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

Apr 20, 2026 The Container Problem in LFP Long-Duration Storage Will the LDES story for LFP be hamstrung by larger cells trying to sit in 20-foot containers? As we started to chart how cell form factors are evolving, there is an unmistakable artifact: the incremental change in usable system energy is not as much as it used to be, if these cells are to be housed in prototypical 20-foot ISO shipping containers For a typical 0.04 C use-case, we see that from 280 Ah to 314 Ah, the change in system energy is almost 45.80%; however, when we go from 1,175 Ah to 1,300 Ah, the change in system energy is only 10.40%. As OEMs push the limits from 314 Ah to 500 Ah+ form factors, they must also contend with real-estate constraints, especially because of how power and energy are coupled in Lithium-based systems. This tight coupling means cell geometry affects both thermal management footprint and C-rate flexibility. The energy density ceiling imposed by the container is increasingly the binding constraint, not the cell chemistry. We can see from the image below that, at 0.04 C, we're seeing only 287.50 kW per container at 1,300 Ah, assuming we can fit that in a 20-foot container for a typical 1,500 V architecture -looking ahead to 2,000 V architectures, the challenges compound further: higher bus voltages introduce insulation, switching, and safety certification hurdles that could slow adoption for LDES applications specifically. What's your take? Email us at hello@camelotenergygroup.com for any questions! Raafe Khan < Back Back

Feb 10, 2026 Foreign Entity of Concern (FEOC) Regulations for Battery Energy Storage Systems (BESS) Definitions Under §48E, BESS is treated as an ‘Energy Storage Technology’ or EST An EST is defined (by reference to §48 (c) (6) as property that: Receives, stores, and delivers energy for conversion to electricity Has a nameplate capacity ≥ 5 kWh Is not primarily used for transportation Includes thermal energy storage properties BESS qualifies for §48E Clean Electricity Investment Tax Credits if: It is placed in service after December 31, 2024 Construction begins after statutory termination dates It does not include material assistance from a Prohibited Foreign Entity (PFE) if construction begins after December 31, 2025 Determination is based on supplier's tax year at time of cost payments Material Assistance Cost Ratio For BESS eligibility depends on definitions under 7701 (a) (52): Total direct costs include direct material, direct labor cost of Manufactured Products (MPs) and components incorporated into the EST PFE direct costs are the portion attributable to MPS or Manufactured Product Components (MPCs) that are mined, manufactured and produced by a PFE. If MACR is below the applicable threshold, the EST includes material assistance from a PFE and is ineligible The threshold percentage are as follows: 55% in 2026 60% in 2027 65% in 2028 70% in 2029 75& in 2030 and beyond Technical Cost Components For MACR, only MPs and MPCs are included, some examples are: Battery modules Battery packs Battery cells Inverters Power conversion systems Control systems Thermal management systems Steel and iron-based structural components are excluded from MACR unless identified as MPs or MPCs Main power transformers can be ignored However, it is important to note that asset owners must focus only on a discrete number of MPs and MPCs for MACR calculations Tracking Methodologies Notice 2026-15 establishes three tracking methodologies: Individual component tracking , where each MP or MPCs is tracked to specific BESS units De-minimis assignment (10% rule), where each MP or MPCs representing < 10% of total direct costs may be assigned across facilities Averaging for small BESS (<1 MWAC) Must be of same type < 1 MWAC Placed in service same taxable year Taxpayers may average direct costs and PFE production percentage. This is especially relevant for Distributed Generation (DG)BESS portfolios Applicable Safe Harbors Two interim safe harbors apply as of the date of the notice: Identified safe harbor - Use 2023-2025 Safe Harbor Tables (Notice 2025-08) to identify and qualify and quantify MPs/MPCs Cost percentage safe harbor - Use assigned cost percentages instead of actual cost tracking (only if using identification safe harbor) It is important to note that safe harbor is: Not allowed for incremental production rule projects Excluding used property under 80/20 rule from MACR calculations Per Notice 2025-08, a grid-scale BESS is one with a name plate capacity greater than 1 MWh, where as distributed BESS shall have a nameplate capacity less than or equal to 1 MWh Qualified Interconnection Property If BESS includes qualified interconnection property: Separate MACR must be calculated If interconnection property fails MACR,BESS ITC can still be claimed but interconnection costs are excluded from qualified investment Qualified interconnection property could include network upgrade costs paid to the interconnecting utility – the IRS has recommended separate MACR calculations for these network upgrades It is imperative to work in concert with the utilities to determine cost and sourcing of equipment to accurately quantify and qualify an interconnection specific MACR The Risk of not Being Diligent If MACR is overstated, then: 20% accuracy penalty applies 1% understatement threshold instead of10% 6-year statute of limitations of MACR-related deficiencies Supplier misstatements subject to§6695B penalties That said, there is both economic and reputational risk of not being diligent about strategic sourcing The onus of traceability is solely on the developer's shoulders and goes beyond traditional checklists and CAPEX focused decision making Technical Implications Supply chain strategy Track origin of battery cells and modules carefully Avoid PFE-produced battery cells unless MACR remains above threshold Portfolio structuring Consider < 1 MW averaging rule for distributed projects Use the safe harbor cost tables where advantageous Contracting Ensure supplier certifications, but be diligent about reviewing these in detail due to potential penalties at play Avoid licensing arrangements that could trigger ‘effective control’ by PFEs Financial modeling Build MACR analysis into tax equity underwriting Model threshold compliance by construction year Future Guidance The IRS is still working on FEOC, so the current notice is one of many expected in the coming months FEOC also bans tax credits from being claimed on any project or product over a Specified Foreign Entity(SFE) has been effective control by contract Congress wrote into the statute 13 contract clauses that are leading signs of effective control to ensure non-circumvention Granting the rights to use Intellectual Property (IP) belonging to an SFE, or modifying an existing contract, on or after July 4, 2025, is automatically considered to give the SFE effective control and as such automatic disqualification from a tax-credit perspective FEOC explicitly bars any company that is a PFE from claiming federal tax credits The IRS is seeking comments on the current notice up until March 30, 2026 Reach out to us at @ hello.camelotenergygroup.com for any questions! Raafe Khan < Back Back

Jan 14, 2025 New Acquisition Opportunity in ERCOT 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 one hybrid (Solar + BESS) project in ERCOT – a region where many folks have had development and acquisition interests. A few details to highlight: Project located in Reeves County (West Hub) Point of Interconnect PV Capacity is 16.1 MWdc and BESS Capacity is 28.2 MWh (Assumed to be a 2-hour battery with an overbuild). It’s designed to participate in ERCOT as a Settlement-Only Distribution Generator (SODG) with Clip Charge and Energy Arbitrage. Solar PV will employ bifacial modules with single-axis tracker and the BESS equipment will use Li-ion technology. Interconnection is planned with Texas New Mexico Powe Company (TNMP), with a 12.47 kV voltage specification, connected to a substation, which is 0.3 miles from project to Point of interconnect. Key milestones such as the completion of Initial Assessment (IA) studies and Phase I ESA have been achieved for both sites. Due to its location, there are no county requirements for environmental permitting. Given the project size, state permitting requirements are also favorable. Lease agreements for 30+ years have been secured Approx. 70 Acres secured, possibly allowing future additional buildout Anticipated COD in Q4 2025. Camelot has recently performed diligence on, and supported the development of, several projects in ERCOT (“TX 10’s”) and we find that revenues can vary widely based on the specific node, though volatility in the region is moderate and favorable to BESS project economics. The DC-coupled configuration is somewhat unique to the market, allowing clipping capture from the solar side, but making market participation more difficult; In ERCOT, regardless of the coupling configuration, the solar and the BESS systems apply for interconnection separately. 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 good opportunities in an active market. If you are new to the ERCOT market and/or BESS considerations, feel free to check out our relevant articles: www.linkedin.com Ahead of the Curve: How to Choose Forward Curves for BESS Projects Tips For Selecting Optimal Forward Curves for Energy Storage Projects with Mina M. Hanna Last week we introduced why accurate forward curves are critical. www.linkedin.com ERCOT Auxiliary Services for Energy Storage Systems Overview ERCOT purchases ancillary services in the day-ahead market to balance the forthcoming day's electricity supply and demand on the grid and address real-time operational challenges. These services, which can be offered by either generators or consumers, allow for rapid adjustments to the electricity s www.linkedin.com Understanding BESS Augmentation in the Renewable Energy Landscape Modern Battery Energy Storage Systems (BESS) lose available energy capacity as they age and are used to store and discharge energy. As such, many asset owners must carefully consider their approach to maintaining energy capacity throughout the useful life of the BESS. 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. < Back Back

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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