< 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

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 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

< Back Mark Warner Senior Project Manager Mark Warner, a Project Manager at Camelot Energy Group, has over 5 years of experience in the renewable energy development and EPC contractor space. Mark has extensive background in project development, siting, energy analysis, design, construction planning, and permitting for commercial and utility-scale solar projects. Mark holds a Bachelor of Science Degree in Mechanical Engineering Technology from the University of Maine. mark.warner@camelotenergygroup.com

OUR MISSION To power a just and sustainable society with clean energy Getting to this point will require substantial investment in solar, energy storage, and other clean energy technologies, with such investment coming not only from banks and investment funds but communities, corporations, and governments. Building the energy systems of tomorrow offers a chance to rethink energy systems, infrastructure, ownership, and equity. Enabling the investment required to scale clean energy is about people. Investors in the clean energy future have very human questions, concerns, and anxiety as they step into unknown technologies, financing mechanisms, commercial agreements, and other challenges. These people, whether experienced investors or community leaders new to energy topics, deserve respect, expertise, empathy, and service as they bravely step into the future. At Camelot Energy Group , to these brave owners, investors, and visionaries putting their resources into the clean energy future, we say: “We’ve got your backs”. Camelot was founded to accelerate investment in the clean energy infrastructure of the future but also to embrace the human aspects of this transition. By taking the time to listen to our clients, staff, and partners and give each the focus and attention they deserve, we set ourselves apart from other consultancies that focus on sales, overly standardized services, and lackluster support provided by overworked and distracted teams. We believe that by treating our team and clients with respect, dignity, and empathy we provide the best possible advisory services and solve real-world challenges. OUR CORE VALUES Integrity, empathy, courage, and service > Back

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

May 27, 2026 ERCOT NPRR 1333: Is Your Inverter-Based Resource Eligible for the $25M Grid-Forming Incentive? ERCOT just posted NPRR 1333, a $25M one-time incentive to retrofit existing inverter-based resources with advanced grid-support capabilities (grid forming, specifically). The mechanics are tight: $1,500 per MW of nameplate, paid 12 months after implementation Linear availability haircut below 90% Applications due March 31, 2027; implementation deadline December 31, 2028 First-come, first-served allocation Funded by Load on an LRS basics Section sunsets June 30, 2030 Three things stand out: The cap binds fast. $25M divided by $1,500/MW ~ 16,700 MW of qualifying capacity against ~50 GW of grandfathered ESRs alone, before wind and solar. First movers win. The price point signals intent. $1,500/MW is modest relative to hardware-heavy retrofits, suggesting the target is units where advanced grid support is largely a controls or firmware update. The protocol language hints at this directly, too The impact analysis is striking for what's absent. Based on the recent disclosure, there is no project cost, no system impact, no staffing impact, and no alternatives evaluated. This is a pure market-incentive lever, not an infrastructure program. Building on NOGRR 272 and PGRR 121 (approved by the PUCT in November 2025), NPRR 1333 closes the gap for the existing IBR fleet. ERCOT's own analysis suggests up to 10% improvement in Generic Transmission Constraints (GTC) in West Texas, McCamey, and the Panhandle under tested scenarios. For ESR owners with marginal-cost retrofit paths, the math is worth running this quarter, not next. Contact Camelot Energy Group today to evaluate your options! Raafe Khan < Back Back

< Back Calla Schultz Associate Project Engineer Calla Schultz is an Associate Project Engineer at Camelot Energy Group, where she supports the Technical Services team in advancing clean energy projects. Her focus is on engineering analysis, market and policy research, and technical documentation to inform decision-making and advance solar and battery energy storage project deployment. Previously, she interned at Camelot on the Programs and Policy team, contributing to technical advisory work and feasibility studies for public sector clients. Before joining Camelot, she worked as a Battery Energy Storage Systems (BESS) Intern at PureSky Energy. She has also conducted laboratory research in both academic and industry settings across life sciences and geochemistry, reflecting her interest in applying physical science to address environmental problems. Calla values collaborating with Camelot's experienced and thoughtful team to help build a resilient, accessible energy system for future generations. Outside of work, she enjoys traveling and learning about different cultures, practicing yoga, drinking coffee, and spending time in nature. She has an M.S. in Materials Science and Engineering from Boston University, with a concentration in Materials for Energy and Environment, and holds a B.S. in Chemistry from McGill University. calla.schultz@camelotenergygroup.com

Jun 25, 2026 Battery Storage Incentive Landscape in New York Introduction The New York energy landscape is shifting faster than most people realize. Between the summers being hotter than ever, strict emission rules, higher levels of electrification, and a grid that is feeling the pressure of these rising load demands, the disequilibrium between supply and demand could not be higher. If you are a property owner in New York, not only do you need to hunt for available incentives, you also need to understand how the timing, program specifics, and new compliance rules would impact the actual value of your investments. The markets are changing rapidly, and with this article, we aim to help break down the options for you. The state has committed to deploying 6GW of energy storage by 2030 in every region from the 5 boroughs to upstate cities. Understanding how these programs interact and how to execute a relatively linear execution workflow are crucial as these incentives are substantial as well as limited. NYSERDA Incentives Residential and Retail Storage Incentives This is New York’s primary incentive program for battery storage systems up to 5 MW AC . The program offers upfront rebates based on usable installed kilowatt-hour (kWh) capacity. Incentives are usually paid directly to the NYSERDA Participating contractors and are required to be passed by the customer as a reduction in the total installed project cost. Residential Energy Storage Incentives are available for behind-the-meter systems with up to 25 kWh of storage capacity. The Retail Energy Storage Incentives are available to both behind-the-meter and front-of-the-meter projects up to 5 MW AC . The program uses a “ declining block ” setup. Funding is divided into tiers, and as those tiers fill up, the incentive amount tends to drop. To lock in the highest possible rate, the best decision is to act soon! For qualifying in this incentive: You’ll need to work with a NYSERDA-approved installer. The system needs to meet all required safety and permitting standards, including UL 9540A fire safety testing and approvals from local authorities. Projects are expected to stay in service long enough to deliver meaningful, long-term benefits to the grid. Systems need to be properly integrated with building electrical infrastructure and utility interconnection requirements. Incentive levels change by region, with New York City operating under a separate declining block schedule compared to Upstate New York and Long Island, each of these follows its own regional incentive structure and funding. Value of Distributed Energy Resources (VDER) or the Value Stack The VDER is a methodology created by the New York State Public Service Commission to compensate energy created by distributed energy resources including solar, standalone energy storage and co-located energy storage systems. Eligible systems include behind-the-meter nonresidential projects larger than 750 kWAC, as well as front-of-the-meter projects up to 5 MWAC that export electricity onto the electric distribution system. The Value Stack tariff provides savings to a project through bill credits;, there are no direct cash payments. Compensation is based on when and where a project provides electricity to the grid, determined by the following components of the Value Stack: Energy Value (LBMP) Capacity Value (ICAP) Environmental Value (E) Demand Reduction Value (DRV) Locational System Relief Value (LSRV) Each month, NY utilities file a statement that includes the rates associated with each of the above components of the value stack. Bulk Energy storage incentive (Index Storage Credit Program) This program is designed for the large-scale “front-of-the-meter” projects, those larger than 5 MW that feed power directly into the grid. In this program the ISC gives developers long-term financial stability. You still sell power and services in the wholesale market although the ISC acts as a buffer against price rises. This works as a “contract for differences.” As the market price falls below the agreed strike price, NYSERDA pays you the difference. If market is booming and you make more than that price, you do end up paying the extra cost back. Which helps in keeping the income steady and predictable. Grid interconnection, strict safety testing (UL 9540A), and local permitting are yet required, as New York is more streamlined, they have more rigorous requirements. If you can manage the complex utility-scale projects this program is for you! Inclusive Storage Incentive (ISI) This program is designed as a bonus payment. If your project is in the Disadvantaged Community (DAC) it provides and additional per-kWh incentive adder for eligible projects along with the Residential and Retail Energy Storage Incentive. The goal of this incentive is to bring clean energy to the neighborhoods hit hardest by climate change, ensuring everyone gets a chance as New York moves to achieve its climate goals. This is for small property owners. You need to check from the NYSERDA’s mapping tool you are in the qualifying area which factors the local health, environmental and economic factors to identify communities in need. This incentive can be combined with other perks like property tax exemptions (RPTL § 487) and utility rewards programs. For this you receive the payment right alongside with your base incentive as the project is completed. Standard safety rules always need to be followed, which include passing the fire safety test (UL 9540A) and getting the permits for DOB and FDNY. BESS Peer Review Although not an incentive program, the new BESS Peer Review process is an important requirement tied to both the Retail and Bulk Storage programs for non-NYC projects. Required for all NYSERDA-funded energy storage projects exceeding 600 kWh, the Peer Review is a pre-construction desktop review of design documents conducted by vetted, qualified experts to verify code compliance and safety before construction begins. The process generally involves document submission, an iterative technical review with feedback, and results in an approved Peer Review Report. Applicants should plan for 45–60 days for a complete submission. Once approved, major design or equipment changes should be avoided, because any material deviations from the approved design carry financial risk and must be resubmitted for review. A post-construction onsite field inspection is also required to confirm the project was built in accordance with the approved design. We are proud to be one of the contracted firms that helped design the Peer Review program and are positioned to carry out reviews to help ensure projects are built to the highest safety standards for communities, local AHJs, and fire departments. Property Based Incentives Solar & Electric Storage Property Tax Abatement (PTA) If you like working on a solar or battery project this is a powerful incentive. It is designed to help you recoup a significant chunk of your investment through direct tax relief. 30% of the installation cost can be recovered, with a total cap of $250,000 which is spread over 4 years. Which breaks down tax to be $62,500 per year. New York is a fast city! Applications are to be submitted by March 15th to see the credit on the following tax year’s bill. In case you miss it then you must wait for next year to start saving. This PTA applies to Class 1 (residential homes), Class 2 (multifamily building) and Class 4 (commercial buildings). You need to clear the usual requirements: Clearing tests from DOB and DFNY UL9540A fire system standards must be met. The drawback is that you can’t combine this and the RPTL § 487 property tax exemption at the same time. Hence, owners need to calculate which incentive is more pocket-friendly for them. Clean Energy Systems Exemption (RPTL § 487) This is a statewide incentive program that keeps property taxes from increasing after the installation of a battery storage system. For 15- years any increase in your property assessed value which comes from the new system is completely tax-exempt. The incentive is best for owners and developers. As this is a state law the local governments and the school districts outside the New York can choose to opt out of this. To enroll in this, one needs to check with the local government to confirm if the local municipality is participating. How do you claim this? Owners need to file the RP-487 Form Notice of Intent (NOI) to their local tax authority. Meet fire codes, building code and utility interconnection standards. This exemption can’t be combined with Property Tax Abatement (PTA), so you will need to analyze the project's costs and see which helps you in saving more. Other Regional Incentives and Statewide Support Programs Con Edison Demand Management Programs (Downstate) This program is for high-traffic areas, i.e. Brooklyn and Queens, where the grid can get overloaded due to congestion. To solve building expensive power plants, Con Edison offers programs such as Brooklyn – Queens Demand Management (BQDM) which pays building owners for using less power when there is a strain on the grid. To reduce load during peak demand events in the summer due to the use of HVAC, Load Relief Programs are introduced where they pay the building owners and operators to reduce the load during the peak events. These programs tend to be highly lucrative paying between $2,500-$3,000 per kW. This isn’t a one-time confirmation;, it’s a combination of an upfront payment and ongoing rewards for how well your system would perform when dispatched by Con Edison during peak demand events. As summer heatwaves rise and we continue to see prolonged cold snaps, the grid needs a fast response. Battery storage is the perfect solution for this as it discharges power by dropping the buildings net demand the moment Conm Ed sends a signal. To qualify for this: The system needs a 4-hour dispatchable capacity. The systems need to be integrated with Con Ed’s monitoring system so they can verify that the load is reducing during peak events. When these payments are combined with NYSERDA rebates and federal tax credits, battery storage economics improve. In many neighborhoods, stacking these incentives transforms battery storage from a marginal option to a high return, and a must- have investment by also shortening the payback period. Other Utility Programs by Region PSEG Long Island has been testing out storage rebates in LIPA territory for residential and commercial customers. Residential – single family or small residential properties billed under residential tariffs. Commercial - non – residential or multifamily property billed under commercial institutional utility tariffs. National Grid, NYSEG, RG&E and Central Hudson offer programs which are focused on peak load reduction and demand response, encouraging customers to reduce usage during high-demand periods to help in managing the local grid constraints. Connected Solutions – This program is a performance-based incentive program that pays National Grid customers for sharing stored energy from their battery systems with the electric grid during periods of peak demand. Customers receive annual incentive payments based on the average amount of power they contribute. Active National Grid electric service account customers, both residential and commercial and industrial, with behind-the-meter battery energy storage systems are eligible. Statewide and Complementary Support Programs NY – Sun Program: Pairing solar panels with a battery system? You can be eligible for this incentive program. It is particularly helpful for commercial properties and housing projects dedicated to low-to-moderate income housing. NY Green Bank: Offers flexible, low-cost loans designed to support energy storage projects, whether deployed as standalone systems or on a solar array. NYSERDA Permitting Toolkit : A resource packed with templates and guides to make the permitting process less of a headache. This helps developers and local government get on the same page and ultimately cut down soft costs and delays. Clean Energy Communities (CEC): Local towns adopt clean energy-friendly policies as expedites permitting energy code enhancements that qualify for state funding. How to Maximize ROI Incentive stacking can improve project economics and support compliance objectives. A typical stack would include: NYSERDA rebates NYC PTA or RPTL § 487 Federal Investment Tax Credit Utility demand management programs Factors to consider: Timing – ensure to place the system in service Installation type – Standalone BESS vs. solar + storage Property type – Residential, commercial or multifamily. Compliance Landscape Local Law 97 (The Carbon Tax) Buildings which are over 25,000 sq ft and exceed their annual emissions usage limits face penalties of $268 per metric ton of CO2 emissions above the limit. Although the penalty rate is fixed, emissions caps tighten over time, increasing compliance risk for inefficient buildings. Batteries help buildings reduce emissions penalties by shifting electricity use to lower- emissions periods, lowering overall emissions intensity and supporting future solar or EV charging stations. Local Law 87 (The Efficiency Tune-Up) It requires covered New York city buildings to complete energy audits and retro-commissioning every ten years to identify and correct inefficiencies in building systems. Reports often reveal load spikes. Battery storage can support HVAC upgrades or electric boilers by managing these spikes and reducing the strain on electrical services. Compliance doesn’t require paying full costs. Stacking NYSERDA rebates, utility programs, the federal ITC and NYC property tax abatements can reduce the system costs. Residential and commercial battery storage is a practical way to support compliance with New York’s energy requirements while minimizing the need for major electrical infrastructure upgrades. BESS Moratorium Map Conclusion The clock is ticking. Incentives don’t stay forever. Funding levels through NYSERDA inventive levels decline as funding blocks are fully subscribed, and missing a single tax deadline means a delay for a year to save your pockets. Early action wins. Starting now doesn’t just improve your banks, it leads to smoother approvals through permitting and approval processes, particularly as demand for energy storage grows. Moving sooner will improve project economics. Early adoption of battery storage supports building level compliance efforts and contributes to a cleaner, more reliable and more resilient New York for the future. Raafe Khan, Nimisha Shah < Back Back