Dec 4, 2025 CAISO Market Operations CAISO Market Refresh CAISO is the second largest renewable energy market by deployment, just marginally behind TX, however, operating in CAISO isn’t trivial – the market works in a few layers, and all required capacity is procured in the DA market However, two additional balancing markets run throughout the day – the Integrated Forward Market (IFM) and the Fifteen Minute Market (FMM) Source: CAISO OASIS Data Integrated Forward Market (IFM): Bidding starts in the IFM the morning before the day starts and all operators submit bids for DA and AS for each operating hour. However, BESS with Resource Adequacy (RA) contracts are required to make bids for every hour Fifteen Minute Market (FMM): Once the day begins, FMM gets to work. Operators must submit bids 75 minutes prior to each operating hour. This is also referred to as the 75-minute lockout period FMM capacity is cleared in 15-minute increments Real-Time Dispatch (RTD): RTD works in 5-minute intervals and CAISO uses this to address sudden system wide issues like outages, demand spikes, etc. FMM awards can be adjusted in both directions in RT, and this can cause uncertainty about the immediate operating hours. It is important to note that assets with firm AS obligations must have 60-minutes of SoC in the IFM and 30-minutes of SoC in the RTM to deliver and avoid penalties. Key Market Mechanisms & Initiatives Extended Day-Ahead Market (EDAM): This is a major ongoing initiative to expand the real-time WEIM into a day-ahead market. Status: The EDAM is scheduled to launch in May 2026, with PacifiCorp and Portland General Electric as initial participants. Stakeholder workshops are ongoing to finalize tariff clarifications and implementation details. Source: U.S Energy Information Administration Flexible Ramping Product (FRP): This market mechanism is designed to manage the significant net load variability caused by high solar and wind integration. Function: It procures capacity to handle forecasted movement and uncertainty in net load (total load minus solar/wind generation) in the real-time market. Performance & Challenges: The CAISO net load can swing more than 20 GW in a single hour. While beneficial for grid stability, the FRP rarely presents consistent, high-value revenue opportunities for most battery energy storage systems (BESS) as prices are often zero due to sufficient available capacity. The Department of Market Monitoring has previously identified implementation errors in the product's demand curve calculations that resulted in under-procurement of upward capacity during critical ramps. FRP addresses real-time variability across the Western grid, with CAISO facing some of the steepest ramps Source: U.S EIA SP15 hosts nearly 75% of CAISO’s battery storage, reflecting where solar growth and ramping needs are most concentrated. This regional buildout plays a major role in shaping real-time flexibility and FRP activity across the grid. As storage scales further, SP15 increasingly influences CAISO’s price formation and operational dynamics. Source: CPUC Master Resource Database Ancillary service prices in SP15 have declined sharply as battery storage has scaled across CAISO. With increased competition, services like RegUp, Spin, and Non-Spin offer far less revenue than previous years. This shift pushes storage operators to rely more on energy arbitrage and real-time market opportunities. Source: CAISO OASIS Data With ancillary service prices declining, energy arbitrage now makes up the largest share of CAISO BESS revenue. Growing solar-driven volatility has increased DA–RT spreads, making arbitrage more valuable. As a result, storage operators rely more on price forecasting and real-time optimization to capture returns. Source: CAISO Special Data TB4 opportunities come from predictable daily price swings in CAISO, where low midday prices encourage charging and high evening prices reward discharging. This spreads-based strategy is a major revenue driver for batteries under tolling agreements. Capturing these spreads consistently requires strong forecasting, SOC planning, and real-time optimization. Source: CAISO OASIS Data California utilities and CCAs are rapidly increasing their TB4-settled procurement, growing from under 2 GW in 2023 to over 3.5 GW by 2025. TB4 contracts shift real-time operational risk from offtakers to independent power producers (IPPs). This structure gives utilities financial certainty while requiring storage operators to manage price volatility and dispatch performance. The growing adoption of TB4 highlights the market’s move toward financially settled performance-driven contracting for BESS. Source: CPUC Fillings 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

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

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

Aug 30, 2024 Solar Availability Series Part 3 Welcome back for Part 3 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, please checkout Part 1 and Part 2 of this series. We’ve set the groundwork with how availabilities are calculated and reported along with the current state of IE assumptions. Today we’ll touch on ways of maximizing availability (minimizing downtime). This topic could be its own series, so we’ll focus on the bigger picture. If you’re curious about Camelot’s stance on availability assumptions as an IE, be on the lookout for future parts in this series. Thank you for joining us! The most impactful sources of downtime come from major component failures such as from inverters, which put entire blocks of a system offline at the same time, although more minor events can still bring smaller portions of the site down. We’ll focus primarily on the most impactful contributors to downtime here. There are two broad, controllable factors which impact availability: The frequency of downtime events , driven by component failure rates and the need for planned maintenance. The quality of the engineering and proactive maintenance is important for this piece; and The duration of downtime events , driven by staffing, readiness of replacements, and other primarily-O&M considerations. Reducing the Frequency and Duration of Downtime Events During Operations Owners and O&M providers and can have a significant impact on both the frequency and duration of downtime events at an operational project once it’s been built. Here are a few recommendations for ensuring success: Follow a Robust O&M Agreement. The O&M agreement should be closely followed during operations, which unfortunately does not always occur. The agreement should be robust and include elements of the items below. More recommendations for O&M agreements are also included in the next section. Predictive Maintenance: Utilize data analytics to predict potential equipment failures before they occur. By analyzing trends and historical data, O&M teams can identify patterns that signal imminent issues, allowing for timely interventions. Sufficient Preventive Maintenance: Schedule regular maintenance based on equipment manufacturers' guidelines and site-specific conditions. This includes checking electrical connections and inspecting mechanical systems such as trackers. Of note, energy-based availabilities can be optimized by scheduling maintenance events during periods of expectedly-low production. The time-based availability metric might be the same, but the smaller energy loss means a higher energy-based availability. Spare Parts Management: Maintain a well-stocked inventory of critical spare parts on-site or at a nearby location. This ensures that replacements can be done swiftly without waiting for parts to be ordered and delivered. Follow manufacturer recommended list and review periodically as components may become less available over time. Strong Vendor Relationships: Collaborate closely with equipment manufacturers and vendors to gain access to the latest updates, best practices, and support services. This can also help in negotiating favorable terms for spare parts and service agreements. Third-Party Audits: Engage third-parties to review the performance of the O&M program periodically. External audits can provide fresh insights and identify areas for improvement that internal teams might overlook. Training: conduct regular staff training and testing to ensure readiness for major component failures and extreme weather events. An inverter fire which caused system-wide availabilities to drop for a significant period of time Reducing the Frequency and Duration of Downtime Events During Development O&M activities may be the most visible contributor to a Project’s operational success, but they are not everything. An ace car mechanic can still see more issues with an old, poorly-built junker than a novice will see with a durable, high-end car. Camelot encourages developers to have a mindset of ensuring long-term operational success, which leads to fewer issues and less-impactful downtime. For this, we offer a few broad suggestions: Environmental Impacts: Consider site suitability at an early stage. Evaluate potential environmental risks such as wildlife interference, extreme wind speeds, natural disasters, and erosion which could affect the project’s operation and maintenance. Durable Components : Select robust inverters, transformers, racking systems, and other components designed to withstand harsh environmental conditions and have low failure rates. This often means evaluating cost tradeoffs for more expensive components. Exceed Codes and Standards: At a minimum, ensure the project complies with all local, regional, and international standards for safety, performance, and environmental impact. Even more importantly, most EPC agreements only require code compliance, and code is not about longevity of the asset, it is about safety. As such, make sure your EPC Agreement reflects materials, methods, and design standards consistent with the planned (and financed) useful life. Access: Ensure the site has adequate access for maintenance personnel, which can impact the duration of downtime events. Make major equipment accessible near site roadways and ensure roads are wide enough to facilitate easy use of cranes and other heavy kit. Design the site to allow for spacing between components so that specialized equipment isn’t required for access and repair. Remote Monitoring Infrastructure : Deploy advanced SCADA (Supervisory Control and Data Acquisition) systems to monitor the performance of the solar farm in real-time. This allows for quick identification of issues before they lead to significant downtime. Contract with Reliable O&M providers : Developers will elect to engage with O&M providers during the later stages of development, and should do their due diligence on prospective providers to ensure they will have the right capabilities. The O&M contract should be comprehensive and include elements of the list in the prior section. A few of the most impactful items include: Availability Guarantees: The agreement should include specific availability targets. These targets set clear expectations for how often the solar plant should be operational, and should be tied to incentives to increase the chance of compliance and incentivize high availability. Maintenance Schedules and Protocols , including preventative maintenance schedules, corrective maintenance procedures, and component replacement protocols. Regular Reporting Requirements: The agreement should mandate regular performance reports, including availability, downtime events, maintenance activities, and any corrective actions taken. Transparency in reporting helps project owners monitor O&M effectiveness. For more details on ways of ensuring optimal operations at a solar project, Camelot has released a couple of related articles, including Navigating the Testing and Commissioning Process for Solar Projects , and Tips and Tricks for Procuring PV Modules in 2024 and Beyond . For quick examples of some of the more notable mistakes made in construction/operations which directly lead to lower availabilities, you can follow us on our ongoing Field Failure Series (FFS) . The next article in this series will cover Camelot’s balanced approach when advising our clients on availability expectations for our projects. In the meantime, for questions and more details about Camelot Energy Group and our distinct attitude towards these issues, please reach out at info@camelotenergygroup.com . About Camelot Energy Group is a technical and strategic advisor to owners and investors in clean energy and energy storage projects, programs, and infrastructure. Guided by our core values of courage, empathy, integrity, and service we seek to support the energy needs of a just, sustainable, and equitable future. Our team has experience in supporting 7+GW of solar PV and 10+ GWh of energy storage and offers expertise in technology, codes and standards, engineering, public programs, project finance, installation methods, quality assurance, safety, contract negotiation, and related topics. Our services are tailored to a providing a different kind of consulting experience that emphasizes the humanity of our clients and team members, resulting in a high quality bespoke service, delivered with focus, attention, and purpose. Key services include: -Technical due diligence of projects and technologies -Owner’s representative and engineer support -Strategic planning -Training and coaching -Codes and standards consulting -Contract negotiation and support < Back Back

< Back Sagar Bharadwaj, PMP Project Manager Sagar Bharadwaj is a Project Manager at Camelot Energy Group with experience in renewable energy, energy storage, and project management. His work spans battery energy storage systems (BESS), long-duration energy storage, hydrogen technologies, technical project management, and engineering coordination, supporting projects from early-stage development through execution. Prior to joining Camelot, Sagar worked across the energy storage and clean energy sectors, supporting the development of lithium-ion and non-lithium battery technologies, hydrogen-powered aviation systems, and utility-scale energy storage projects. He managed the development of a long-duration battery energy storage project at the University of Minnesota, leading technical evaluations, procurement strategy, financial analysis, and project planning. He also supported the development of hydrogen-powered aviation systems at ZeroAvia and contributed to the development of battery technologies at Aerosapien Technologies. Sagar holds a Master of Science in Energy Science, Technology & Policy from Carnegie Mellon University and a Bachelor of Technology in Mechanical Engineering from Vellore Institute of Technology (VIT). He is also a certified Project Management Professional (PMP®). Outside of work, Sagar enjoys producing music, experimenting with new recipes, traveling to national parks, and staying up to date on emerging technologies Sagar.Bharadwaj@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

< Back Hieu Le Chief Financial Officer Hieu serves as Chief Financial Officer at Camelot, bringing deep financial and operational expertise to the role. Before joining Camelot, he was an Associate Partner at McKinsey & Company, where he advised CFOs on restructuring, finance transformation, and organizational performance. Prior to McKinsey, Hieu held direct P&L ownership at Siemens, giving him hands-on experience running operations, not just advising on them. At Camelot, Hieu leads the finance function with the same rigor and discipline he's applied throughout his career, from finance capability building to cost restructuring and reorganization. His approach is grounded in real-world execution, not just strategy on paper. Hieu's guiding principle: finance that holds up in the boardroom, and in reality. Areas of expertise: CFO agenda and finance transformation, cost restructuring and reorganization, P&L ownership and operational finance, finance capability building, global finance operations Hieu.Le@camelotenergygroup.com

Aug 26, 2025 Constructability Part 2 In the last Camelot Energy Group constructability article, we discussed the importance of gathering detailed topography data as it is critical to reduce costly redesigns, permitting delays, and unexpected construction obstacles and issues. In this second constructability article, we are going to go through some considerations that owners and developers need to be taking when putting together project layouts and designs to set the project up for permitting, construction, and long-term success. As we discussed in the last article, in the early stages of development, a preliminary design is typically put together using the sometimes minimal public information on hand. The goal of this initial design is to verify project feasibility, usually in the form of DC and AC system size. Where a lot of project designers go astray is that they primarily focus on module layout and creating as large of a project as possible without considering the other layout considerations that are critical for the project’s success. Doing the due diligence and putting together an accurate and realistic project should always be the goal! Even during the early stages of a project, there are specific layout considerations that should be discussed and ironed out, including site and construction access, medium voltage configurations, module layout, equipment pad locations, wetland locations and mitigations, and overall site hydrology. Site Access: The Forgotten Risk Multiplier Once a potential parcel is identified and a preliminary module layout has been put together, the project team then needs to verify how the site will be accessed for construction and long-term asset management. Project sites will also need access ahead of construction mobilization to do onsite testing for racking as well as for potential tree clearing and site work. Site access may sound simple, but without de-risking how the project will receive racking, modules, transformers, and other equipment, the project is at risk of facing multiple critical constructability issues. The first thing that needs to be considered is the location of the site’s main entrance. Even projects that are adjacent to a paved road can present challenges, including: Steep topography requiring grading or retaining walls Stream crossings and culverts needing hydraulic analysis Public utility crossings that may require additional design complexities and coordination Local DOT requirements for driveway permits, signage, or acceleration/deceleration lanes It’s important to remember that large semi-trucks, some carrying oversized loads, will need to safely turn into the project site so if the approach angle or turning radius isn’t addressed early, retrofits or access delays can quickly erode construction schedules and budget. Designing the Site Access Road Once the site entrance is located, the project’s access road needs to be laid out with construction, operations, and safety in mind. A well-designed access road doesn’t just connect points A and B it facilitates: Efficient traffic flow for potentially hundreds of daily deliveries Safe two-way traffic for large trucks Designated turnarounds for dead-ends or tight sites Clear routing to temporary laydown and permanent O&M areas Where possible, the road should follow natural contours to reduce earthwork. Additionally, early geotechnical investigations can prevent surprises during grading, particularly in regions with expansive clays, bedrock, or high groundwater tables. The design should also consider future maintenance equipment and weather impacts. Medium Voltage Routing: Hidden Cost Driver The next consideration that needs to be well thought out is how medium or high voltage will be routed and interconnected. This affects not just cost, but also the construction timeline and long-term reliability. Generally, there are two ways of routing MV cables: overhead or underground. There are pros and cons to both: Overhead lines are typically less expensive per foot and faster to install in soft or forested terrain but may require FAA filings (if near airports), additional tree clearing, and more extensive permitting. Underground lines reduce visual impact and are more protected but come with higher costs, greater trenching needs, and longer lead times on materials like duct banks or vaults. Additional onsite testing may also be required to verify sub surface conditions will be acceptable for trenching. Where feasible, routing the MV lines along the site access road reduces the number of disturbed areas, consolidates construction zones, and limits environmental impacts. This “co-location” strategy also minimizes total site clearing and road crossings, saving time, money, and permitting effort. Siting Equipment Pads with Precision Once the site access and MV routing are aligned, the focus shifts to the strategic siting of equipment pads, usually housing inverters, transformers, switchgear, and potentially Battery Energy Storage Equipment. Pads must be located with multiple variables in mind: DC home run distances : Minimize string length to reduce voltage drop and avoid oversized cabling. Voltage drop : Particularly on larger sites, both DC and AC voltage drop must be calculated during the 30% design stage to optimize cable size and verify the site configuration is cost effective. Drainage : Pads should not be sited in low areas where water naturally collects, leading to pooling, flooding, and potentially failed equipment. Like we discussed in our first constructability article, the site’s topography should be considered to avoid storm water run-off issues. Water and electricity don’t go well together! Access : These pads must remain accessible post-construction for maintenance vehicles and emergency responders. This includes making room for service clearances, crane access (for transformer/BESS replacement), and pull-off areas. Wetland and Hydrology Impacts: Early Action Avoids Late Pain Finally, no layout is complete without overlaying wetland, floodplain, and surface water data. Many projects mistakenly treat this as a permitting detail rather than a constructability issue. Ignoring hydrology can lead to: Equipment and roads placed in flood-prone areas Unforeseen permitting delays (jurisdictional waters, buffer zones, etc.) Costly re-routing of cable trenches or roads Long-term operational headaches related to erosion or access loss Construction delays and potentially expensive construction tactics Projects should engage qualified wetland consultants early and plan for buffers that not only comply with regulations but allow for construction maneuvering and long-term asset protection. Having a Civil Engineering firm put together a Storm Water Prevention Plan in parallel with the preliminary layout should be a standard task of any project’s development. Closing Thoughts and a look ahead While it's common for early-stage project designs to focus on maximizing DC and AC capacity, this singular focus often overlooks critical infrastructure and constructability elements. Without simultaneously considering site access, medium voltage routing, and strategic equipment pad siting, even the most efficient module layout can become unbuildable or result in major cost overruns. These oversights can lead to unexpected grading requirements, excessive cable runs, inefficient traffic flow during construction, and even the need for complete redesigns. Integrating these considerations ensures the design is not only optimized for energy production but also practical, buildable, and financially viable over the project's lifecycle. At Camelot Energy Group, we work with owners and developers to make sure these decisions are integrated into the layout process early, reducing project risk and setting the stage for a streamlined construction phase and long-term performance. In upcoming “Constructability” articles, we will dive deeper into other critical factors, including geotechnical challenges and how to de risk the issues that may be lurking under the surface of your next project! Stay tuned for more constructability insights from the Camelot Energy Group! Mark Warner < 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. Bespoke technical and strategic advisory for a better world About Us Our mission is to power a just, equitable, and sustainable society with clean energy . Our team of industry experts supports asset owners, investors, public agencies, and others through owner’s engineering, technical due diligence, and strategic advisory services. LEARN MORE WHO WE ARE OUR SERVICES LATEST ARTICLES CAMELOT PHOTO GALLERY

Feb 2, 2026 PJMInterconnectivity The Base Residual Auction The 27/28 Reliability Pricing Model (RPM) Base Residual Auction (BRA) cleared ~ 135 GW of Unforced Capacity (UCAP) at an RTO wide cap of $333.44 per MW-day Only ~ 809 MW of UCAP did not clear due to those resources being priced above the temporary price cap of $333.44 per MW-day Note, this price cap is expected to go away in the upcoming auction in June/July 2026 For those struggling to convert, this is equivalent to $10 per kW-mo In the absence of the cap, the auction would have effectively cleared at $529.80 per MW-day (Rest of RTO) with a reserve margin of 15.1%, clearing somewhere in the range of $26.3B The RPM cleared 14.8% of Installed Reserve Margin (IRM), 5.2% below the 20% IRM. For context, the IRM is the margin required to maintain a one-day-in-10 years Loss of Load Expectation (LOLE) According to estimates, PJM is short of 6.62 GW of UCAP The Bottom Line The price came in at the FERC-approved cap, $333.44/MW-day (UCAP) for the entire PJM footprint, a slight increase (+1.3%)from the 2026/2027 Base Residual Auction . The cap, agreed to be in place for the Base Residual Auctions for delivery years2026/2027 and 2027/2028, is calculated using the accredited capacity of the PJM reference resource. The cleared supply in the auction times the clearing price totals $16.4 billion, although not all load pays this clearing price because of the impact of self-supply and bilateral contract arrangements. Generation Resource Mix The cleared resource mix in this auction includes: 43% natural gas, 21% nuclear,20% coal, 5% demand response, 4%hydro, 2% wind, 2% oil and 1% solar The latest auction results were driven by a 5,250-MW increase in PJM’s demand forecast, almost entirely driven by datacenters, and a roughly 370-MW increase in cleared “unforced capacity” compared to the last auction Reliability risk has shifted from ‘fuel security’ to ‘capacity sufficiency’ Where prior reliability concerns focused on winter gas performance, this time around, the system is short of accredited capacity itself Even perfect performance wouldn’t fix a structural MW/MWh gap Effective Load Carrying Capability Even at record capacity prices, PJM is still not able to attract meaningful storage capacity as well as large-scale renewables This is telling because if high prices are not enough to incentivize investment, the issue is less to do with cost of revenue capture , but more to do with interconnection, accreditation, and rules-based risk Clues from the Queues Based on the interconnection queue, there is ~2,500 MW of offshore wind , 914 MW of solar, 732 MW of BESS, and 569 MW of natural gas under construction at the time of writing Withdrawals took center stage in the last 12-18 mos., where we saw ~37,442 MW of solar, 35,659 MW of BESS, 21,669 MW of natural gas, 7,414 MW of hybrids, 5,117 MW of offshore wind, 3,602 MW of onshore wind exit the queue due to a variety of reasons The greatest number of withdrawals took place in PA, VA, IL, and IN, respectively By capacity, VA and MD have the most projects currently under construction, whereas from a pipeline perspective, IL, VA, and OH have the most projects currently active in the queue This underscores the fact that ne generation response continues to remain weak in PJM. The BRA is signaling scarcity and it’s not going to get better without serious reforms The auction increases the probability of an ‘out of market’ action by PJM, indicating market design as a hurdle this weakening investor confidence in RPM Load Growth PJM has flagged that one of the major drivers of the tight supply-demand balance is the increase in forecasted load , to the tune of + 5,249.9 MW, mostly attributed to large loads Summer: Projected to average 3.1% per year over the next 10-year period and 2.0% over the next 20 years Annualized 10-year growth rates for individual zones range from 0.1% to 6.3%; median of 0.7% Winter: Projected to average 3.8% per year over the next 10-year period, and 2.4% over the next 20 years. Annualized 10-year growth rates for individual zones range from 0.1% to 6.0%; median of 1.6% Some Key Takeaways There was no price discovery this auction – it hit a wall When every LDA clears at the cap, price loses locational signaling value Demand Response was the quiet winner. Required Demand Response (DR) availability increased to all hours in the year, and the calculation of the winter peak load was updated to a coincident value. This was a major driver to an increase of the ELCC value for DR from 69% in the 2026/2027 BRA to 92% in the 2027/2028 BRA If the shortfall continues for two consecutive BRAs, PJM will trigger a Reliability Backstop Auction (RBA) with prior filing with FERC This is almost certain given the large gap between supply and demand The clearing solution may be required to commit capacity resources out-of-merit order but still in a least-cost manner to ensure that all these constraints are respected. In those cases where one or more of the constraints results in out-of-merit commitment in the auction solution, resource clearing prices will be reflective of the price of resources selected out-of-merit order to meet the necessary requirements PJM submitted $0 offers for specific Reliability Must-Run units and will allocate the revenue as a credit to the associated load The Chanceford-Doubs 500 kV backbone transmission line was delayed , which significantly impacted MAAC, SWMAAC and DOM CETLs. Reach us at hello@camelotenergygroup.com for any questions! Raafe Khan < Back Back

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