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WHO WE ARE At Camelot, we believe in and work towards a just, equitable, and sustainable society where everyone has access to clean and affordable electricity. 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. > Read More RT Our Round Table Shawn Shaw, PE Founder, CEO Read More Aaron King, PE Director of Programs & Policy Read More Hieu Le Chief Financial Officer Read More Jacques Cantin, PE Senior Project Manager, PE Read More Sagar Bharadwaj Project Manager Read More Lynn Appollis-Laurent, PE Director, Technical Services Read More Raafe Khan Head of Energy Storage and Emerging Markets Read More Bill Atkinson, CEM Senior Project Engineer Read More Andrew Leslie Senior Project Engineer Read More Nimisha Shah Associate Analyst Read More Taylor Parsons Director, Technical Advisory Read More Bill Coon Head of Construction Read More Mark Warner Senior Project Manager Read More Michelle Aguirre Project Manager Read More Calla Schultz Associate Project Engineer Read More

< Back Hieu Le Chief Financial Officer Hieu serves as Chief Financial Officer at Camelot, bringing deep financial and operational expertise to the role. Before joining Camelot, he was an Associate Partner at McKinsey & Company, where he advised CFOs on restructuring, finance transformation, and organizational performance. Prior to McKinsey, Hieu held direct P&L ownership at Siemens, giving him hands-on experience running operations, not just advising on them. At Camelot, Hieu leads the finance function with the same rigor and discipline he's applied throughout his career, from finance capability building to cost restructuring and reorganization. His approach is grounded in real-world execution, not just strategy on paper. Hieu's guiding principle: finance that holds up in the boardroom, and in reality. Areas of expertise: CFO agenda and finance transformation, cost restructuring and reorganization, P&L ownership and operational finance, finance capability building, global finance operations Hieu.Le@camelotenergygroup.com

OUR LATEST ARTICLES Merlin's Library Filter by Category > Subscribe Regulatory Compliance Jul 7, 2026 Analysts expect rising PPA prices as clean energy tax credits phase out > Read With the July 4 safe-harbor deadline passed, non-tax-advantaged solar projects may need PPAs in the mid-to-high $60s/MWh, up from $40-45. Jul 3, 2026 FERC issues ‘show cause’ orders to US grid operators on large load integration. > Read FERC gives PJM, MISO, SPP, CAISO, ISO-NE, and NYISO 60 days to show their tariffs can handle data center-scale loads without shifting costs to ratepayers. Jun 25, 2026 Battery Storage Incentive Landscape in New York > Read The Big Apple needs Big Batteries, too! Jun 2, 2026 Garden State Energy Storage Program (GSEP) > Read Regulatory Compliance May 27, 2026 ERCOT NPRR 1333: Is Your Inverter-Based Resource Eligible for the $25M Grid-Forming Incentive? > Read Regulatory Compliance May 6, 2026 Field Failures > Read Series of graphical lessons learned from field Quality Assurance (QA) of solar and Battery Energy Storage System (BESS) projects Energy Markets May 4, 2026 Midcontinent Independent System Operator [MISO] > Read Energy Markets Apr 27, 2026 Round-Trip Efficiency Is Not a Spec Sheet Number - It's a System Behavior Under Load > Read Why BESS efficiency claims without operating context are meaningless, and what actually drives the 15–20 point gap between lab specs and field performance Regulatory Compliance Apr 20, 2026 The Container Problem in LFP Long-Duration Storage > Read Why bigger cells don't mean proportionally more energy in a 20-foot box Energy Markets Mar 27, 2026 From lab to grid: making LDES bankable > Read The chemistry debates hide the real issues: Commercial readiness, technological advancement, operational flexibility, and market adaptation Regulatory Compliance Feb 10, 2026 Foreign Entity of Concern (FEOC) Regulations for Battery Energy Storage Systems (BESS) > Read Based on Notice 2026-15 Energy Markets Feb 4, 2026 Tired of BESS commissioning delays? Start the process earlier than you think > Read Regulatory Compliance Feb 2, 2026 PJMInterconnectivity > Read Summary of Base Residual Auction (BRA) 2027/2028 Energy Markets Dec 4, 2025 CAISO Market Operations > Read Understanding IFM, FMM and RTD in California's Energy Market Energy Markets Dec 2, 2025 SMART 3.0 - PY 26 Update > Read What's New in MA's Solar and Storage Framework Energy Markets Nov 11, 2025 ERCOT RTC + B > Read A Market Overhaul in Progress Energy Markets Nov 6, 2025 The Future of Grid - Scale Storage > Read How Technology, Market Shifts, and Design Are Redefining Energy Storage Regulatory Compliance Oct 30, 2025 NFPA 855 (2026) > Read Camelot Takes on Evolving ESS Safety Standards Energy Markets Oct 28, 2025 Smart 3.0 Is Here > Read Here's What You Need to Know Construction Aug 26, 2025 Constructability Part 2 > Read From Concept to Construction – Getting Solar Project Layout and Access Right Regulatory Compliance Aug 8, 2025 Camelot Unpacks UL 9540 – Part 2 > Read Regulatory Compliance Aug 8, 2025 Camelot Unpacks UL 9540 – Part 1 > Read Regulatory Compliance Apr 4, 2025 New U.S. Tariff Policy > Read Implications for Energy and Manufacturing Energy Markets Mar 20, 2025 New Acquisition Opportunity in MISO > Read M&A Opportunity Mar 14, 2025 New Acquisition Opportunity in ISO-NE > Read Construction Mar 10, 2025 Constructability Part 1 > Read The Critical Role of Constructability in Renewable Energy Projects Regulatory Compliance Feb 13, 2025 NERC’s New Compliance Threshold > Read What You Need to Know About the 20MW+ Requirements Energy Markets Feb 12, 2025 MA SMART Part 2 > Read Key Financial Implications for Hybrid Systems Energy Markets Jan 15, 2025 MA SMART Part 1 > Read Massachusetts SMART and Clean Peak Overview M&A Opportunity Jan 14, 2025 New Acquisition Opportunity in ERCOT > Read Energy Markets Nov 7, 2024 Part 2: VDER Revenue Stack > Read VDER Revenue Stack for Hybrid (Solar + Storage) Projects Energy Markets Oct 31, 2024 U.S. ISO/RTO Regions > Read Exploring Market Opportunities Across U.S. ISO/RTO Regions Energy Markets Oct 10, 2024 Part 1: VDER Revenue Stack > Read VDER Revenue Stack for Standalone Storage Projects Solar Availability Sep 11, 2024 Solar Availability Series Part 4 > Read Camelot’s Balanced Approach Solar Availability Aug 30, 2024 Solar Availability Series Part 3 > Read Methods for Maximization Solar Availability Aug 23, 2024 Solar Availability Series Part 2 > Read Measurements and Metrics Solar Availability Aug 15, 2024 Solar Availability Series Part 1 > Read Background and State-of-the-Industry Energy Markets Jan 30, 2024 On VDER > Read Simplifying the (Somewhat) Simplified Economics of DG Projects in New York State Subscribe Stay informed Email* Subscribe I want to receive alerts for new articles

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

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

Jul 3, 2026 FERC issues ‘show cause’ orders to US grid operators on large load integration. The Federal Energy Regulatory Commission ( FERC ( https://www.energy-storage.news/tag/ferc/ ) ) has issued show cause orders under Section 206 of the Federal Power Act to all six regional grid operators under its jurisdiction, addressing how large energy users such as data centers and manufacturing operations are integrated onto the electric grid. The orders, which received support from all five FERC commissioners, aim to ensure consumers continue to have access to reliable, affordable power as demand increases. The orders require six US regional grid operators—PJM Interconnection ( PJM ( https://www.energy-storage.news/tag/pjm/ ) ), Midcontinent Independent System Operator ( MISO ( https://www.energy-storage.news/tag/miso/ ) ), Southwest Power Pool ( SPP ( https://www.energy-storage.news/tag/spp/ ) ), California Independent System Operator Corporation ( CAISO ( https://www.energy- storage.news/tag/caiso/ ) ), ISO New England ( ISO-NE ( https://www.energy-storage.news/tag/isone/ ) ), and New York Independent System Operator ( NYISO ( https://www.energy-storage.news/tag/nyiso/ ) ) —along with their transmission owners, to respond within 60 days. They must either provide justification explaining why their current tariffs remain just and reasonable in the absence of clear and consistent provisions for large load customers, or alternatively propose changes. “What the show cause orders are telling us is that there is an underlying concern about the integration of large loads across markets - there’s a perceived risk of those costs being borne by other ratepayers,” says Raafe Khan, head of energy storage and emerging markets at Camelot Energy Group. The orders support the Secretary of Energy’s advance notice of proposed rulemaking (ANOPR) to expedite the integration of large loads onto the transmission system, which is intended to, as FERC wrote, “support the innovation economy, lead the global AI race, and reshore manufacturing jobs to the US.” Five reform categories FERC has proposed five categories of reforms that grid operators must address: Developing efficient transmission service application and study processes, including consideration of alternative transmission technologies. Preventing cost shifting and requiring transparency into transmission costs. Accommodating co-location arrangements and behind-the-meter generation. Providing new transmission services for flexible large loads. Developing a process to study generating facilities serving electrically proximate large loads and large co-located locals. Khan notes of FERC’s approach, “They’re trying to be firm with what they’re looking for with respect to the outcome, but they’re also being thoughtful about telling the RTOs and ISOs what they need to do.” “They’re basically encouraging study processes that reward technologies that have more of a deflationary impact on power pricing - things like batteries, virtual power plant (VPP) programs, and different passive and active devices that can be installed at a relatively lower cost." Timeline The orders establish a defined timeline for compliance. Grid operators have 21 days from the 18 June order (until 9 July) to intervene formally, must submit a detailed report by the end of July, and have until mid- August for tariff fillings and show cause responses. Within 30 days, RTOs/ISOs and their transmission ownersmust submit detailed information reports on how each intends to ensure adequate generation will be available to serve existing and new large loads. These reports should include any proposals under consideration to address resource adequacy for new large loads, detailed schedules of key milestones, and any ongoing stakeholder processes aimed at increasing the pace of adding generating capacity in the region. “I think some markets are ahead of other," Khan notes. SPP is kind of ahead of the game. PJM is tracking in parallel. MISO is experiencing the fastest growth in terms of data centre integration of any region. California is structurally distinct in terms of the way it operates, and then New York and ISO New England have a lower amount of urgency." Regional differences FERC recognizes that regional differences exist in the procedures and strategies implemented by grid operators and has designed the orders to reflect these variations. SPP has developed its High Impact Large Load and High Impact Large Load Generation Assessment processes, which are expedited frameworks for serving large power demand from loads such as data centers. FERC addresses co-located loads in PJM in a separate proceeding. Transmission service models differs significantly, including in CAISO, which does not offer traditional Order No.888 transmission services. The orders allow each RTO and ISO to define large loads and to create operational requirements particular to their region, while also accounting for regional differences on topics such as cost transparency, study processes, and network upgrades. Energy Storage's expanding role The orders also have implications for energy storage's role transmission planning and grid integration. “I think the show cause order is sensibly about data centers, but really what it’s about is flexibility, and batteries are one of the few technologies that can make large loads connect faster, easier to manage, less expensive for the rest of the system," says Oliver Kerr, managing director, North America at Aurora Energy Research. "What the show cause order does is provide clear guidance to ISOs for ways to enable storage to unlock the value of that flexibility." “I’m very curious to see how ISOs and RTOs embrace grid-enhancing technologies like batteries and dynamic line ratings and advanced conducting to help bring costs down,” Khan says. “With transmission costs ranging anywhere from US$1 million to US$5 million per mile of high voltage transmission, if you can mitigate that by using some of these other commercially available technologies, that’s going to cost less, be deployed faster, and allow more energy to be flowing through the grid.” Khan discusses the potential for batteries in transmission planning, “I’m curious to see how batteries become—and we’ve talked about this a lot— storage as a transmission asset, and how storage becomes part of that overall transmission planning effort.” He continues, "Because of the nature of batteries being able to charge and discharge strategically, that could open some new opportunities for battery-based developers and also opportunities on the grid to alleviate some of those congestions that we see in pockets of the grid.” Enabling storage through reform Kerr explains how the orders directly support energy storage integration, saying, “One of the challenges right now is, if you have an on-site battery at a data centre, that can reduce demand during peak hours. Grid operators essentially see data centers as a big network upgrade problem, and when they’re studying “What batteries on site allow you to do is, during peak times, reduce that maximum draw on the system, and that can reduce your effective demand," Kerr continues," One thing that this FERC order could do is encourage system operators to study both the load and the generation on site together and consider them as a package rather than as two separate things, and that can help projects get online quicker.” Kerr also highlights the potential for new market products, “ISOs and RTOs might be asked to create new products to reward batteries for that, so instead of just playing in as energy arbitrage or ancillary services, they can be rewarded for load management and the transmission benefits they provide.” Long-duration energy storage (LDES) considerations While LDES has received attention in relation to large load integration, Khan notes that market evolution will be necessary to support its deployment. “The challenge that we’ve had with LDES is that we haven't had a market price signal," Khan explains. "In markets like ERCOT, where you have plenty of one to two-hour batteries, the reason we've had so many batteries installed in that duration spectrum is because we had a price signal in the form of ancillary services. But for long duration— if you're talking in order of eight hours, 10 hours, or 12 hours, we don't have a price signal that is incentivizing that longer discharge." He continues, “The reason why the average duration of batteries today is four hours is not by accident—it’s purely because the market rewards you in that two to four-hour range.” Despite these challenges, Khan sees potential for LDES. “Long duration, because of its ability to cover not just your peak load but even around the peak load, is certainly attractive. I think that’s going to be part of the overall planning process evolution.” Kerr adds that the orders could support LDES deployment depending on implementation, “In general, this will encourage more data centers to have onsite generation that’s dispatchable. Batteries are one of the key technologies. Longer duration, depending on how the rules are designed, could favour longer duration assets and provide another revenue stream for them. It will depend exactly on how the rules are written. Do you need to be able to reduce your peak load for just an hour? Is it for a longer system stress event?" He notes that hybrid approaches are already emerging, “One thing that we’re seeing right now is data centers pair batteries with gas as well, so that the battery can ramp up very quickly, and then you’ve got gas for longer periods of needed load reduction.” Co-Location The orders address the growing trend of data centers co-locating with existing generation facilities, including nuclear power plants. FERC is asking the RTOs and ISOs to evaluate co-location of data centers with generators like nuclear, solar and wind and what rules they're going to make for electrical proximity for these large loads," Khan explains. He notes, "FERC basically told all the ISOs and RTOs that they need to adopt preliminary definitions for co-located loads and arrangements for co-location, including behind-the-meter (BTM), and whether co-located loads interconnected below generators’ maximum output should take transmission service and how the demand charges should be allocated without having them transferred over to ratepayers.” Kerr emphasises the importance of clear rules, saying “Right now, there aren’t very clear rules for what co-location looks like and how it should be treated by the grid. In asking ISOs to create clearer rules, I think it just provides a pathway to monetise the value of that flexibility that a battery can provide on site.” This issue has become more relevant as hyperscalers sign capacity agreements with nuclear power plants to secure baseload power. “The problem is that if the load is going to be BTM to the plant, then all of that transmission cost shifts over to other loads, like residential loads,” Khan says. “That’s not going to work, and that’s why I think this show cause order couldn’t come sooner, because we are seeing a lot of these hyperscalers trying to be co-located with these large generators that are already on the grid or have been retired and are coming back to life over the next few years, especially on the nuclear side." State Authority Notably, FERC’s orders do not affect the authority of states to select, site, and permit generating resources or the authority of state public utility commissions to set the rates, terms and conditions of retail electricity sales. The orders specify that while the Commission addresses cost shifting among transmission customers, states retain responsibility to ensure there is no cost shifting among retial customers. The orders are not intended to disrupt existing agreements that large loads have negotiated or are in the process of negotiating for the provision of transmission service. The orders provide that RTOs/ISOs should allow a reasonable amount of time to finalize agreements that are nearing completion when any tariff revisions are filed with the Commission. Market Leadership When asked which markets are best positioned to integrate energy storage into large load integration processes, Kerr points to ERCOT and SPP, " ERCOT is probably furthest along with this in their batch zero study process. It’s not actually covered by the FERC order, but they’ve already made a strong start, and I think they’re ahead of the game of the other markets. I think SPP is probably most advanced in terms of what it’s doing.” He adds, “As a result of this order, all ISOs will have to think through the large load interconnection process and tariffs, and the general push is to encourage flexibility, and there just aren’t many ways that data centers can do that. Batteries are one of the key options for them.” Kerr views FERC’s approach positively, noting, "FERC's role here is not to dictate exactly how each ISO should do it, but just encourage them and really force them to adopt policies, processes, and rules that they didn't have before. It really is those policies, processes, and rules that will be adopted at the ISO/RTO level that will enable the flexibility that batteries provide to be rewarded and broadly encourage flexibility for large loads. I think FERC has done its job. I think it's a really solid order." Khan believes the grid operators have the information needed to respond within the timeline provided, " I think some markets are ahead of others, and they have a lot of the data. The ISOs and RTOs need to act fast because the data center growth story cannot wait. Sometimes we see the technology comes first and regulation follows. This is very much the same way, where technology and regulation are kind of at odds a little bit, but I do believe that they have all the data that they need in order to make an informed decision." Raafe Khan < Back Back

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

Feb 2, 2026 PJMInterconnectivity The Base Residual Auction The 27/28 Reliability Pricing Model (RPM) Base Residual Auction (BRA) cleared ~ 135 GW of Unforced Capacity (UCAP) at an RTO wide cap of $333.44 per MW-day Only ~ 809 MW of UCAP did not clear due to those resources being priced above the temporary price cap of $333.44 per MW-day Note, this price cap is expected to go away in the upcoming auction in June/July 2026 For those struggling to convert, this is equivalent to $10 per kW-mo In the absence of the cap, the auction would have effectively cleared at $529.80 per MW-day (Rest of RTO) with a reserve margin of 15.1%, clearing somewhere in the range of $26.3B The RPM cleared 14.8% of Installed Reserve Margin (IRM), 5.2% below the 20% IRM. For context, the IRM is the margin required to maintain a one-day-in-10 years Loss of Load Expectation (LOLE) According to estimates, PJM is short of 6.62 GW of UCAP The Bottom Line The price came in at the FERC-approved cap, $333.44/MW-day (UCAP) for the entire PJM footprint, a slight increase (+1.3%)from the 2026/2027 Base Residual Auction . The cap, agreed to be in place for the Base Residual Auctions for delivery years2026/2027 and 2027/2028, is calculated using the accredited capacity of the PJM reference resource. The cleared supply in the auction times the clearing price totals $16.4 billion, although not all load pays this clearing price because of the impact of self-supply and bilateral contract arrangements. Generation Resource Mix The cleared resource mix in this auction includes: 43% natural gas, 21% nuclear,20% coal, 5% demand response, 4%hydro, 2% wind, 2% oil and 1% solar The latest auction results were driven by a 5,250-MW increase in PJM’s demand forecast, almost entirely driven by datacenters, and a roughly 370-MW increase in cleared “unforced capacity” compared to the last auction Reliability risk has shifted from ‘fuel security’ to ‘capacity sufficiency’ Where prior reliability concerns focused on winter gas performance, this time around, the system is short of accredited capacity itself Even perfect performance wouldn’t fix a structural MW/MWh gap Effective Load Carrying Capability Even at record capacity prices, PJM is still not able to attract meaningful storage capacity as well as large-scale renewables This is telling because if high prices are not enough to incentivize investment, the issue is less to do with cost of revenue capture , but more to do with interconnection, accreditation, and rules-based risk Clues from the Queues Based on the interconnection queue, there is ~2,500 MW of offshore wind , 914 MW of solar, 732 MW of BESS, and 569 MW of natural gas under construction at the time of writing Withdrawals took center stage in the last 12-18 mos., where we saw ~37,442 MW of solar, 35,659 MW of BESS, 21,669 MW of natural gas, 7,414 MW of hybrids, 5,117 MW of offshore wind, 3,602 MW of onshore wind exit the queue due to a variety of reasons The greatest number of withdrawals took place in PA, VA, IL, and IN, respectively By capacity, VA and MD have the most projects currently under construction, whereas from a pipeline perspective, IL, VA, and OH have the most projects currently active in the queue This underscores the fact that ne generation response continues to remain weak in PJM. The BRA is signaling scarcity and it’s not going to get better without serious reforms The auction increases the probability of an ‘out of market’ action by PJM, indicating market design as a hurdle this weakening investor confidence in RPM Load Growth PJM has flagged that one of the major drivers of the tight supply-demand balance is the increase in forecasted load , to the tune of + 5,249.9 MW, mostly attributed to large loads Summer: Projected to average 3.1% per year over the next 10-year period and 2.0% over the next 20 years Annualized 10-year growth rates for individual zones range from 0.1% to 6.3%; median of 0.7% Winter: Projected to average 3.8% per year over the next 10-year period, and 2.4% over the next 20 years. Annualized 10-year growth rates for individual zones range from 0.1% to 6.0%; median of 1.6% Some Key Takeaways There was no price discovery this auction – it hit a wall When every LDA clears at the cap, price loses locational signaling value Demand Response was the quiet winner. Required Demand Response (DR) availability increased to all hours in the year, and the calculation of the winter peak load was updated to a coincident value. This was a major driver to an increase of the ELCC value for DR from 69% in the 2026/2027 BRA to 92% in the 2027/2028 BRA If the shortfall continues for two consecutive BRAs, PJM will trigger a Reliability Backstop Auction (RBA) with prior filing with FERC This is almost certain given the large gap between supply and demand The clearing solution may be required to commit capacity resources out-of-merit order but still in a least-cost manner to ensure that all these constraints are respected. In those cases where one or more of the constraints results in out-of-merit commitment in the auction solution, resource clearing prices will be reflective of the price of resources selected out-of-merit order to meet the necessary requirements PJM submitted $0 offers for specific Reliability Must-Run units and will allocate the revenue as a credit to the associated load The Chanceford-Doubs 500 kV backbone transmission line was delayed , which significantly impacted MAAC, SWMAAC and DOM CETLs. Reach us at hello@camelotenergygroup.com for any questions! Raafe Khan < Back Back

Jul 7, 2026 Analysts expect rising PPA prices as clean energy tax credits phase out Dive Brief: Ahead of the One Big Beautiful Bill Act’s July 4 deadline for wind and solar projects to commence construction in order to capitalize on the Inflation Reduction Act’s investment and production tax credits, developers have met the occasion and safe-harbored a massive pipeline of projects, industry experts say. Crux, which provides a marketplace for the transfer of tax credits, in February estimated a 170 gigawatt pipeline of safe harbored projects. “So it’s presumably only grown over the past seven months,” Josh Price, Crux’s director of intelligence and research, told ESG Dive sister publication Utility Dive. Price, along with Camelot Energy Group Head of Energy Storage and Emerging Markets Raafe Khan, predicted that as projects are no longer eligible to qualify for IRA tax credits, the price of power purchase agreements for those projects is likely to go up. Dive Insight: “If you don’t have the ITC, you have to make that up with revenue and cost,” Khan told Utility Dive. “There’s not so much that a developer can do on cost as much as they can do to negotiate a PPA rate that is favorable, but that does push forward-looking power pricing to the higher end.” Khan said that Camelot Energy Group analyzed the difference between a tax-advantaged and a non-tax-advantaged solar asset, and found that the example case of a 200 megawatt solar facility with a 30% investment tax credit would need a PPA “in the $40 to $45 per megawatt hour range. But if you’re non-tax advantaged, no ITC basis, then you’re basically pushing mid-to-high $60s.” “That’s a 50% increase in power price alone, and that’s going to put a lot of pressure on utilities and developers,” he said. Price said that in the absence of tax credits, “that missing money has to come from somewhere to make the project pencil, and that will likely be through PPA prices, so really it’s kind of a shift from the taxpayer to the ratepayer to make up that delta.” In the meantime, however, Khan said “a healthy amount of projects” that are tax-advantaged will complete construction and be placed in service between 2028 and 2030. “I do think that solar still has a very bright future,” he said. “We don’t really see any kind of sharp drop-off coming up on Saturday, or really over the next four years,” Price said. “And one of the reasons is this has been projected or telegraphed to developers since at least the passage of [the OBBBA], so a year ago is when a lot of these decisions were made to safe harbor, to meet the construction deadlines.” The One Big Beautiful Bill Act, which President Donald Trump signed into law July 4, 2025, stipulated that wind and solar projects had to commence construction within a year of the law’s enactment to qualify for the IRA’s clean electricity production and investment tax credits, or be subjected to an end of 2027 “placed in service” deadline to be eligible. “If you miss the deadline coming up, it is highly unlikely or improbable that you will be able to get a project in the door and placed in service before December 31 [2027], unless you are just so far along from all the work you’ve done in years past that you are basically at the finish line in terms of interconnection, and that your equipment is in a warehouse just waiting to be delivered,” Khan said. “I think that is very much an outlier, I think that’s more of the exception than the norm.” Looking ahead Chris Girouard, renewable energy tax credit attorney at Bryan Cave Leighton Paisner, said in an email that after July 4, he expects “energy industry participants to focus on their safe harbored projects through the end of the decade and lobby for changes in law that reintroduce tax credits applicable to wind and solar projects.” “To the extent tax credits become available for wind and solar projects that began construction after July 4, 2026, we expect the development of those projects to quickly pick back up,” Girouard said. “Outside of the wind and solar context, we expect that the increased attention in other energy technologies will continue to grow. Specifically, we are already seeing increased interest in battery and nuclear projects.” Bryen Alperin, managing director at Foss & Co, also said he anticipates solar and wind credits possibly being “extended sometime in the next few years.” “There are plenty of safe harbored projects,” Alperin said in an email. “As we get to 2029 to 2030, we may have a shortage of solar and wind projects, but by then we expect to have ramped up volume in other technologies.” Energy storage tax credits were left unscathed by the OBBBA’s cuts to the Inflation Reduction Act, offering batteries a boost, said Price and Khan. “One thing that I feel confident in, is it’ll be a lot of storage,” Price said. “We’ve already seen a lot of storage deployment … Q1 was a record quarter.” Khan said he thinks that industry thinking could even shift from solar-plus-storage to storage-plus-solar to power data centers, “to be able to provide a firm shape to the power output of the facility, so that it can actually match the utility’s load profile or the data center’s load profile much better.” Another challenge posed by the OBBBA was its new foreign entity of concern rules, which have complex provisions and have received limited additional guidance from the U.S. Department of the Treasury so far. Khan said that although FEOC enforcement began at the start of this year, “the rules are still not clear, and everyone’s obviously talking to law firms to try to get a better sense of the lay of the land, and we are dealing with an environment where it almost seems manufactured for confusion.” Girouard said he found the guidance released in February , which offered interim safe harbor guidance for calculating a project or component’s material assistance cost ratio, was “helpful to address market concerns.” “However, the lack of guidance regarding the effective control rules continues to be challenging for the renewable energy industry,” he said. “We, along with almost all of the industry, are hoping that forthcoming guidance from the IRS on those rules is released soon and that the guidance provides a practical approach to complying with the effective control regime.” Raafe Khan < Back Back

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

Jan 30, 2024 On VDER New York has long been an active market for distributed energy resources (DERs) and community-scale clean energy projects. Camelot has supported numerous community solar projects, as well as a variety of energy storage projects and despite strong policy support for clean energy, the New York market remains one of the most complex for developers and investors. The VDER program was established to simplify and streamline the economics of smaller projects but we still find that many developers struggle with some of the nuances. In our due diligence reviews of VDER projects, we typically find a few common points of discussion: How to project some revenue streams forward past the end of VDER value streams like LSRV and DRV Forecast and assumptions for ICAP revenues Coincidence of energy arbitrage and DRV time periods Approach to modeling charging costs When modeling the revenues for purely merchant projects, Camelot uses a sophisticated toolset including an optimized dispatch model but projects with significant programmatic revenues, such as NY VDER projects, often require a more customized approach to validating revenue streams and financial model inputs. Below, we provide some background on the VDER program to help developers and investors better understand this important program. Background on VDER The “Value of Distributed Energy Resources” (VDER) program, implemented by the New York Independent System Operator (NYISO), is a novel pricing mechanism designed to value and compensate distributed energy resources (DERs), including solar, wind, and energy storage systems. This program marks a shift from the traditional net metering system, specifically for certain DERs in NYISO. Unlike its predecessor, VDER is a more intricate system that considers various factors such as the location of the resource, the timing of energy production and storage, as well as the impact on the grid and the environment. This comprehensive approach aims to provide a more precise and potentially more advantageous form of compensation for owners of DERs. The introduction of VDER is a key element in New York's broader strategy to revamp its energy system. It supports the state's efforts to increase the use of renewable energy and reduce greenhouse gas emissions, thereby aligning with state-level policies such as the Reforming the Energy Vision (REV) initiative. This initiative reflects New York's commitment to modernizing its energy infrastructure, promoting sustainable practices, and moving towards a more environmentally conscious energy landscape. Projects under the VDER program can be as large as 5 MW-AC in capacity. The value of these projects is determined by several factors, including their geographical location and the time of day or year they operate. This valuation is determined through the VDER's Value Stack, which is composed of several key components for energy storage projects: Energy Value (LBMP): This component is primarily based on the zonal day-ahead hourly location-based marginal pricing (LBMP) set by NYISO. The LBMP is influenced by several factors: Market Dynamics: The LBMP is affected by the number of generators bidding into the market. This includes the cost of fuels such as natural gas and oil, which play a significant role in setting the price. Renewable Energy Integration: The integration of renewable energy sources like solar and wind power into the grid also affects the LBMP. Typically, a higher presence of these renewable sources tends to drive down energy costs. Demand Fluctuations: Another significant factor is the fluctuation in energy demand, which varies hourly across different zones in NYISO. This demand is particularly sensitive to weather conditions, as the usage of air conditioning and electric heating systems can dramatically increase energy demand. Impact of External Factors: External factors also play a role in shaping LBMP. For instance, in 2019 and 2020, there was a notable decrease in the pricing for capacity and energy. This trend was attributed to an abundance of generating facilities, lower natural gas prices, relatively mild peak demand periods, and a reduction in energy consumption due to the COVID-19 pandemic. Within the VDER framework, a critical element impacting the Energy Value is the Charging Costs, which differ across utility territories and significantly influence net energy revenues. In regions like the ConEd Territory, encompassing New York City and Westchester, these Charging Costs are particularly variable and can change monthly. As a result, net energy revenues in these areas are often higher, but these fluctuations also present a substantial risk by potentially reducing net revenues. To optimize the financial performance of a Battery Energy Storage System (BESS) in these areas, it is essential to identify and utilize periods when charging costs are at their lowest. By charging the BESS during these optimal times, project operators can minimize charging costs and thereby maximize net energy revenues. This strategy is particularly relevant in territories like ConEd, where the impact of these charging costs is more pronounced. Capacity Value (ICAP): Known as Installed Capacity, which is an essential factor in evaluating how effectively a project mitigates energy usage in New York during the most energy-demanding days of the year. This value is closely linked to the NYISO wholesale capacity markets. The rates for ICAP are subject to fluctuations based on several factors: Increase in ICAP Rates: These rates can rise in scenarios where power plants retire or when the State experiences a high annual peak load, indicating increased demand for energy. Decrease in ICAP Rates: Conversely, ICAP rates may decline if there's an excess in power generation, such as when new power plants come online, or if the annual peak load is lower than expected, indicating a surplus in energy availability. ICAP Alt 3 rates change monthly and vary based on NYISO Load Zones. For standalone energy storage projects, the only applicable ICAP payout option is known as Alternative 3 (Alt 3). Under Alt 3, project compensation is calculated and awarded each month throughout the year. This is based on the energy injections from the peak hour of the previous summer, which are then multiplied by the monthly ICAP Alt 3 rate, expressed in dollars per kilowatt ($/kW). This approach ensures that the compensation is reflective of the actual contribution of the project to reducing peak demand, thus aligning with the core objective of ICAP in the VDER framework. Demand Reduction Value (DRV): This aspect of the Value Stack quantifies the impact of DERs on reducing the need for future grid upgrades by utilities. This value is essentially determined by assessing how much a DER project can lessen the necessity for utilities to enhance their distribution networks to handle new peak load demands. The DRV value and is locked in for 10 years and Based on Several Factors: These rates are derived from the utilities' estimated costs associated with upgrading their distribution networks to accommodate increasing peak loads. Decrease in DRV Rates: Peaks can be lowered by factors such as enhanced energy efficiency measures and declining populations. These developments could lead to a reduction in DRV rates. Increase in DRV Rates: Conversely, factors that contribute to higher peak loads, such as population growth and increased electric consumption during peak times (e.g., due to the adoption of heat pumps and electric vehicles), can lead to an increase in DRV rates. Compensation and Performance: The compensation for the DRV value is closely tied to the performance of the BESS during a predefined DRV Window. The DRV value, expressed in $/kW-yr, is calculated with the assumption that the BESS is capable of discharging at its full capacity during all the hours within the DRV Window. Variation by Utility and Region: It's important to note that both the DRV Window and the associated value can vary depending on the specific utility and the region in question. This variation reflects the differing needs and characteristics of each utility's grid and the regional differences in peak load patterns. Therefore, in the VDER framework, the DRV is a dynamic component that reflects the evolving landscape of electricity demand and supply, as well as the regional characteristics of utility grids. It plays a vital role in incentivizing DER projects that can effectively reduce the need for costly grid upgrades. Locational System Relief Value (LSRV): This value recognizes the additional benefits DERs can provide to the grid in specific utility-designated locations. Here are the key aspects of the LSRV: Project Location Requirements: To qualify for LSRV, a project must be situated in a utility-specified substation or location. Some projects might also be eligible for a Location Adder, which provides additional incentives for being in specific areas deemed crucial for grid support. Availability in Designated Locations: LSRV is accessible only in certain areas designated by utilities where DERs can offer extra benefits to the electrical grid. These areas are typically identified based on their potential for grid relief or congestion reduction. Capacity Limitations: Each designated location for LSRV has a finite amount of capacity available, measured in megawatts (MW). This means that there's a limit to the amount of DER capacity that can qualify for LSRV benefits in any given area. Minimum Call Events: Each utility is required to have a minimum of 10 call events per year. These events are opportunities for DERs to demonstrate their capacity to provide grid relief. Advance Notice: A notice of 21 hours prior will be given for these call events, and they are scheduled to occur during the DRV window. Duration of Calls: The duration of these calls will range from 1 to 4 hours. Compensation Structure: Compensation for participating in these call events is based on the lowest hourly kilowatt (kW) injection during a call window. This method ensures that DERs are rewarded based on their actual contribution to grid relief during these critical periods. The LSRV is thus an integral part of the VDER framework, incentivizing projects that are strategically located to provide maximum benefits to the grid. Through this component, the VDER program aims to encourage the deployment of DERs in areas where they can significantly contribute to grid stability and efficiency. Conclusions To conclude, each of these components plays a role in determining the overall worth of an energy storage project within NYISO’s VDER framework, reflecting its multifaceted approach to valuing DERs. If you're interested in evaluating energy storage projects in NYISO’s VDER Program, don't hesitate to reach out and say hello at info@camelotenergygroup.com . < Back Back

Oct 10, 2024 Part 1: VDER Revenue Stack Many developers and financiers rely on the Value of Distributed Energy Resources (VDER) Calculator, a freely accessible spreadsheet calculator tool ( here ) to calculate expected VDER revenues for potential projects. While this tool is freely available and relatively easy to use, we find that it can be insufficient for accurately modeling some potential revenue streams. Some potential shortcomings of an approach relying solely on the VDER calculator could include: The VDER calculator uses only a linear degradation model and a fixed round-trip efficiency value for the life of the project. In reality, degradation follows a curve and RTE also degrades over time. The VDER calculator uses historical call periods for Locational System Relief Value (LSRV), when in actual operation, an operator would act to maximize LSRV revenues by discharging coincident with Demand Reduction Value (DRV) periods. This can result in the VDER calculator under-representing LSRV revenues. Actual Location Based Marginal Pricing (LBMP) revenues are calculated at the nodal level, while the VDER calculator uses zonal-level data, which is not sufficiently granular to accurately capture true prices. ConEd revenues are calculated by Group (A-D) and these groups are not present in the VDER calculator. So, while the VDER calculator is a helpful tool for preliminary analysis, when making an investment in utility-scale BESS, it is important to supplement this initial analysis with a more detailed revenue forecast that accounts for the many additional variables present in actual operations. Like other leading BESS market analytics experts, Camelot uses an optimized dispatch model to calculate future revenues for BESS projects participating in merchant energy and ancillary services markets. However, projects with significant programmatic revenues, like NY VDER projects, often require a more tailored approach to validate revenue streams and financial model inputs, so Camelot has built out additional tools and capabilities to incorporate these revenue streams seamlessly with applicable merchant market opportunities. We provided some background on the VDER program to help developers and investors better understand this critical framework, which you can view here . Below, we have modeled the revenue stack for a 5 MW, 4-hour Battery Energy Storage System (BESS) under the VDER program for various utilities. We estimated LSRV and Installed Capacity (ICAP) revenues manually, while using an optimized dispatch model to estimate LBMP and DRV values. Figure 1 Excerpt from Camelot Q4 2024 NY Market Outlook Report Reasons for manually modeling LSRV and ICAP Alternative 3 (Alt 3) LSRV: Since the VDER Calculator does not distinguish between ConEd Groups (A-D), it can incorrectly place LSRV revenue periods outside the DRV windows for ConEd C and D Groups. In reality, these LSRV calls would correctly align with the DRV windows in each ConEd Group, therefore we have manually adjusted the LSRV periods in ConEd C and D Groups to correct for this. For example, in ConEd Group C , 2023 historical data would suggest that the LSRV period occurs from 2pm-3pm, whereas the DRV period is from 4pm-8pm. In this case, an optimized dispatch might prioritize the DRV period, resulting in no LSRV revenues. Camelot, therefore, adjusts the LSRV revenues to reflect the more likely operating scenario wherein a BESS would gain both LSRV and DRV revenues. Regions with longer DRV windows, such as RG&E, show the greatest loss in LSRV revenues due to capacity degradation in the BESS, as the systems age and become less able to fully discharge over 5+ hour DRV windows. Regions with shorter typical DRV windows or windows capturing most of their revenue within an hour or two , such as ConEd A, were less affected by BESS capacity degradation. Figure 2 Excerpt from Camelot Q4 2024 NY Market Outlook Report ICAP Alt 3: Under the VDER program, ICAP Alt 3 is the sole option for BESS projects and is considered the most lucrative ICAP variant, though this varies by region. Monthly compensation is awarded based on injections during the annual peak hour multiplied by the ICAP Alt 3 rate ($/kW), which fluctuates monthly. Additionally, all ICAP alternatives already account for an ELCC (Effective Load Carrying Capability) adjustment, eliminating the need for further capacity accreditation adjustments. Moreover, since capacity prices fluctuates on a monthly and annual basis, we modeled ICAP manually using the 2024 VDER Calculator and applied an escalation rate based on our market outlook. Key trends and insights from the above figure results The energy component is the smallest contributor to the value stack, largely due to higher charging costs in ConEd and PSEG areas, which face elevated electricity prices caused by high demand, congestion, and transmission losses. Thought energy is discharged at a higher price, too, the difference (high minus low) in price can often be modest. Capacity prices vary significantly by NYISO load zones, making it challenging to predict capacity revenues due to the volatility of auction prices across zones. Prices could decline with the addition of offshore wind, which contributes to both energy and capacity. Historically, capacity prices have been high across Zone J (ConEd NYC) and Zone K (PSEG LI), with Zone J (ConEd NYC) averaging 2.5 times higher than other zones due to expected thermal retirements and the difficulty of integrating new renewables due to land constraints. Projects located in regions with 2 PM to 7 PM DRV windows show the best results, as these times overlap with potential system peak windows. For example, DRV revenues in ConEd and PSEG regions are much higher than in other areas, with ConEd DRV revenues 7.02 times higher than the state average and PSEG DRV revenues 2.22 times higher than the state average. In the Central Hudson utility territory, LSRV does not apply. The highest LSRV revenues are observed in ConEd and PSEG, particularly in ConEd Zone A, where LSRV revenue is 3.17 times higher than the state average. PSEG’s LSRV revenues are, on average, 1.13 times higher than the state average. Conclusions In summary, the VDER revenue stack diminishes considerably when projects are located outside of ConEd and PSEG territories. Though CAPEX and OPEX costs for upstate projects may be generally lower, this is more than offset by the more lucrative revenue streams noted in this article. In calculating these revenue streams, it is important to consider the many market nuances applicable to the VDER revenue stack. The freely available VDER Value Stack Calculator, while a good initial analysis tool, may not be sufficient in all cases to estimate accurate forward revenues and our team recommends a more detailed analysis be done to support development and financing of energy storage projects in New York State. Stay tuned for Part 2, where we will discuss and compare the VDER value stack for hybrid projects under ICAP Alt 1 and Alt 2, as well as the PV Charging Only and the PV & Grid Charging considerations. 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