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

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

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

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

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

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

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

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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. OUR SERVICES At Camelot Energy Group, our services are best defined by our clients’ needs and we approach each engagement by listening to our clients and providing a bespoke solution. With that in mind, our services generally align with the following major activities. If your needs don’t perfectly align with one of these, no worries. These are only general guidelines and you can always contact us. Owner’s Engineering Technical Due Diligence Strategic Advisory Public Program Support Owner’s Engineering (OE) Technical Due Diligence Strategic Advisory Services 01. OWNER'S ENGINEERING (OE) Today’s clean energy asset owner face a rapidly evolving technology landscape, complex technical agreements, supply chain constraints, quality control issues, and schedule risks. At Camelot, we aim to address these challenges and help our clients build more clean energy projects, secure in the knowledge that a team of experts is in their corner ensuring their projects get negotiated, designed, built, and operated to the best possible standards. Our OE clients often ask for our help with: Negotiating supply, EPC, O&M, and other major project agreements Performing technical due diligence on technology and design options Design reviews Project management Commissioning and testing support Field inspections Reporting for financiers and investors Troubleshooting performance challenges Asset management support If you would like to talk to us about your OE needs, please contact us. We look forward to meeting you and learning about your project. 02. TECHNICAL DUE DILIGENCE The market for clean energy transactions is active and growing and projects and portfolios are bought and sold almost daily. Making the choice to invest in a portfolio of greenfield or operating assets, development platform, or new technology can present a great opportunity for savvy investors but there are risks as well. As these bids become more competitive, investors need actionable technical feedback on real-world risks so they can make informed decisions. At Camelot, we have a deep understanding of the M&A process and our team has provided actionable due diligence on everything from energy storage development platforms to large utility scale solar plants and portfolios of C&I projects. Our team evaluates key areas of potential acquisitions, including: Major agreements (EPC, O&M, interconnection, offtake, and supply) Financial models Major technologies Key team members and contractors Energy models Project designs and methods Installation quality Factory QA programs Independent Engineer (IE) reports Camelot and our team members have supported the financing of over $8bn in clean energy assets for private equity, debt, and tax equity financiers, from regional banks to some of the largest financiers in the world. If you think you may need help with technical due diligence on a project, platform, or other investment opportunity, please contact us . If you already have financing and want to make sure your project is well-executed, our Owner’s Engineering services are tailored to provide that peace of mind. OE Technical Due Diligence 03. STRATEGIC ADVISORY SERVICES Many of the world’s most successful investors have identified the clean energy space as ripe for investment and are seeking to successfully enter the market or expand their position to take advantage of the global growth trends. The opportunity is vast but the competition is fierce and wasting valuable time and resources on a bad deal can set you back considerably. Whether the need is to bring your team up to speed on the latest solar and energy storage markets, technologies, and trends or to get help identifying and validating potential M&A targets, our team’s broad industry knowledge, deep relationships, and expertise can help save precious time and avoid the pitfalls of a poor investment choice. Our team provides strategic guidance related to: Leadership team briefings on solar and energy storage market and technology trends Extended trainings and boot camps to get your team up to speed quickly Support for impact investing and energy access Target identification and due diligence Technology roadmap reviews On-call expertise If your team needs help evaluating new market opportunities, please contact us . If you are ready to consider investment in projects or portfolios, you may find our technical due diligence services helpful. STRATEGIC ADVISORY SERVICES

< Back Jacques Cantin, PE Senior Project Manager Jacques Cantin is a Senior Project Manager at Camelot Energy Group with over 13 years of experience delivering renewable energy and energy storage projects. Based in Montreal, he has led utility-scale battery energy storage system (BESS) and wind projects across Canada and the United States, overseeing project development, systems integration, design, construction, and commissioning. Prior to joining Camelot, Jacques managed storage and renewable projects for a battery storage technology provider and a renewable energy developer and founded a technology start-up focused on wind turbine blade de-icing solutions. At Camelot, he manages advisory engagements for developers, asset owners, and investors, providing technical due diligence, market and economic analysis, and owner’s engineering support for solar, storage, and other clean energy assets. Jacques holds a Bachelor of Applied Science in Mechanical Engineering from Université Laval and an Executive MBA from Queen’s University. Jacques.Cantin@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