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

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

< Back 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

< Back Andrew Leslie Senior Project Engineer Andrew Leslie is a career Field Service Representative with over thirty years of customer service experience in the Power Utilities and Automotive sectors. As a member, lead-hand, or site supervisor of an installation and commissioning team, he was called upon regularly to provide support for the team’s EHS (Environment, Health & Safety) concerns. Project planning, coordination and execution are also areas of his expertise, along with civil construction of substations, duct banks and buried conduits required in Utility Hydro and EV Infrastructure projects. These projects typically included electrical and mechanical installation of switchgear, robots, and components, robotic programming, PLC coordination, and site support. As a Construction Supervisor, Lead-hand, and Team Member at Black and MacDonald, he primarily coordinated and executed Substation Maintenance and Construction projects for Toronto Hydro in the Downtown and Horseshoe substations, on Medium Voltage (5, 15, and 27.6 KV) installation and maintenance projects. His training in the Canadian Armed Forces has given him the ability to adapt to new challenges effectively and his experience as a Field Service Representative in the Power/Utilities and Automotive industries, Substation Construction and Maintenance, EV Infrastructure, BESS O&M, and HV Maintenance backs up his commitment to providing clients end-to-end Stellar Customer Service. andrew.leslie@camelotenergygroup.com

Feb 13, 2025 NERC’s New Compliance Threshold Big changes are coming for renewable energy projects in North America. Starting in May 2025, NERC will require all inverter-based resources (IBRs) with an aggregate nameplate capacity of 20 MVA or more—connected at 60 kV or higher—to register as a Generator Owner (GO) and/or Generator Operator (GOP). If your solar, wind, battery storage, or fuel cell project falls into this category, compliance is no longer optional—it’s mandatory. 1. Understanding the New Requirements Historically, NERC registration was only required for facilities above 75 MVA and 100 kV, but these new thresholds mean that many mid-sized energy projects will now be subject to NERC oversight for the first time. The goal? Enhancing grid reliability as more inverter-based resources connect to the bulk power system. 2. Key Steps for Compliance If your project meets the new criteria, here’s what you need to do: Assess Your Facilities – Determine if your current or planned projects exceed the 20 MVA and 60 kV thresholds. Begin the NERC Registration Process – Registering with NERC isn’t an overnight task. The process can take 6–12 months, depending on factors like documentation requirements, technical assessments, and coordination with regional reliability entities. Early registration helps avoid bottlenecks and ensures compliance well ahead of the May 2026 enforcement deadline. Develop a Compliance Plan – This includes: Meeting NERC Reliability Standards , such as PRC-024 (Generator Frequency and Voltage Protection) to ensure proper coordination with the grid. Updating operational procedures , like implementing real-time monitoring systems to log and report grid disturbances. Training personnel on cyber and physical security best practices to align with CIP (Critical Infrastructure Protection) requirements. Conducting regular audits to ensure ongoing compliance with evolving regulations. Engage with Experts – Compliance can be complex, and mistakes can be costly. Partnering with experienced professionals ensures a smoother transition. 3. How Camelot Energy Group Can Help At Camelot Energy Group, we can assist you with NERC registration and compliance support for energy storage and renewable energy projects. Whether you’re navigating the registration process for the first time or need a tailored strategy to meet NERC’s evolving reliability standards, our team of experts is here to help. From registration assistance to ongoing compliance support, we provide: End-to-end NERC compliance services tailored to your specific project Technical assessments to determine your compliance obligations Regulatory expertise to help you avoid penalties and operational risks With the May 2026 compliance deadline approaching, early action is critical. Don’t let regulatory hurdles slow down your project—reach out to Camelot Energy Group today to ensure you stay ahead of the curve. Contact us to discuss your NERC compliance strategy! < Back Back

Nov 6, 2025 The Future of Grid - Scale Storage Grid forming projects: Should developers want to design grid-forming inverters they will need to engineer their systems differently. This means that auxiliary loads and losses will be higher, and economics will need to be re-casted to account for SoC-loss during standby operation and forming operation In addition, the following challenges must be navigated: Transformer inrush control POW switching or V/f pre-flux ramp for soft energization Over-voltage issues Handling reactive power absorption Resonance and harmonics Damping network oscillations and ensuring stable short-circuit response Frequency and load pick-up challenges Stabilizing V/f during cold load pickup and staged block loading Operational sequencing Q-droop hierarchy, staged energization, etc. validated via EMT and HIL tests Synchronization issues Smooth ramping, droop control, etc. Ramp rate tuning Staged load pickup and reserve margins Raafe Khan and Shawn Shaw < Back Back

Apr 4, 2025 New U.S. Tariff Policy In an Executive Order signed on April 2, 2025, President Trump has instituted a minimum 10% universal tariff on all imports starting April 5. These 10% tariffs will be additional to “Reciprocal Tariffs” between 10% and 50% on products from about 60 countries starting April 9. The Trump Administration has calculated these Reciprocal Tariffs based on the ratio of country-level trade deficits with the US divided by the value of US imports from the target country. This ratio is being described as a measure of perceived unbalanced trade practices against the US and the Reciprocal Tariffs are being set at 50% of this value for most countries. We note that there are a variety of reasons for countries to have trade deficits and the existence of such deficits is not, in its own, an indication of unfair or unfavorable trade policies. It merely conveys that the US buys more of a country’s exports than that country buys of US exports and these deficits are a normal part of global trade between nations. Exceptions ➡️These new tariffs will not apply to goods that have been loaded on a vessel at a port and are deemed to be in transit before the new rates go into effect. ➡️The universal rate will not apply to goods in transit to the US before April 5 and the reciprocal rates will not apply to goods in transit to the US before April 9. ➡️According to the Executive Order, the new tariffs will not apply to certain articles that President Trump has already singled out for current or possible future sector-specific tariffs. Per the National Electrical Contractors Association (NECA), these sectors are steel, aluminum, some downstream products that use steel or aluminum, copper, pharmaceuticals, autos and auto parts, semiconductors, certain critical minerals and energy and energy products. ➡️The tariffs apply only to the non-US content of goods that include US components. However, at least 20% of the value of such goods would have to originate within the US. Implications for the Energy Sector The new tariffs will impact a variety of energy related technologies, from solar modules produced in Vietnam to wind turbines made with foreign components. FERC recently released their Energy Infrastructure Update for January 2025, in which they noted that the vast majority of new generating capacity will be in solar and wind . Other equipment necessary for bringing power plants online, like switchgear, transformers, and substation equipment is largely imported and will see costs increase. The fossil fuel industry is not exempt, either. Thermal generation equipment, like natural gas combined cycle (NGCC) turbines. Supply is already constrained, and capacity is tied up until about 2029-2031 from Tier 1 suppliers, so added costs will add even more strain. The broad application of new tariffs is expected to have an impact across the energy sector, from gas turbines to solar modules, just as energy demand is growing nationwide to fuel the growth of the AI sector. Impacts on the Energy Storage Supply Chain Many of the countries that supply battery energy storage systems (BESS) to the US market are heavily impacted by the new tariffs. As it currently stands, assuming no other changes, by January 2026, BESS from China will be subject to a total tariff of about 82.4%, as shown below. Clearly, juggling all of the relevant tariffs and duties is a significant exercise with many moving parts. *HTSUS = The Harmonized Tariff Schedule of the United States Tariff Rate Base Tariff, applied March 2025 20.0% HTSUS* Tariff (2012) 3.4.0% Section 301 Tariff 7.5% (2025), 25.0% (2026) Reciprocal Tariff 34.0% Total 64.9% (2025), 82.4% (2026) A summary of the major BESS exporting countries to the US and their new tariffs is shown below. Imported BESS from China have a significantly higher expected tariff than most other countries exporting BESS into the US market. The final tariffs on any product, however, will be complicated to determine as the underlying components may, themselves, be subject to additional tariffs (e.g., an Indonesian BESS made with Chinese inputs). This will be most impactful to the lithium iron phosphate (LFP) BESS suppliers in the near term but with no country being exempt from at least some sort of tariff, we can expect a great deal of supply chain adjustment in the months ahead. Country HTSUS Tariff Base Tariff Section 301 Tariff (Before 1/1/26) Section 301 Tariff (After 1/1/26) US Reciprocal Tariff Total New Tarriff Rate in 2025 Total New Tariff Rate in 2026 China 3.4% 20.0% 7.5% 25.0% 34.0% 64.9% 82.4% Indonesia 3.4% 10.0% 0.0% 0.0% 32.0% 45.4% 45.4% South Korea 3.4% 10.0% 0.0% 0.0% 25.0% 38.4% 38.4% Japan 3.4% 10.0% 0.0% 0.0% 24.0% 37.4% 37.4% Impacts on Battery Storage Pricing Based on our tariff tracker, Chinese made DC blocks are now effectively between the $130 - $180 per kWh-dc range (DDP to site), whereas Non-Chinese DC blocks (manufactured in let’s say Indonesia) are between the $115 - $165 per kWh-dc range (DDP to site). Baseline costs are expected to shift in the near term so this gap may narrow or widen further based on macroeconomic conditions. The gap between domestically manufactured non-LFP DC blocks and Chinese made LFP blocks is expected to narrow by early next year to about $50-$60 per kWh-dc. This means, if OEMs in this category reduce their prices by about 25-30%, based on current capacity projects, then, domestically manufactured non-LFP BESS will be a more attractive option for buyers based on total cost of ownership, not inclusive of the domestic content adder under the IRA. It is to be noted that the American Active Anode Material Producers (AAAMP) filed an AD/CVD petition in 2024 seeking a tariff of up to 910%. This has not yet been adjudicated by the Department of Commerce; however, we expect some movement on this later this fiscal year. Chart from Camelot Energy Group – Impact of April 5 Tariff on DC Blocks International Reactions The scale of the current trade actions is highly likely to elicit stiff responses from the international community. As of this morning of 4/4/25, China has announced a 34% tariff on all US imports, alongside increased export controls affecting rare earth minerals and other key materials exported to the US. While the US is a net importer of most clean energy technologies, US exports of biofuels and components for wind and hydropower systems may be impacted. Perhaps even more impactful, however, would be an increase in export controls that reduce the availability of key input materials. Efforts to onshore lithium-ion battery production, for example, will struggle without a ready supply of high grade graphite for making suitable anodes (currently, despite recent AD/CVD claims, there are no domestic suppliers of graphite who can meet the battery industry’s purity requirements). Also, the majority of equipment used in manufacturing solar cells is currently sold by China, with one recent manufacturer Camelot spoke with indicating the only other option was to buy European equipment at “4x the cost and half the output” compared to the Chinese alternatives. If these trade actions are intended to spur a renaissance of domestic manufacturing, the US is highly vulnerable to interrupted supply chains and export controls from abroad that restrict the very tools we need to build and scale a domestic manufacturing industry. The global trade situation and its impacts on the clean energy sector are evolving quickly and this is a developing topic. Stay tuned for periodic updates from the Camelot team in the days ahead. Follow us on LinkedIn for the latest insights. Next Steps for Industry Stakeholders With growing pressure due to pricing, it is time to carefully evaluate projects and supply chain risks. The Camelot team can help asset owners, investors, and other key stakeholders: Perform due diligence on potential new projects, optimizing technology, revenue streams, and asset management strategy Establish, strengthen, and diversify supply chains to ensure you have flexibility to keep your projects on track Evaluate new technologies that may offer new opportunities, as well as new challenges The Camelot team combines technical, economic, procurement, and strategic insights to help our clients navigate the changing market. Reach out to Hello@CamelotEnergyGroup.com today. We look forward to hearing how the new tariffs affect your business- and ensuring you get the help you need. Bespoke technical and strategic advisory for a better world Raafe Khan, Shawn Shaw < Back Back

Mar 10, 2025 Constructability Part 1 Constructability refers to the overall ease and efficiency with which a project can be built. This directly influences both the speed of construction, and the cost required to complete the project. It encompasses various aspects of design, planning, procurement, and execution to ensure the project can be built effectively, safely, and within budget and timeline constraints. The Importance of Constructability in Solar and Battery Storage Projects When it comes to solar and battery storage projects, constructability should be considered as early as the site acquisition stage. Typically, during this phase, developers identify a potential land parcel and create a preliminary layout to assess site capacity, estimate annual energy production, and gauge interconnection feasibility using the limited information available. While this is a crucial first step, constructability concerns are often overlooked or insufficiently analyzed. This can lead to projects with critical constructability challenges advancing through the development process—resulting in wasted time and money on projects with a low likelihood of successful execution. The Camelot Energy team has extensive experience in development, engineering, procurement, and construction, allowing us to help owners and developers identify and address constructability concerns early in a project’s lifecycle. By doing so, we help mitigate late-stage issues, ensuring smoother project execution. This article is the first in a series on "Constructability," where the Camelot team will highlight common challenges and showcase solutions that enable seamless project development and construction. The Ups and Downs of Topography in Renewable Energy Projects One of the most common constructability issues we encounter during the development and construction phases is inadequate attention to topography . The terrain of a project site significantly impacts design feasibility, energy production estimates, and overall constructability. Why Topography Matters Most preliminary project layouts are created using publicly available data, which typically provides only 5’ or 10’ contour intervals. While this offers a rough idea of site conditions, it lacks the precision needed to fully de-risk a project. This limitation is particularly problematic for sites with complex terrain, dense forestation, or proximity to floodplains. For such projects, hiring a professional survey company to conduct a detailed topographic survey (with 2’ contour intervals or finer) is essential. This data enables developers and engineers to validate site conditions accurately and plan accordingly. Using Topography Data in Project Design and Development Once a detailed topographic survey is completed, the preliminary layout—including solar arrays, battery storage units, access roads, fencing, and equipment pads—should be incorporated into computer-aided design (CAD) software . By integrating this data into the design, engineers can assess site suitability and proactively address constructability challenges. At this stage, a slope analysis should be conducted to identify areas of concern. This analysis requires input from multiple disciplines, including civil, structural, and electrical engineers, construction professionals, and racking vendors . Collaboration ensures that all aspects of the project are evaluated, and risks are mitigated early. Key Topography Considerations for Constructability Civil Design Grading requirements to meet design standards Stormwater management and hydrology considerations Access road construction feasibility Equipment pad locations and elevation planning Structural Design Vendor-specific racking slope tolerances Structural calculations for stability and safety Accommodation of varying site elevations Electrical Design Trenching and underground conductor runs Placement of medium-voltage poles and guy wires for overhead lines Routing and protection of underground cables Construction Considerations Water management strategies during construction Temporary erosion control measures Site layout for construction staging areas Placement of office trailers and parking zones Operations & Maintenance (O&M) Planning Long-term vegetation management strategies Ongoing erosion control measures Why Early Topographic Analysis is Essential Topography sets the foundation for every aspect of a renewable energy project—it is the building block of successful development and project design. Identifying and addressing topographic challenges early minimizes risks, helps maintain budget and schedule discipline, and ensures that project goals are met. By taking a proactive approach, developers can avoid costly redesigns, permitting delays, and unexpected construction obstacles. Looking Ahead This article is just the beginning of our series on constructability. In upcoming articles, we will dive deeper into other critical factors affecting constructability, including geotechnical challenges, interconnection hurdles, and procurement risks. Stay tuned for more constructability insights from the Camelot Energy Group! < 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