1. Without further ado, here is our own take on availability projections: Until we have more information, we should not be differentiating between different mounting types . ICF’s and DNV’s observations contradicted each other. It’s likely other factors influenced the analyses, especially the sample sizes and quality of the input data. The factors which can impact downtime should be studied further, which means collecting more data, ensuring its accuracy, and capturing all potentially-relevant project details. In addition to mounting types, the difference between inverter technologies must be studied further as one of the primary sources of downtime observed at operating sites. For instance, the higher availability noted by DNV on smaller fixed-tilt sites than larger fixed-tilt sites may indicate a reliability advantage for string inverters over relatively small sites with central inverters. This would align with our general experience with operating sites but the data to positively confirm this is not yet available in sufficient quantity. The major sources of downtime should be studied and modeled separately . Using an overall system availability as a metric can muddy the waters significantly, especially when trying to tease out the impact of different design decisions on future performance. When performing energy yield analyses for wind energy projects, some IEs will include assumptions for balance of plant availability, grid availability, and turbine availability separately. Not only can this improve our validations (data allowing), but it will improve the way we assess technology tradeoffs at the design stage. Swapping out a more robust system for a less-robust one should impact only the downtime assumption for that system. Camelot recommends the industry work towards a bottom-up availability model based on historical failure/downtime data at the module, tracker, inverter, MV, HV, and BOS levels. These levels correspond with likely failure points within the system and provide a lowest common denominator that can be adjusted during project design to optimize expected availability. Ensuring this approach has buy-in from IEs will provide a financial incentive to specify better equipment and design better sites. Year-1 availability should be modeled separately from later years due to initial startup issues observed in each validation. Nearly all financial models are already set up to account for annually-varying losses, so adjusting our assumptions based on the clear signals we see from the data appears to be a no brainer. The industry should start modeling a ramp-down in availability later in projects’ life, as DNV may have alluded to, because component failure rates impact availability trends. Without more data, it is difficult to say the magnitude of the decreases because of the other factors at play. However, based on our experience modeling availability at other infrastructure projects, Camelot considers it reasonable to model availability as a ramp-down as a project nears the end of its design life. The “bathtub curve” shown below is an Engineering concept which supports this idea. It shows how infant mortality failures likely contributed to the observed availabilities in the first 6-12 months of operation, and highlights the further need for more operational data as projects age. This is applicable to individual components in many physical systems. Aggregated across an entire system and accounting for typical replacements and maintenance, one might expect to see a flatter availability curve, but with some consideration for early- and late-stage failures. We have seen this already with 10-15 year old PV sites, where owners struggle to obtain compatible replacement equipment that can be “dropped in” to replace original equipment onsite. As technology continues evolving quickly, we can expect new module types, inverter technologies, sensing devices, and code requirements to all play a role in the maintainability of PV sites in the late stages of their useful life. Camelot’s Balanced Approach The summary below provides a graphical representation of each IE’s default availability recommendations over time, and includes Camelot’s own recommended defaults (when no other project-specific information is available). We note the following: Camelot’s approach accounts for the size impacts observed by DNV, which appears to be a strong signal in the data, but does not differentiate between technologies until more information is made available supporting the distinction. Much like DNV, Camelot’s recommended availability starts slightly lower in year 1 before reaching steady operations, as is supported by all studies. We recommend modeling availability declines after year 20 based on several factors, including the bathtub curve concept described above, the typical useful life for major components, and our expectation that the impacts of mid-life failures will likely offset by the efficiencies gained from experience during operations. While we see this assumption as a necessary recognition of late-stage wear-out failures, it’s worth noting that its impacts on a financial model are muted by the time value of money. On average, Camelot’s assumptions are less pessimistic than ICF, and strike a balance between the assumptions reported by Natural Power and DNV. Camelot will consider quantitative adjustment to our base availability assumptions for sponsor efforts that materially result in increased reliability, such as: Demonstrating better than average historical availability for project- specific equipment (e.g., inverters) through operational data (as described in item 3 above) Adding incentives to O&M Agreements for increased availability, beyond simply guaranteed levels Purchasing extra spare parts for more vulnerable system components likely to need frequent replacing Investing in predictive analytics and above-market O&M services to reduce the frequency and severity of unplanned maintenance events While these recommendations may be Camelot’s “default” values, as an IE which cares heavily about the accuracy of our projections, we will always consider factors such as operator experience or the relative track record of the technologies deployed at each site. As the saying goes, “show us the data.” Before we close, it is important to underscore an important point. Recent reporting that indicates PV projects are falling short of expected availability is a call to action for all of us. It is a call to action for more data, better analysis, and a deeper understanding of what causes PV systems to underperform. It is, notably, not a call to action for unnuanced conservatism. Simply whacking a few points off availability is, in our view, insufficient to the task of ensuring a better-performing PV fleet and it creates blind spots. We hope our fellow IEs will join us in not simply erring on the side of conservatism but, rather, will continue to advance our knowledge of these issues and build better, and more nuanced models that reward innovation, investment, and effort. We hope you’ve found this series to be helpful, and we welcome the opportunity to partner with any of our readers who would be able to support with future efforts. Although this is the last of our solar availability series for now, we fully intend to revisit the topic in the future. For our storage-oriented audience, you can expect a similar discussion on availability assumptions for BESS technologies in upcoming articles. 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

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

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

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

Jul 7, 2026 Analysts expect rising PPA prices as clean energy tax credits phase out Dive Brief: Ahead of the One Big Beautiful Bill Act’s July 4 deadline for wind and solar projects to commence construction in order to capitalize on the Inflation Reduction Act’s investment and production tax credits, developers have met the occasion and safe-harbored a massive pipeline of projects, industry experts say. Crux, which provides a marketplace for the transfer of tax credits, in February estimated a 170 gigawatt pipeline of safe harbored projects. “So it’s presumably only grown over the past seven months,” Josh Price, Crux’s director of intelligence and research, told ESG Dive sister publication Utility Dive. Price, along with Camelot Energy Group Head of Energy Storage and Emerging Markets Raafe Khan, predicted that as projects are no longer eligible to qualify for IRA tax credits, the price of power purchase agreements for those projects is likely to go up. Dive Insight: “If you don’t have the ITC, you have to make that up with revenue and cost,” Khan told Utility Dive. “There’s not so much that a developer can do on cost as much as they can do to negotiate a PPA rate that is favorable, but that does push forward-looking power pricing to the higher end.” Khan said that Camelot Energy Group analyzed the difference between a tax-advantaged and a non-tax-advantaged solar asset, and found that the example case of a 200 megawatt solar facility with a 30% investment tax credit would need a PPA “in the $40 to $45 per megawatt hour range. But if you’re non-tax advantaged, no ITC basis, then you’re basically pushing mid-to-high $60s.” “That’s a 50% increase in power price alone, and that’s going to put a lot of pressure on utilities and developers,” he said. Price said that in the absence of tax credits, “that missing money has to come from somewhere to make the project pencil, and that will likely be through PPA prices, so really it’s kind of a shift from the taxpayer to the ratepayer to make up that delta.” In the meantime, however, Khan said “a healthy amount of projects” that are tax-advantaged will complete construction and be placed in service between 2028 and 2030. “I do think that solar still has a very bright future,” he said. “We don’t really see any kind of sharp drop-off coming up on Saturday, or really over the next four years,” Price said. “And one of the reasons is this has been projected or telegraphed to developers since at least the passage of [the OBBBA], so a year ago is when a lot of these decisions were made to safe harbor, to meet the construction deadlines.” The One Big Beautiful Bill Act, which President Donald Trump signed into law July 4, 2025, stipulated that wind and solar projects had to commence construction within a year of the law’s enactment to qualify for the IRA’s clean electricity production and investment tax credits, or be subjected to an end of 2027 “placed in service” deadline to be eligible. “If you miss the deadline coming up, it is highly unlikely or improbable that you will be able to get a project in the door and placed in service before December 31 [2027], unless you are just so far along from all the work you’ve done in years past that you are basically at the finish line in terms of interconnection, and that your equipment is in a warehouse just waiting to be delivered,” Khan said. “I think that is very much an outlier, I think that’s more of the exception than the norm.” Looking ahead Chris Girouard, renewable energy tax credit attorney at Bryan Cave Leighton Paisner, said in an email that after July 4, he expects “energy industry participants to focus on their safe harbored projects through the end of the decade and lobby for changes in law that reintroduce tax credits applicable to wind and solar projects.” “To the extent tax credits become available for wind and solar projects that began construction after July 4, 2026, we expect the development of those projects to quickly pick back up,” Girouard said. “Outside of the wind and solar context, we expect that the increased attention in other energy technologies will continue to grow. Specifically, we are already seeing increased interest in battery and nuclear projects.” Bryen Alperin, managing director at Foss & Co, also said he anticipates solar and wind credits possibly being “extended sometime in the next few years.” “There are plenty of safe harbored projects,” Alperin said in an email. “As we get to 2029 to 2030, we may have a shortage of solar and wind projects, but by then we expect to have ramped up volume in other technologies.” Energy storage tax credits were left unscathed by the OBBBA’s cuts to the Inflation Reduction Act, offering batteries a boost, said Price and Khan. “One thing that I feel confident in, is it’ll be a lot of storage,” Price said. “We’ve already seen a lot of storage deployment … Q1 was a record quarter.” Khan said he thinks that industry thinking could even shift from solar-plus-storage to storage-plus-solar to power data centers, “to be able to provide a firm shape to the power output of the facility, so that it can actually match the utility’s load profile or the data center’s load profile much better.” Another challenge posed by the OBBBA was its new foreign entity of concern rules, which have complex provisions and have received limited additional guidance from the U.S. Department of the Treasury so far. Khan said that although FEOC enforcement began at the start of this year, “the rules are still not clear, and everyone’s obviously talking to law firms to try to get a better sense of the lay of the land, and we are dealing with an environment where it almost seems manufactured for confusion.” Girouard said he found the guidance released in February , which offered interim safe harbor guidance for calculating a project or component’s material assistance cost ratio, was “helpful to address market concerns.” “However, the lack of guidance regarding the effective control rules continues to be challenging for the renewable energy industry,” he said. “We, along with almost all of the industry, are hoping that forthcoming guidance from the IRS on those rules is released soon and that the guidance provides a practical approach to complying with the effective control regime.” Raafe Khan < Back Back

< Back Cecilia Gao Project Manager Cecilia Gao is a Project Manager at Camelot Energy Group, with three years of experience in the energy industry. New to Camelot, they’ve joined its Advisory team, supporting private-sector clients with a range of technical services. Their background is in asset management, construction, and procurement across distributed and utility-scale solar as well as district energy. Cecilia was previously at an infrastructure fund, where her responsibilities involved the technical and financial asset management of operating projects, oversight of construction timelines, coordination of tax equity funding processes, and the project management of RFP submissions. Prior to this, they also spent time as a product designer and conducted research on the Arawakan language family in South America and syntax in Bardi, an Australian indigenous language. They are excited to continue working in the renewables space with the Camelot team in the greater hope of building more reliable, efficient means to access energy in the near- and long-term future. In their free time, you can find Cecilia drinking black coffee, strolling around with their cat, reading, trying to line dance, birdwatching, or at the movies. (This year, they're really trying to watch a lot more movies and observe more birds.) Cecilia holds degrees in Cognitive Science and Linguistics from the University of California, Berkeley. Cecilia.Gao@camelotenergygroup.com

< 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

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

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

< Back Bill Coon Head of Construction Bill is Camelot’s Head of Construction and oversees all aspects of solar and storage construction and installation quality. This work includes construction monitoring, field supervision, and QA inspection of clean energy construction projects. Bill has over 20 years in the construction field and prior to joining Camelot oversaw QA and safety for a solar construction company and spent time as a construction project manager, solar inspector, and engineer. Bill has a Bachelor’s Degree in Mechanical Engineering from Syracuse University. Bill also holds Installer, Inspector, Commissioning, and Maintenance certifications from the North American Board of Certified Energy Professionals (NABCEP) and is a licensed electrician. bill.coon@camelotenergygroup.com

< 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 Aaron King, PE Senior Project Engineer Aaron is a Senior Project Engineer at Camelot Energy Group and has over 10 years of experience in the solar and storage industry. Aaron works across Camelot’s Technical Advisory and Owner’s Engineering departments supporting clients on a wide variety of services. He has acted as a project manager and technical lead on different projects and portfolios at all different stages of development from M&A due diligence, design and permitting, construction monitoring, site inspections, testing & commission, and asset management. Aaron started his career designing commercial rooftop systems and solar canopies. Aaron has also worked as a technical PV consultant and owner's engineer with a range of different clients including utilities, property management companies, EPCs, municipalities, state governments, and large universities. Aaron is a licensed Professional Electrical Engineer (Power) in the state of Massachusetts and holds a M.S. in Energy Systems Engineering from Northeastern University and a B.S. in Mechanical Engineering from Johns Hopkins University. aaron.king@camelotenergygroup.com