< Back Bill Atkinson, CEM Senior Project Engineer Bill is a Senior Engineer with over 17 years of experience in the renewable energy and energy storage industry. During that time, Bill has worked extensively developing and implementing rigorous quality assurance and inspection processes for clean energy incentive programs and Bill has inspected more than 530MW of PV and energy storage systems. Bill has performed hundreds of design reviews, technology evaluations, major agreement reviews, and site assessments. Bill is a Certified Energy Manager, Certified PV System Inspector, and holds a B.S. in Community and Regional Planning and Sustainable Technology from Appalachian State University. bill.atkinson@camelotenergygroup.com

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

< 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

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

Jul 3, 2026 FERC issues ‘show cause’ orders to US grid operators on large load integration. The Federal Energy Regulatory Commission ( FERC ( https://www.energy-storage.news/tag/ferc/ ) ) has issued show cause orders under Section 206 of the Federal Power Act to all six regional grid operators under its jurisdiction, addressing how large energy users such as data centers and manufacturing operations are integrated onto the electric grid. The orders, which received support from all five FERC commissioners, aim to ensure consumers continue to have access to reliable, affordable power as demand increases. The orders require six US regional grid operators—PJM Interconnection ( PJM ( https://www.energy-storage.news/tag/pjm/ ) ), Midcontinent Independent System Operator ( MISO ( https://www.energy-storage.news/tag/miso/ ) ), Southwest Power Pool ( SPP ( https://www.energy-storage.news/tag/spp/ ) ), California Independent System Operator Corporation ( CAISO ( https://www.energy- storage.news/tag/caiso/ ) ), ISO New England ( ISO-NE ( https://www.energy-storage.news/tag/isone/ ) ), and New York Independent System Operator ( NYISO ( https://www.energy-storage.news/tag/nyiso/ ) ) —along with their transmission owners, to respond within 60 days. They must either provide justification explaining why their current tariffs remain just and reasonable in the absence of clear and consistent provisions for large load customers, or alternatively propose changes. “What the show cause orders are telling us is that there is an underlying concern about the integration of large loads across markets - there’s a perceived risk of those costs being borne by other ratepayers,” says Raafe Khan, head of energy storage and emerging markets at Camelot Energy Group. The orders support the Secretary of Energy’s advance notice of proposed rulemaking (ANOPR) to expedite the integration of large loads onto the transmission system, which is intended to, as FERC wrote, “support the innovation economy, lead the global AI race, and reshore manufacturing jobs to the US.” Five reform categories FERC has proposed five categories of reforms that grid operators must address: Developing efficient transmission service application and study processes, including consideration of alternative transmission technologies. Preventing cost shifting and requiring transparency into transmission costs. Accommodating co-location arrangements and behind-the-meter generation. Providing new transmission services for flexible large loads. Developing a process to study generating facilities serving electrically proximate large loads and large co-located locals. Khan notes of FERC’s approach, “They’re trying to be firm with what they’re looking for with respect to the outcome, but they’re also being thoughtful about telling the RTOs and ISOs what they need to do.” “They’re basically encouraging study processes that reward technologies that have more of a deflationary impact on power pricing - things like batteries, virtual power plant (VPP) programs, and different passive and active devices that can be installed at a relatively lower cost." Timeline The orders establish a defined timeline for compliance. Grid operators have 21 days from the 18 June order (until 9 July) to intervene formally, must submit a detailed report by the end of July, and have until mid- August for tariff fillings and show cause responses. Within 30 days, RTOs/ISOs and their transmission ownersmust submit detailed information reports on how each intends to ensure adequate generation will be available to serve existing and new large loads. These reports should include any proposals under consideration to address resource adequacy for new large loads, detailed schedules of key milestones, and any ongoing stakeholder processes aimed at increasing the pace of adding generating capacity in the region. “I think some markets are ahead of other," Khan notes. SPP is kind of ahead of the game. PJM is tracking in parallel. MISO is experiencing the fastest growth in terms of data centre integration of any region. California is structurally distinct in terms of the way it operates, and then New York and ISO New England have a lower amount of urgency." Regional differences FERC recognizes that regional differences exist in the procedures and strategies implemented by grid operators and has designed the orders to reflect these variations. SPP has developed its High Impact Large Load and High Impact Large Load Generation Assessment processes, which are expedited frameworks for serving large power demand from loads such as data centers. FERC addresses co-located loads in PJM in a separate proceeding. Transmission service models differs significantly, including in CAISO, which does not offer traditional Order No.888 transmission services. The orders allow each RTO and ISO to define large loads and to create operational requirements particular to their region, while also accounting for regional differences on topics such as cost transparency, study processes, and network upgrades. Energy Storage's expanding role The orders also have implications for energy storage's role transmission planning and grid integration. “I think the show cause order is sensibly about data centers, but really what it’s about is flexibility, and batteries are one of the few technologies that can make large loads connect faster, easier to manage, less expensive for the rest of the system," says Oliver Kerr, managing director, North America at Aurora Energy Research. "What the show cause order does is provide clear guidance to ISOs for ways to enable storage to unlock the value of that flexibility." “I’m very curious to see how ISOs and RTOs embrace grid-enhancing technologies like batteries and dynamic line ratings and advanced conducting to help bring costs down,” Khan says. “With transmission costs ranging anywhere from US$1 million to US$5 million per mile of high voltage transmission, if you can mitigate that by using some of these other commercially available technologies, that’s going to cost less, be deployed faster, and allow more energy to be flowing through the grid.” Khan discusses the potential for batteries in transmission planning, “I’m curious to see how batteries become—and we’ve talked about this a lot— storage as a transmission asset, and how storage becomes part of that overall transmission planning effort.” He continues, "Because of the nature of batteries being able to charge and discharge strategically, that could open some new opportunities for battery-based developers and also opportunities on the grid to alleviate some of those congestions that we see in pockets of the grid.” Enabling storage through reform Kerr explains how the orders directly support energy storage integration, saying, “One of the challenges right now is, if you have an on-site battery at a data centre, that can reduce demand during peak hours. Grid operators essentially see data centers as a big network upgrade problem, and when they’re studying “What batteries on site allow you to do is, during peak times, reduce that maximum draw on the system, and that can reduce your effective demand," Kerr continues," One thing that this FERC order could do is encourage system operators to study both the load and the generation on site together and consider them as a package rather than as two separate things, and that can help projects get online quicker.” Kerr also highlights the potential for new market products, “ISOs and RTOs might be asked to create new products to reward batteries for that, so instead of just playing in as energy arbitrage or ancillary services, they can be rewarded for load management and the transmission benefits they provide.” Long-duration energy storage (LDES) considerations While LDES has received attention in relation to large load integration, Khan notes that market evolution will be necessary to support its deployment. “The challenge that we’ve had with LDES is that we haven't had a market price signal," Khan explains. "In markets like ERCOT, where you have plenty of one to two-hour batteries, the reason we've had so many batteries installed in that duration spectrum is because we had a price signal in the form of ancillary services. But for long duration— if you're talking in order of eight hours, 10 hours, or 12 hours, we don't have a price signal that is incentivizing that longer discharge." He continues, “The reason why the average duration of batteries today is four hours is not by accident—it’s purely because the market rewards you in that two to four-hour range.” Despite these challenges, Khan sees potential for LDES. “Long duration, because of its ability to cover not just your peak load but even around the peak load, is certainly attractive. I think that’s going to be part of the overall planning process evolution.” Kerr adds that the orders could support LDES deployment depending on implementation, “In general, this will encourage more data centers to have onsite generation that’s dispatchable. Batteries are one of the key technologies. Longer duration, depending on how the rules are designed, could favour longer duration assets and provide another revenue stream for them. It will depend exactly on how the rules are written. Do you need to be able to reduce your peak load for just an hour? Is it for a longer system stress event?" He notes that hybrid approaches are already emerging, “One thing that we’re seeing right now is data centers pair batteries with gas as well, so that the battery can ramp up very quickly, and then you’ve got gas for longer periods of needed load reduction.” Co-Location The orders address the growing trend of data centers co-locating with existing generation facilities, including nuclear power plants. FERC is asking the RTOs and ISOs to evaluate co-location of data centers with generators like nuclear, solar and wind and what rules they're going to make for electrical proximity for these large loads," Khan explains. He notes, "FERC basically told all the ISOs and RTOs that they need to adopt preliminary definitions for co-located loads and arrangements for co-location, including behind-the-meter (BTM), and whether co-located loads interconnected below generators’ maximum output should take transmission service and how the demand charges should be allocated without having them transferred over to ratepayers.” Kerr emphasises the importance of clear rules, saying “Right now, there aren’t very clear rules for what co-location looks like and how it should be treated by the grid. In asking ISOs to create clearer rules, I think it just provides a pathway to monetise the value of that flexibility that a battery can provide on site.” This issue has become more relevant as hyperscalers sign capacity agreements with nuclear power plants to secure baseload power. “The problem is that if the load is going to be BTM to the plant, then all of that transmission cost shifts over to other loads, like residential loads,” Khan says. “That’s not going to work, and that’s why I think this show cause order couldn’t come sooner, because we are seeing a lot of these hyperscalers trying to be co-located with these large generators that are already on the grid or have been retired and are coming back to life over the next few years, especially on the nuclear side." State Authority Notably, FERC’s orders do not affect the authority of states to select, site, and permit generating resources or the authority of state public utility commissions to set the rates, terms and conditions of retail electricity sales. The orders specify that while the Commission addresses cost shifting among transmission customers, states retain responsibility to ensure there is no cost shifting among retial customers. The orders are not intended to disrupt existing agreements that large loads have negotiated or are in the process of negotiating for the provision of transmission service. The orders provide that RTOs/ISOs should allow a reasonable amount of time to finalize agreements that are nearing completion when any tariff revisions are filed with the Commission. Market Leadership When asked which markets are best positioned to integrate energy storage into large load integration processes, Kerr points to ERCOT and SPP, " ERCOT is probably furthest along with this in their batch zero study process. It’s not actually covered by the FERC order, but they’ve already made a strong start, and I think they’re ahead of the game of the other markets. I think SPP is probably most advanced in terms of what it’s doing.” He adds, “As a result of this order, all ISOs will have to think through the large load interconnection process and tariffs, and the general push is to encourage flexibility, and there just aren’t many ways that data centers can do that. Batteries are one of the key options for them.” Kerr views FERC’s approach positively, noting, "FERC's role here is not to dictate exactly how each ISO should do it, but just encourage them and really force them to adopt policies, processes, and rules that they didn't have before. It really is those policies, processes, and rules that will be adopted at the ISO/RTO level that will enable the flexibility that batteries provide to be rewarded and broadly encourage flexibility for large loads. I think FERC has done its job. I think it's a really solid order." Khan believes the grid operators have the information needed to respond within the timeline provided, " I think some markets are ahead of others, and they have a lot of the data. The ISOs and RTOs need to act fast because the data center growth story cannot wait. Sometimes we see the technology comes first and regulation follows. This is very much the same way, where technology and regulation are kind of at odds a little bit, but I do believe that they have all the data that they need in order to make an informed decision." Raafe Khan < Back Back

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

< 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

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

The Clean Energy Helpdesk At Camelot, we believe that local authorities, communities, local governments, and non-profits should have access to the same expert advice that is available to developers and big banks. After all, if we are going to power a just and sustainable society with clean energy, it is going to take support from everyone. As such, we have launched the Clean Energy Helpdesk, wherein members of these groups can ask for pro bono support from Camelot’s team of experts. Requests will be responded to in the order received and Camelot staff will provide up to 8 hours of expert consulting to help address topics such as: Training and technical support on battery energy storage systems for local authorities Technical assistance on energy storage codes and standards Guidance on zoning best practices Q&A with municipal officials about a planned project Business case for community renewable energy If you are a community, local authority, local government entity, or non-profit and need help with questions like these, please fill out the form below. We will be glad to review your questions with you and offer help. Clean energy should be a win-win for everyone, so if you have questions please reach out. How can we help? First name Last name Organization* Email* Phone Tell us what you need help with... Send

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

Nov 7, 2024 Part 2: VDER Revenue Stack As discussed in Part 1: VDER Revenue Stack for Standalone Storage Projects , while the Value of Distributed Energy Resources (VDER) Calculator is a freely accessible tool for estimating expected VDER revenues, it can fall short in accurately modeling certain revenue streams. Therefore, when evaluating investments in Battery Energy Storage System (BESS) or hybrid (solar + storage) projects, it’s crucial to supplement this initial analysis with a more detailed revenue forecast that considers additional variables encountered in real-world operations. Like other leading market analytics providers, Camelot uses an optimized dispatch model to project future revenues for BESS and hybrid projects participating in merchant energy and ancillary services markets. However, projects with substantial programmatic revenues—such as NY VDER projects—often require a more customized approach to accurately validate revenue streams and financial model inputs. To address this need, Camelot has developed additional tools and capabilities that seamlessly integrate these programmatic revenue streams with relevant merchant market opportunities. You can find more background on the VDER program here to help developers and investors understand this critical framework. For our analysis, we modeled the revenue stack of a hybrid system with a 5 MWDC solar array and a 5 MW, 4-hour BESS under the VDER program across various utilities. We estimated the Locational System Relief Value (LSRV) manually, while our optimized dispatch model calculated LBMP, ICAP Alt 1, ICAP Alt 2, and DRV values. Additionally, we created four scenarios based on the following configurations: Hybrid Systems – PV Charging Only PV Charging Only (Alt 1) PV Charging Only (Alt 2) Hybrid Systems – PV & Grid Charging PV & Grid Charging (Alt 1) PV & Grid Charging (Alt 2) Key Trends and Insights from the PV Charging Only Results Figure 1 Excerpt from Camelot Q4 2024 NY Market Outlook Report Figure 2 Excerpt from Camelot Q4 2024 NY Market Outlook Report Energy Component (LBMP): The combined energy (LBMP) values from both BESS and solar in PV Charging Only projects are not the lowest among VDER components when compared to standalone BESS projects. This is largely because there are no charging costs—BESS charges from PV rather than the grid. Installed Capacity (ICAP) Value: Capacity prices vary significantly by NYISO load zones, making capacity revenue forecasts challenging due to price volatility across zones. These prices may decline as offshore wind is integrated, which contributes both energy and capacity. ICAP Alt 2 yields higher revenue than ICAP Alt 1 across all zones, primarily due to the rate structure of ICAP Alt 2. Similar to ICAP Alt 3 (applicable only to standalone BESS), ICAP Alt 2 prices have historically been higher, especially in Zone J (NYC – ConEd Group A) and Zone K (PSEG LI). Zone J prices average 3.04 times higher than other zones due to anticipated thermal retirements and land constraints that limit new renewable integration. Demand Reduction Value (DRV): Like standalone BESS projects in areas with 2 PM to 7 PM DRV windows, PV Charging Only projects also achieve strong DRV results as these hours often align with system peak windows. In ConEd Group B (Westchester), projects within the 2 PM to 6 PM DRV window produce significantly higher DRV revenues compared to those in the 2 PM to 7 PM window, as the former aligns more closely with potential peak periods. For instance, DRV revenue in ConEd Group B is 6.36 times higher than the utility average within the 2 PM to 7 PM window and 5.82 times higher than the state average. Locational System Relief Value (LSRV): In Central Hudson’s territory, LSRV does not apply. However, the highest LSRV revenues are seen in ConEd (Zones A to C) and PSEG territories, where LSRV revenues are 2.60 times higher than the state average. Environmental Value: The environmental value remains constant across all utilities and is locked in for 25 years. This revenue stream applies only to PV Charging Only cases in VDER, making these configurations more attractive than PV & Grid Charging due to the additional revenue stream. Key Trends and Insights from the PV and Grid Charging Results Figure 3 Excerpt from Camelot Q4 2024 NY Market Outlook Report Figure 4 Excerpt from Camelot Q4 2024 NY Market Outlook Report Energy Component (LBMP): In PV & Grid Charging projects, the combined energy (LBMP) components from both BESS and solar, including charging costs, are the lowest revenue component when compared to PV Charging Only projects in VDER. This is largely because PV Charging Only projects incur no charging costs, as BESS charges directly from PV rather than the grid. Installed Capacity (ICAP) Value : Capacity prices vary significantly by NYISO load zones, making capacity revenue forecasting challenging due to price volatility across zones. These prices could decrease with the addition of offshore wind, which contributes both energy and capacity. Like PV Charging Only projects, PV & Grid Charging projects see higher revenues under ICAP Alt 2 compared to ICAP Alt 1 across all zones, primarily due to the higher rate structure of ICAP Alt 2. Like ICAP Alt 3, which applies only to standalone BESS projects, ICAP Alt 2 prices have historically been highest in Zone J (NYC – ConEd Group A), followed by Zone K (PSEG LI). Zone J averages 3.06 times higher than other zones, driven by anticipated thermal retirements and land constraints that hinder new renewable integration. Demand Reduction Value (DRV): Similar to standalone BESS projects in regions with 2 PM to 7 PM DRV windows, PV & Grid Charging projects also achieve strong DRV results as these times often align with system peak periods. However, as with PV Charging Only projects, PV & Grid Charging projects in ConEd Group B (Westchester) within the 2 PM to 6 PM DRV window yield much higher DRV revenues than those in the 2 PM to 7 PM window, as the former more closely overlaps with system peaks. For example, DRV revenue in ConEd Group B is 5.95 times higher than the utility average within the 2 PM to 7 PM window and 4.87 times higher than the state average. Locational System Relief Value (LSRV): In the Central Hudson territory, LSRV does not apply. Similar to PV Charging Only projects, the highest LSRV revenues are observed in ConEd (Zones A to C) and PSEG, where LSRV revenues are 2.73 times higher than the state average. Environmental Value: The environmental value applies exclusively to PV Charging Only cases within VDER, making PV & Grid Charging cases less favorable in the VDER revenue stack due to the lack of this additional revenue component. Conclusions The VDER revenue stack significantly diminishes for projects located outside of ConEd and PSEG territories. Although CAPEX and OPEX costs for upstate projects may generally be lower, this advantage is offset by the more lucrative revenue streams available in ConEd and PSEG regions, as highlighted in this article. When calculating these revenue streams, it’s essential to account for the various market nuances specific to the VDER revenue stack, as discussed in Part 1: VDER Revenue Stack for Standalone Storage Projects. While the VDER Value Stack Calculator is a useful tool for preliminary analysis, it may not always provide accurate forward revenue estimates. Our team recommends conducting a more detailed analysis to support the development and financing of energy storage and hybrid projects in New York State. In summary, when comparing the VDER value stack for hybrid projects under ICAP Alt 1 and Alt 2, as well as the PV Charging Only and PV & Grid Charging options, we find that PV Charging Only (Alt 2) projects generate higher revenues than PV & Grid Charging projects. This is primarily due to the Environmental value, which is locked in for 25 years at a fixed rate of $31.03/MWh, and the increased revenue potential that ICAP Alt 2 offers over Alt 1. To accurately assess the benefits of PV Charging Only versus PV & Grid Charging, Camelot can assist you in determining the optimal storage system size to co-locate with your solar system, helping you maximize returns for hybrid projects. If you're interested in assessing energy storage and/or hybrid projects in NYISO’s VDER Program, feel free to reach out to us at info@camelotenergygroup.com . About Camelot Energy Group is a technical and strategic advisor to owners and investors in clean energy and energy storage projects, programs, and infrastructure. Guided by our core values of courage, empathy, integrity, and service we seek to support the energy needs of a just, sustainable, and equitable future. Our team has experience in supporting 7+GW of solar PV and 10+ GWh of energy storage and offers expertise in technology, codes and standards, engineering, public programs, project finance, installation methods, quality assurance, safety, contract negotiation, and related topics. Our services are tailored to a providing a different kind of consulting experience that emphasizes the humanity of our clients and team members, resulting in a high-quality bespoke service, delivered with focus, attention, and purpose. Key services include: -Technical due diligence of projects and technologies -Owner’s representative and engineer support -Strategic planning -Training and coaching -Codes and standards consulting -Contract negotiation and support. < Back Back