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Dec 30, 2025 PJM Interconnection 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 Source : PJM THE BOTTOM LINE Source : PJM 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 years 2026/2027 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 data centers, 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 Source : PJM EFFECTIVE LOAD CARRYING CAPABILITY Source : PJM • 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 Source : PJM • 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 new 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 these 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. MARKET EVOLUTION • The Federal Energy Regulatory Commission this year also approved a PJM-proposed expansion of Surplus Interconnection Service to augment the operating efficiency and availability of existing resources, and the Reliability Resource Initiative, which attracted 11,000 MW of nameplate capacity in proposed, shovel-ready, high reliability generation projects. • PJM has also asked FERC for amendments to the rules on Capacity Interconnection Rights (CIRs) that would facilitate an expedited interconnection process to utilize the CIRs of a deactivating resource. • Recognizing that electricity demand is increasing faster than generation is being added, PJM is working on multiple fronts to further streamline the Interconnection Study processes. This includes our collaboration with Google/Tapestry, to leverage artificial intelligence to further streamline the study process and reduce study timelines. Raafe Khan < Back Back

Feb 12, 2025 MA SMART Part 2 Massachusetts continues to establish itself as a leader in state-level clean energy programs, and Camelot is staying closely aligned on the latest developments in the region. Developers and other players take note: Through the Solar Massachusetts Renewable Target (SMART) Program and the Clean Peak Energy Standard, the state has introduced dynamic frameworks designed to accelerate renewable energy adoption while addressing grid reliability and peak demand challenges. Here, in part 1 of our two-part series on the Massachusetts programs, we’ll set the scene with what you need to know about the programs, and will dive more deeply into the key financial implications in part 2. Massachusetts SMART Program Overview The Solar Massachusetts Renewable Target (SMART) Program is a pioneering initiative aimed at promoting solar energy adoption across the state. Managed by the Massachusetts Department of Energy Resources (DOER), the program provides long-term incentives for solar photovoltaic (PV) projects, encouraging residential, commercial and small utility scale installations up to 5MW AC. Here’s an in-depth look at its objectives, structure, and benefits. The SMART program is a feed-in-tariff program that assigns a unique energy rate to different qualifying solar projects based on system size, system type, system location, offtaker type, and associated energy storage system size. The SMART program has a total capacity of 3,200 MW AC, which is distributed among Massachusetts' three investor-owned electric distribution companies: National Grid , Eversource Energy , and Unitil . The capacity assigned to each utility is proportional to the number of customers in their service area. Generally, sites serviced by municipally-owned electric utilities are not eligible for the SMART program. Each utility’s allocated capacity is further divided into two categories: one for systems larger than 25kW AC and one for systems smaller than 25kW AC. These categories are then subdivided into 16 "capacity blocks." As SMART applications are approved, these blocks gradually fill up. Once a block is fully subscribed, it is considered at capacity, and the program advances to the next block. The incentive rate for the new block is lower than that of the previous one, declining by 4% each block. Figure 1: Summary of Capacity Blocks as of 1/9/2025. SMART Capacity Block updates are posted at www.masmartsolar.com for each utility company To determine the exact SMART tariff rate that a project is granted, the DOER determines a base compensation rate based on the system size and the current utility capacity block. Then adders are applied based on system location, off-taker type, energy storage and racking (see Figure 1). Similar to the declining capacity blocks, the adders have declining “tranches”, and as each tranche is filled at the state level, the incentive rate declines by 4%. However, the adder rates for the Agricultural, Brownfield, Canopy, Floating and Landfill Adders will be locked in at their Tranche 1 rates for the duration of the SMART program and the adder rate for the Building Mounted Adder will be locked in at the Tranche 2 rate for the duration of the SMART program as modified by order 20-145-B released by the Department of Public Utilities on 12/30/2021. Figure 2: Previous Adder Values Massachusetts DOER SMART Program – Initial Release 2018 *Significant adjustments to this table are proposed in the Straw proposal: Figure 3: Straw proposal for new adders Massachusetts DOER SMART Updates – Straw Proposal 2024 SMART and Energy Storage Under the current SMART regulations, all projects over 500kW must be coupled with an Energy Storage System (ESS).* SMART projects coupled with ESS are provided with an “energy storage adder” that ranges between 0.025 – 0.077 $/kWh. The exact adder value is dependent on the max power output of the ESS and the duration, with the maximum adder being granted to projects with 100% of the max power of the PV system and 6 hours duration and the minimum adder being granted to projects with max 25% of max PV power and 2 hour duration. The incentive of the Energy Storage adder is applied to all power generated by the system, independent of the use case of the ESS. There is a requirement that each year the ESS must be cycled a minimum of 52 times to maintain eligibility for this adder.** * The new straw proposal published 7/29/24 specifies only projects over 1MW AC will require ESS ** The new straw proposal published 7/29/24 increases this requirement to 156 cycles per year and adds the requirement that the ESS is online and able to discharge 85% of the time during summer and winter months. Figure 4: Energy Storage Adder Matrix Massachusetts Clean Peak Energy Program Overview The Massachusetts Clean Peak Energy Standard (CPS) is a first-of-its-kind program designed to encourage the use of clean energy during peak electricity demand periods. Managed by the Massachusetts DOER, the program incentivizes renewable energy systems and energy storage solutions that contribute to grid stability and reduce reliance on fossil fuel-based power during high-demand hours. How the Program Works Clean Peak Energy Certificates (CPECs): Eligible resources earn Clean Peak Energy Certificates (CPECs) by generating or dispatching energy during defined Seasonal Peak Periods and the Actual Monthly System Peak, as specified by the Massachusetts Department of Energy Resources (MA DOER). CPECs can be traded in the market to electricity suppliers required to meet clean peak compliance obligations. Various applicable multipliers align CPEC generation with time periods and resource attributes that have the highest impact. For instance, higher multipliers are assigned for summer and winter months (4x) compared to other season months (1x). The Actual Monthly System Peak is weighted disproportionately to incentivize project owners to optimize performance during the peak hour of a given month, which determines the infrastructure sizing requirements. Hybrid Solar + ESS projects that are enrolled in the SMART program can also participate in the Clean Peak program and generate CPECs. However, these projects are awarded a 0.3 multiplier for all CPECs generated, effectively derating the value of their incentive by 70%. Eligible Resources: Wind turbines with storage. Solar PV systems paired with energy storage. Standalone storage systems charged with renewable energy. Demand response resources that reduce load during peak periods. Figure 5 – Energy Storage Charging Windows for Solar-Based Charging Hours Defined Peak Periods: Peak hours are established seasonally to reflect times of highest grid demand. These periods typically occur during late afternoon to early evening hour Figure 6 – Clean Peak Season (CPS) Windows Market-Driven Prices: The value of CPECs fluctuates based on market supply and demand, providing financial incentives for participating resources. Things To Note CPEC Revenues CPEC revenues are designed to incentivize clean energy generation during peak demand periods and can apply to projects that include solar paired with energy storage systems (solar + storage), as these systems are particularly effective at delivering energy during peak periods. Standalone solar projects can still qualify for CPEC revenues, but their ability to maximize these revenues is typically limited compared to solar-plus-storage systems, which offers greater flexibility in aligning energy delivery with peak periods because storage enhances the ability to participate in the Clean Peak Standard (CPS) program. By storing solar energy and dispatching it during peak demand hours, hybrid systems can generate additional CPEC revenues, making them a financially attractive option. ACP Rate Changes The DOER has implemented significant updates to the Alternative Compliance Payment (ACP) rate as part of its emergency rulemaking. The ACP rate will remain at $45/MWh through Compliance Year 2025. However, starting in 2026, the rate will increase to $65/MWh and stay at this level until 2032. After 2032, the ACP will return to $45/MWh, where it will remain through 2050. This marks a major departure from the original regulations, which planned for a declining ACP rate, dropping to $4.96 by the end of the policy period. While the higher ACP rate is expected to boost market prices, there is still a risk of steep price drops if surpluses exceed the banking limits of load-serving entities. Figure 7 – CPS Alternative Compliance Payment (ACP) Rates Near-Term Resource Multiplier (NTRM) DOER has also introduced a new NTRM under the CPS. The NTRM will provide a 2x multiplier on CPECs for up to 50 MW of qualified energy storage systems for a duration of 10 years. To qualify, the QESS must be a standalone, front-of-the-meter system interconnected to the distribution system, with a commercial operation date between January 1, 2019, and January 1, 2027. Additionally, it must not have received a Statement of Qualification before January 1, 2025, or the Distribution Credit Multiplier. Ownership is restricted to prevent any single entity from controlling more than 50% (25 MW) of the program’s capacity. DOER released the NTRM application on January 7, 2025[SS3] . Applications submitted by January 21, 2025, will be prioritized based on interconnection service agreement dates. Any applications received after this deadline will be reviewed on a first-come, first-served basis. These updates aim to encourage the development of energy storage systems while addressing previous concerns about market pricing and resource deployment under the CPS. Conclusions Looking forward, Massachusetts aims to expand and refine the SMART & Clean Peak Program to adapt to emerging technologies and evolving market conditions. By integrating solar energy with battery storage and enhancing equitable access, the program continues to serve as a model for other states aiming to transition to a clean energy future. For those considering solar or hybrid projects in the state, the program offers a valuable opportunity to contribute to sustainability while enjoying financial benefits. Stay tuned for Part 2, where we will discuss the revenue stack for hybrid projects, containing a combination of the SMART Program & Clean Peak Program. If you're interested in assessing solar, energy storage, and/or hybrid projects in ISO-NE’s MA SMART Program, feel free to reach out to us at info@camelotenergygroup.com . About Camelot Energy Group is a technical and strategic advisor to owners and investors in clean energy and energy storage projects, programs, and infrastructure. Guided by our core values of courage, empathy, integrity, and service we seek to support the energy needs of a just, sustainable, and equitable future. Our team has experience in supporting 7+GW of solar PV and 10+ GWh of energy storage and offers expertise in technology, codes and standards, engineering, public programs, project finance, installation methods, quality assurance, safety, contract negotiation, and related topics. Our services are tailored to a providing a different kind of consulting experience that emphasizes the humanity of our clients and team members, resulting in a high-quality bespoke service, delivered with focus, attention, and purpose. Key services include: -Technical due diligence of projects and technologies -Owner’s representative and engineer support -Strategic planning -Training and coaching -Codes and standards consulting -Contract negotiation and support. < Back Back

Camelot Energy Group is a technical & strategic advisor to owners and investors in clean energy & energy storage projects, programs & infrastructure. We specialise in Solar, Energy Storage, Consulting, Engineering, Batteries, Due Diligence, Energy Access, Strategy, Owner’s Engineering & Advisory. FEATURED PROJECTS Sectors We Serve Camelot Energy Group specializes in the clean energy sector, particularly focusing on these key areas: Solar Energy Storage Clean Energy Programs Energy Access Solar Energy Storage Clean Energy Programs Energy Access 01. SOLAR Enough solar energy falls on the surface of the earth in one hour to supply all of the energy needs of the global population for a year. However, when it comes to capturing and using that energy, the devil is, as they say, in the details. At Camelot Energy Group, we specialize in those details and our team members have supported the financing and construction of over 7GW of solar PV projects, including: Managing quality assurance for portfolios of distributed solar projects and performing hundreds of hands-on field inspections Performing Owner’s Engineering on utility scale projects from 500kW to 100’s of MW Providing technical due diligence and independent engineering (IE) services to support financing of portfolios, projects, and development platforms Supporting and evaluating state clean energy programs to support solar PV and related technologies Developed and delivered numerous trainings on relevant codes, standards, and best practices Our team members have supported many different public and private clients building and investing in solar technologies. See our Services page or contact us to learn more. 02. ENERGY STORAGE Scaling adoption of clean energy technologies will require a range of enabling technologies but none is more critical than the ability to safely and cost-effectively store and manage electricity. Energy storage technologies, from lithium-ion batteries to pumped hydro facilities, are key to managing the grid of tomorrow and the team at Camelot Energy Group has unique expertise and insights into the energy storage industry. From island microgrids to large utility-scale grid support applications, our team members have supported the energy storage transition for nearly two decades and bring core expertise in: Ensured asset owners receive the best possible technologies, designs, and installations during typical Owners Engineering engagements Evaluating new technologies and suppliers through our Strategic Advisory services Performing Technical due diligence and independent engineering on energy storage (including those with colocated solar) facilities and portfolios Developing and delivering trainings to support government entities and clean energy programs Provided key insights on developing codes and standards via our recent publications, including our founder’s recent book , published with the International Code Council and International Association of Electrical Inspectors. Our team members have supported dozens of energy storage projects, including over 4GWh projects. Please contact us if you would like to know more. SOLAR ENERGY STORAGE 03. CLEAN ENERGY PROGRAMS Clean energy programs often provide valuable incentives and technical support that have been key to driving adoption of new technologies. Though solar PV is much more cost-effective than it was even a few years ago, these programs continue to play a vital role and Camelot Energy Group is pleased to support these efforts. Our team members have: Helped state incentive programs build and manage quality assurance programs, ensuring that public funds support high quality, safe, and effective installations through program design, technical design reviews, process improvement, and implementation of over 4,000 hands-on field inspections. Evaluated public and utility-run incentive programs to determine cost-effectiveness, participant satisfaction, attributable energy benefits, and support filings with relevant regulatory bodies. Supported utilities during Integrated Resource Plan processes by analyzing technical, economic, and market potential for solar , energy storage, and other clean energy technologies. Our team members have worked with programs at the federal level and in over a dozen states. If you manage clean energy programs and need support running, evaluating, or expanding such a program please contact us. CLEAN ENERGY PROGRAMS 04. ENERGY ACCESS Globally, more than 750 million people (twice the population of the United States) lack access to electricity and some 2.6 billion people lack access to clean cooking fuels. At Camelot, we believe that a transition to a clean energy future must include energy access for all and we are glad to support these efforts through: Ensuring high quality and safety standards are maintained through Owner’s Engineering Helping impact investors support good projects and technologies with Technical Due Diligence and Strategic Advisory services Providing technical support and expertise to Clean Energy Programs The global impact investment market is a growing and powerful tool for implementing positive change in energy access. If you need help on this important topic, we would like to hear from you. Please contact us. ENERGY ACCESS

Aug 8, 2025 Camelot Unpacks UL 9540 – Part 1 At Camelot, reviewing the UL Listing status of battery energy storage systems (BESS) for the projects we are overseeing as an Owner’s Engineer (OE) or Independent Engineer (IE) is something our team considers a good starting place in the due diligence process. This Listing is so foundational to a successful and code-compliant BESS project that we often take it for granted that everyone understands what this important Standard entails.   Unfortunately, there is a great deal of misunderstanding about the UL 9540 Listing process, even among some engineers who are otherwise pretty familiar with BESS technologies. Missing a step in verifying the proper UL listing of the BESS on a project can have large implications. For instance, an astute authority having jurisdiction (AHJ) that notices your BESS is not properly Listed may find it is not code-compliant, causing significant delays in permitting and significant costs in addressing deficiencies with the BESS manufacturer. Moreover, a UL 9540 Listing represents the successful completion of a battery (we could not resist, of course) of tests related to safety, reliability, and performance.   Understanding Standards Most folks involved in BESS projects think they know what a Standard is, as it seems pretty self-explanatory, right? Perhaps, but once you move beyond the surface level and try to parse the difference between a “Listed”, “Certified”, and “Recognized” product, it can quickly get confusing. So, let’s address a few common misconceptions.   Misconception 1: Projects Have to Comply with Standards The rollout of new standards, like NFPA 855 and UL 9540, have undoubtedly made BESS projects safer. However, complying with these Standards is not required. Organizations like NFPA or UL have no legal authority to provide, or deny, any project a permit. Permits are issued, rather, based on Codes (e.g., Electrical Code, Building Code, Fire Code) and if the Code for your project’s jurisdiction does not incorporate one of these Standards, then the AHJ may not be able to enforce the requirement. This can happen, for instance, when a local Code has not been updated recently enough to incorporate the latest versions of relevant Standards. So, unless the Code references a particular Standard, the project does not have to comply with the Standard, at least from a permitting perspective. Fortunately, many savvy asset owners have developed their own BESS technical criteria. While these criteria are unrelated to permitting, they can be used as a condition of financing. In this way, the investment community can drive better and safer installations by holding developers to the highest current Standards (literally). Misconception 2: Standards Represent the Gold Standard of Safety and Quality Given all the time taken, and the expertise of the dozens of industry experts applied, in crafting Standards it is natural to assume that each one represents the pinnacle of current thinking in design, safety, and quality. Not so. It is best to think of a Standard as the lowest common denominator that a bunch of technical folks with often-competing priorities can agree on. Anyone that has ever got more than one engineer in a room to talk about BESS likely knows that we can be an opinionated bunch, so imagine what a room with fifty engineers is like when coming up with a new technical Standard. The results are incredible acts of service to the industry, but they are only a starting place. Complying with Standards should be a bare minimum, not a stretch goal.   Misconception 3: A BESS can “Pass” or be Listed to UL 9540A Most folks understand a Standard as something that can be “passed” or “failed”. This is an understandable interpretation, as it applies to everything from everyday household appliances to BESS equipment. Unfortunately, UL 9540A is a little different. UL 9540A is actually a testing Standard that describes how a testing laboratory is to initiate and measure the impacts of thermal runaway . In completing the tests, it is literally impossible to not destroy the BESS (/ the BESS is intentionally destroyed). If thermal runaway is not initiated through one initiation method (e.g., heating), then the test continues using other methods until thermal runaway occurs (e.g., nail penetration, overcharging). There are non-lithium-ion BESS that are not subject to thermal runaway but even these do not “pass”. Instead, at each level of testing, a higher level of testing is required unless the test results fall within a particular range . For example, if a cell is tested and does not exhibit thermal runaway, it is not required to test at the module or unit level.   Misconception 4: UL 9540 Replaces Other Battery Standards In fact, UL 9540 is carefully crafted to build on other key standards, not replace them. Though many spec sheets will list UL 9540 alongside UL 1973 or UL 1741, compliance with UL 9540 already includes many of these relevant equipment-specific Standards , such as: UL 1973 for battery cells and modules UL 1741 for inverters (such as in AC block BESS products) UL 9540A for testing thermal runaway propagation risks   Wrapping Up Part 1 Misunderstandings about UL 9540 aren’t just academic - they can cause costly delays, strained relationships with AHJs, and headaches during financing or commissioning. Clearing up the myths is the first step, but knowing exactly what UL 9540 covers, when it’s required, and how to navigate the Listing or Field Listing process is where the real project-saving insight comes in. In Part 2, we’ll take that next step: unpacking the key requirements baked into UL 9540, explaining how they connect to other Codes and Standards, and clarifying the often-misunderstood Field Listing process. If Part 1 was about avoiding the traps, Part 2 is about charting the course to a compliant, bankable BESS installation. < Back Back

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

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 Taylor Parsons Director, Technical Advisory Taylor is Camelot’s Director of Technical Advisory, and has over 10 years of experience in the energy industry. His primary focuses have been in technical due diligence, energy modeling, and analytics for solar, wind, and energy storage assets. Taylor has led some of the largest due diligence engagements for M&A on projects, platforms, and portfolios. Prior to joining Camelot, Taylor was a Team Lead and Project Manager in DNV's M&A and Energy Assessment Teams. He also supported the National Renewable Energy Laboratory's Systems Engineering team engineering and analysis for wind turbines. He has a Bachelor’s Degree in Mechanical Engineering from the Colorado School of Mines, and is actively pursuing his Executive MBA in Energy (renewables focus) from the University of Oklahoma. taylor.parsons@camelotenergygroup.com

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

Camelot Energy Group is a technical & strategic advisor to owners and investors in clean energy & energy storage projects, programs & infrastructure. We specialise in Solar, Energy Storage, Consulting, Engineering, Batteries, Due Diligence, Energy Access, Strategy, Owner’s Engineering & Advisory. GET IN TOUCH Contact Us Boston, Massachusetts hello@camelotenergygroup.com First Name Last Name Email Phone Leave us a message... Submit Thanks for submitting!

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

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

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