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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. OUR SERVICES At Camelot Energy Group, our services are best defined by our clients’ needs and we approach each engagement by listening to our clients and providing a bespoke solution. With that in mind, our services generally align with the following major activities. If your needs don’t perfectly align with one of these, no worries. These are only general guidelines and you can always contact us. Owner’s Engineering Technical Due Diligence Strategic Advisory Public Program Support Owner’s Engineering (OE) Technical Due Diligence Strategic Advisory Services 01. OWNER'S ENGINEERING (OE) Today’s clean energy asset owner face a rapidly evolving technology landscape, complex technical agreements, supply chain constraints, quality control issues, and schedule risks. At Camelot, we aim to address these challenges and help our clients build more clean energy projects, secure in the knowledge that a team of experts is in their corner ensuring their projects get negotiated, designed, built, and operated to the best possible standards. Our OE clients often ask for our help with: Negotiating supply, EPC, O&M, and other major project agreements Performing technical due diligence on technology and design options Design reviews Project management Commissioning and testing support Field inspections Reporting for financiers and investors Troubleshooting performance challenges Asset management support If you would like to talk to us about your OE needs, please contact us. We look forward to meeting you and learning about your project. 02. TECHNICAL DUE DILIGENCE The market for clean energy transactions is active and growing and projects and portfolios are bought and sold almost daily. Making the choice to invest in a portfolio of greenfield or operating assets, development platform, or new technology can present a great opportunity for savvy investors but there are risks as well. As these bids become more competitive, investors need actionable technical feedback on real-world risks so they can make informed decisions. At Camelot, we have a deep understanding of the M&A process and our team has provided actionable due diligence on everything from energy storage development platforms to large utility scale solar plants and portfolios of C&I projects. Our team evaluates key areas of potential acquisitions, including: Major agreements (EPC, O&M, interconnection, offtake, and supply) Financial models Major technologies Key team members and contractors Energy models Project designs and methods Installation quality Factory QA programs Independent Engineer (IE) reports Camelot and our team members have supported the financing of over $8bn in clean energy assets for private equity, debt, and tax equity financiers, from regional banks to some of the largest financiers in the world. If you think you may need help with technical due diligence on a project, platform, or other investment opportunity, please contact us . If you already have financing and want to make sure your project is well-executed, our Owner’s Engineering services are tailored to provide that peace of mind. OE Technical Due Diligence 03. STRATEGIC ADVISORY SERVICES Many of the world’s most successful investors have identified the clean energy space as ripe for investment and are seeking to successfully enter the market or expand their position to take advantage of the global growth trends. The opportunity is vast but the competition is fierce and wasting valuable time and resources on a bad deal can set you back considerably. Whether the need is to bring your team up to speed on the latest solar and energy storage markets, technologies, and trends or to get help identifying and validating potential M&A targets, our team’s broad industry knowledge, deep relationships, and expertise can help save precious time and avoid the pitfalls of a poor investment choice. Our team provides strategic guidance related to: Leadership team briefings on solar and energy storage market and technology trends Extended trainings and boot camps to get your team up to speed quickly Support for impact investing and energy access Target identification and due diligence Technology roadmap reviews On-call expertise If your team needs help evaluating new market opportunities, please contact us . If you are ready to consider investment in projects or portfolios, you may find our technical due diligence services helpful. STRATEGIC ADVISORY SERVICES

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

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

Mar 14, 2025 New Acquisition Opportunity in ISO-NE At Camelot, we always try to keep a finger on the pulse of the solar and energy storage M&A market, as many of our clients turn to us for technical and market due diligence on these sorts of engagements. We just had a noteworthy M&A opportunity come across our desk from our friends at Enerdatics and wanted to share this opportunity with our network. It’s for a portfolio of three hybrid (Solar + BESS) project in ISO-NE, a region where many folks have had development and acquisition interests in the MA SMART + Clean peak programs. A few details to highlight: This portfolio comprises three hybrid projects totaling 15 MW of solar + 6.72 MW of BESS , available for sale in Massachusetts, USA . Each project is for sale at the Notice to Proceed (NTP) stage, with land, permits, and interconnection already secured . The projects are expected to achieve Commercial Operation Date (COD) between Q3 and Q4 of 2026 . They participate in the MA SMART and Clean Peak programs , with potential eligibility under MA SMART 3.0 . The projects qualify for the 30% federal Investment Tax Credit (ITC) and offer strong revenue potential through offtake strategies and ancillary services in ISO-NE . Offers are welcome for the entire portfolio or individual projects , with transaction closing anticipated in Q2 2025 . Camelot has recently performed diligence on, and supported the development of, several projects in MA SMART + Clean Peak Programs and we find that revenues can vary widely based on the revenue stack, BESS system sizing, and offtake strategy. Similar hybrid projects present a great opportunity and favorable economics, especially with the significant adjustments made to the adders proposed in the Massachusetts Department of Energy Resources (MA DOER) straw proposal. This is in addition to the changes made to the Alternative Compliance Payment (ACP) rate, where starting in 2026, the rate will increase to $65/MWh and stay at this level until 2032. After 2032, the ACP will return to $45/MWh, where it will remain until 2050. Camelot also has recent data on CAPEX and OPEX applicable to the region and can perform a wholistic economic analysis of the projects to verify the seller’s assumptions. Overall, depending on the quality of the development of course, this could be a good opportunity in an active market. If you are new to the MA SMART + Clean Peak Programs, we encourage you to to check out our relevant articles: Massachusetts SMART and Clean Peak Overview MA SMART Part 2: Key Financial Implications for Hybrid Systems If you are interested, we would be glad to put you in touch with our friends at Enerdatics who are tracking the deal and, of course, if you decide to pursue and need any help on the due diligence side of things, please reach out to Taylor Parsons or Shawn Shaw, PE . The Enerdatics team will also be at #Infocast2025 next week and will have other exclusive deals and insights to share. Be sure to reach out to Mohit Kaul or Kshitij N R to connect! < Back Back

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

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

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

< Back Michelle Aguirre, NABCEP PVIP Project Manager Michelle Aguirre is a Project Manager with over 6 years of experience in managing engineering projects. Michelle has expertise in electrical safety, quality assurance, technical report writing, and project management. Michelle has supported with Technical Advisory, Owner’s Engineering, and Supply Chain services on commercial to utility-scale PV and BESS projects with construction monitoring, technology reviews, and managing the quality assurance and traceability of major equipment. Prior to joining Camelot, Michelle was a Product Safety Engineer at TUV SUD. Michelle has the NABCEP PV Installation Professional certification, is a registered Engineer-in-Training in the state of California, and holds a B.S. in Environmental Engineering from the University of California-San Diego. michelle.aguirre@camelotenergygroup.com

Oct 28, 2025 Smart 3.0 Is Here SMART 3.0 is here and here’s what you need to know. 225 CMR 28.00 is the official DOER regulation (effective September 2025) that defines the technical and commercial rules for solar and storage participation under the SMART 3.0 incentive program, with the core goals of reducing greenhouse gas emissions, improving grid reliability, peak shaving, protecting land-use, and alignment with the MA 2050 decarbonization plan. The rules apply to distribution companies, and all owners, authorized agents and primary installers of Solar Tariff Generation Units (STGUs) It is important to note that participation is voluntary but binding – each participant must comply with all 28.00 requirements, or as amended by the DOER. The second enrollment period starts on January 2, 2026. The DOER assigns capacity annually by utility load share: 10% for systems 25-500 kW 10% for low-income property And 15% for community shared solar It is important to note that unused capacity does not roll over Program year 2026 will have 450 MW of available capacity for STGUs subject to the capacity cap Base compensation rates and adders will be baselined annually – it is expected to change by ~$0.01 per kWh. Fundamental calculation remains the same: Base compensation rate for program year 2025 for projects > 1 MW is $0.1729 per kWh The base compensation rate proposed for program year 2026 for projects > 1 MW is $0.1556 per kWh Adder rates are as follows: Energy Storage Adder: AC-coupled: The SMART 3.0 calculator will be made available on the mass.gov webpage. It is free to download and easy to use to determine the appropriate storage adder applicable for the project. An applicant will reserve an adder multiplier rate upon the initial application for the Energy Storage Adder. However, changes to as-built solar photovoltaic (PV) capacity or the Energy Storage System relative to the information contained in the initial application may result in an increase or decrease to the size of the Energy Storage Adder. Additional information on applying for the Energy Storage Adder is provided in the Statement of Qualification Reservation Period Guideline DC-coupled true-up: For DC-coupled STGUs with Energy Storage Systems, there are round-trip efficiency losses resulting in lower generation at the production meter. To compensate STGU owners for the AC equivalent of the renewable energy production of the STGU and to calculate the annual true-up payment of the round-trip efficiency losses, an applicant shall use the following formula: i = the number of intervals in a calendar year E i = 15-minute interval ESS DC net metered energy output η T = fixed transformer efficiency factor η INV = fixed inverter efficiency factor R P = SMART incentive rate for the STGU The Department shall establish a transformer efficiency factor that shall be fixed for all STGUs and an inverter efficiency factor that will be fixed for the specific inverter utilized by the STGU. The current established transformer efficiency factor is 2. To receive the annual true up payment, the Energy Storage System’s performance data and inverter efficiency factor must be reported to the Department. On an annual basis, the Department will calculate the annual true up payment. Once calculated, the Solar Program Administrator will provide the data to the Department for verification prior to submittal to the appropriate Electric Distribution Company for payment to the STGU Owner. Administrative process flow: Projects ≥ 1 MW must attest to or file FERC QF status under PURPA Submit a Statement of Qualification (SOQ) DOER issues preliminary SOQ – 24-month reservation period Upon interconnection authorization, apply for final SOQ with financial proofs and BESS compliance Ground-mount projects must also secure all non-ministerial permits, such as planning board and conversation commission approvals Capacity is allocated on a first-come basis (generally, first 10 business days sequenced by ISA application date Waitlist mechanism defined with 10-day response window General requirements: PV must be ≤ 5 MW AC: 10 MW AC for brownfield or landfills Delivery point must be physically in MA No active SMART 2.0 SOQ All STGUs > 1 MW AC that do not qualify for a locational adder (e.g., brownfield, landfill, dual-use, floating, etc.) must be co-located with an ESS that meet 225 CMR 28.07 (5) (e) 1 Brownfield: up to 10 MW, ISA exceptions are allowed with pre-determination from the MassDEP Canopy: must be raised so that at least 75% of area underneath be usable Dual-use Ag: trackers must be at least 8-ft for fixed tilt or 10-ft tracking; ≤2:1 DC:AC ratio (≤ 7.5 MW DC); and agricultural plan is required Floating: PFAS-free material; ≤ 50% surface coverage; ≤ 40 MW statewide cap Public entity/low-income/community shared solar: ≥ 40% allocation and ≥ 20-40% bill credit discount DOER can grant exceptions on a case-by-case basis for good cause, like transmission constraints or non-viable interconnection ESS must be at least 2 hours in discharge duration, at least 65% RTE at the POI, and must demonstrate > 52 cycles per year with proper metering (15-minute intervals) and reporting (1Y historian) The ESS must also be at least 25% capacity of the PV plant Land-use controls and mitigation fee (§ 28.08-28.09) Replaces “greenfield subtractor” with a project-specific Mitigation Fee for ground-mount > 250 kW on undeveloped land. Fee calculated per acre based on habitat, prime farmland, and carbon-risk layers (Bio Map, MassGIS datasets). 25% is due at the time of SOQ application, balance at Final SOQ; refundable if project is canceled or site reclaimed. SMART 3.0 represents a significant evolution in Massachusetts’ approach to distributed solar and storage, bringing clearer requirements, stronger land-use protections, and incentive structures aligned with long-term decarbonization goals. As developers, owners, and installers prepare for the 2026 program year, understanding the regulatory updates and technical obligations will be critical to securing capacity and maximizing project value. With careful planning and proactive compliance, participants can successfully navigate SMART 3.0 and contribute to a more resilient, clean, and reliable energy future for the Commonwealth. Raafe Khan, Shawn Shaw < Back Back

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

Jun 2, 2026 Garden State Energy Storage Program (GSEP) Phase 1, Tranche 2 The Garden State Energy Storage Program is a New Jersey state initiative created under the Clean Energy Act of 2018, which requires New Jersey to deploy 2,000 MW of energy storage by 2030. Phase 1 focuses on large-scale, transmission-connected battery storage projects and uses a competitive bidding process. Tranche 1 wrapped up in early 2026 with awards to three projects totaling 355 MW. Tranche 2 was launched on March 4, 2026, to procure the remaining 645 MW needed to hit the 1,000 MW Phase 1 target. It was also directly triggered by Governor Sherrill's Executive Order No. 2, which declared a utility affordability emergency and directed the BPU to open Tranche 2 within 45 days of January 20, 2026. The program is funded through the BPU's existing Clean Energy Program budget and Orsted Settlement funds - no new charges will be added to ratepayer electric bills. In fact, BPU analysis found that in most scenarios the capacity savings generated by Tranche 2 projects will exceed the cost of the incentives, making the program a net financial benefit to ratepayers. Who Can Apply? Private and government entities only - electric distribution companies are not eligible Project must be at least 5 MW AC of installed capacity The project must be physically in New Jersey and connected to the PJM transmission network Standalone storage projects and storage paired with solar or other Class I renewable energy resources are eligible Storage paired with solar cannot be received or plan to receive incentives from the Successor Solar Incentive (SuSI) Program for the same storage capacity All commercially available battery technologies are eligible Equipment must be new as projects that have already started construction are not eligible Incentive Structure Winners receive a fixed annual incentive payment per MW of effective nameplate capacity, paid out over 15 years Bids are submitted in $ per MW of effective nameplate capacity and projects are ranked in ascending order of their relative costs Annual payments are tied to dispatch availability - projects must be available for dispatch at least 7,900 hours per year to receive their full payment and are also adjusted downward if the project loses storage capacity due to battery degradation over time Application Process There are two stages to the application process: Stage 1 - Pre-Qualification Submit a Pre-Qualification Request showing the project meets basic eligibility and maturity requirements BPU Staff reviews the submission and notifies applicants of any deficiencies Applicants are given the opportunity to correct deficiencies before the final deadline Stage 2 - Final Application and Bid Submit a complete Final Application along with your incentive bid price Must be submitted by August 7, 2026 Documents Required Proof of site control (lease agreement or property title) Detailed permitting plan, including an execution plan for any permits not yet secured at the time of submission Financial documentation showing the ability to fund construction Evidence of PJM interconnection progress along with path towards interconnection prior to the cliff date Safety and code compliance assurances, including NFPA 855 compliance and UL 9540 certification Year-by-year DC and AC degradation projection for the project's operational lifespan Non-refundable application fee of $200 per MW of nameplate capacity Application Process Additional considerations: Projects on brownfield sites or serving overburdened communities should include relevant supporting documentation, as these factors can positively influence the Board's award decisions Resources: All forms and instructions are posted at cleanenergy.nj.gov/programs/energy-storage/garden-state-energy-storage-program-phase-1-tranche-2 Questions can be submitted to energy.storage@bpu.nj.gov Answers are posted publicly on a rolling basis for all applicants and the public to view Dates to Remember Applicants can submit materials up until August 7, but only those who pre-qualify by June 10 are guaranteed a deficiency review and chance to correct issues before the final deadline. After August 7, no changes are accepted. All bids remain valid for nine months from that date. What's Next? After an Award Winners have 30 days from receiving their award letter to: Register with the BPU Submit a milestone report with estimated dates for: Financial closing Start of construction Planned Commercial Operation Date (COD) Guaranteed Commercial Operation Date (COD) Construction cannot begin until the BPU issues a conditional approval following a complete registration review Delay Penalties: Projects that miss their planned COD are penalized $1,000 per MW per day of delay The Division Director can grant extensions of up to 180 days for good-faith delays Extensions beyond 180 days are only granted in the case of a documented force majeure event Risk of Losing the Award: Projects that miss their guaranteed COD by 36 months risk having their incentive award revoked entirely The Board may waive this penalty if the applicant demonstrates good cause in writing Raafe Khan < Back Back