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Dec 2, 2025 SMART 3.0 - PY 26 Update The Massachusetts Department of Energy Resources (MA DOER) released their final form for the 2026 Program Year. Here’s what you need to know: The DOER began accepting SMART 3.0 applications on October 15, 2025, and since then, 191.90 MW has been submitted, with 301 applications > 25 kW and 86 applications < 25 kW Based on several factors, from the One Big Beautiful Bill Act (OBBBA) of 2025, to equipment supply chain issues, and projected load growth, the DOER revised the following elements of the draft report: PY26 Base Compensation Rates PY26 Energy Storage Multiplier PY26 Annual Capacity Block PY26 Capacity Allocations and Set Asides Capacity Block: PY2026 will have a 600 MW AC of available capacity for STGU subject to the annual cap. This is an increase from the 450 MW AC capacity in the initial draft. Per 225 CMR 28.05 (4), each EDC will be allocated at least 5% of the available capacity block and the remaining capacity will be allocated to the total retail electric load served to Massachusetts customers by each EDC. The distribution capacity for PY2026 was based on March 2026 retail electric load of each EDC. The allocations shall be as follows: Source: Camelot Energy Group 225 CMR 28.05 (5), a minimum amount of capacity is set aside for the following categories: Standalone STGUs > 25 kW and ≤ 250 kW STGUs > 250 and ≤ 500 kW Low Income Property STGUs And Community Shared Solar STGUs These set asides are allocated accordingly: Source: Camelot Energy Group Base Compensation Rates: Base Compensation Rates for STGUs > 25 kW AC were based on the levelized revenue requirements for each project based on the following inputs: Capacity factor Production degradation Installation costs Financing costs Operation and maintenance costs Project management costs Land lease costs Incremental operating and capital expense costs Based on public feedback, and an attempt to balance analysis results with the desire to avoid a significant shift in the MA solar market in the first full year of SMART 3.0 Base Compensation Rates were revised as follows: PY2026 Adders The Compensation Rate Adders for STGUs >25 kW AC were developed by comparing the average levelized cost of energy of all project types >25 kW AC for each respective adder category to a baseline value. Based on the Program Year 2026 analysis, DOER found that there was variation in whether Compensation Rate Adders for Program Year 2026 should be reduced, kept the same, or increased (see “Calculated PY26 Adder Rate” below). As with the Base Compensation Rates, based on the overall Annual SMART Program Assessment, DOER decided to maintain or increase the value of Compensation Rate Adders (see “PY26 Adder Rate” below). That said, the Compensation Rate Adders for PY2026 will be as follows: In conclusion, it is clear that federal policy and broad-based challenges in the energy value chain prompted some changes. We find that rates have mostly increased or stayed the same relative to the initial draft proposal. We see that the DOER is sending a price signal that energy storage and solar are going to be key tools in achieving state mandated energy affordability and climate-based goals. One thing is clear; Massachusetts is setting a strong example of how to fairly incentivize public and private investment in energy infrastructure with the goal of making energy affordable across customer archetypes in the Commonwealth. Raafe Khan < Back Back

Jan 15, 2025 MA SMART Part 1 Massachusetts continues to establish itself as a leader in state-level clean energy programs, and Camelot is staying closely aligned on the latest developments in the region. Developers and other players take note: Through the Solar Massachusetts Renewable Target (SMART) Program and the Clean Peak Energy Standard, the state has introduced dynamic frameworks designed to accelerate renewable energy adoption while addressing grid reliability and peak demand challenges. Here, in part 1 of our two-part series on the Massachusetts programs, we’ll set the scene with what you need to know about the programs, and will dive more deeply into the key financial implications in part 2. Massachusetts SMART Program Overview The Solar Massachusetts Renewable Target (SMART) Program is a pioneering initiative aimed at promoting solar energy adoption across the state. Managed by the Massachusetts Department of Energy Resources (DOER), the program provides long-term incentives for solar photovoltaic (PV) projects, encouraging residential, commercial and small utility scale installations up to 5MW AC. Here’s an in-depth look at its objectives, structure, and benefits. The SMART program is a feed-in-tariff program that assigns a unique energy rate to different qualifying solar projects based on system size, system type, system location, offtaker type, and associated energy storage system size. The SMART program has a total capacity of 3,200 MW AC, which is distributed among Massachusetts' three investor-owned electric distribution companies: National Grid , Eversource Energy , and Unitil . The capacity assigned to each utility is proportional to the number of customers in their service area. Generally, sites serviced by municipally-owned electric utilities are not eligible for the SMART program. Each utility’s allocated capacity is further divided into two categories: one for systems larger than 25kW AC and one for systems smaller than 25kW AC. These categories are then subdivided into 16 "capacity blocks." As SMART applications are approved, these blocks gradually fill up. Once a block is fully subscribed, it is considered at capacity, and the program advances to the next block. The incentive rate for the new block is lower than that of the previous one, declining by 4% each block. Figure 1: Summary of Capacity Blocks as of 1/9/2025. SMART Capacity Block updates are posted at www.masmartsolar.com for each utility company To determine the exact SMART tariff rate that a project is granted, the DOER determines a base compensation rate based on the system size and the current utility capacity block. Then adders are applied based on system location, off-taker type, energy storage and racking (see Figure 1). Similar to the declining capacity blocks, the adders have declining “tranches”, and as each tranche is filled at the state level, the incentive rate declines by 4%. However, the adder rates for the Agricultural, Brownfield, Canopy, Floating and Landfill Adders will be locked in at their Tranche 1 rates for the duration of the SMART program and the adder rate for the Building Mounted Adder will be locked in at the Tranche 2 rate for the duration of the SMART program as modified by order 20-145-B released by the Department of Public Utilities on 12/30/2021. Figure 2: Previous Adder Values Massachusetts DOER SMART Program – Initial Release 2018 *Significant adjustments to this table are proposed in the Straw proposal: Figure 3: Straw proposal for new adders Massachusetts DOER SMART Updates – Straw Proposal 2024 SMART and Energy Storage Under the current SMART regulations, all projects over 500kW must be coupled with an Energy Storage System (ESS).* SMART projects coupled with ESS are provided with an “energy storage adder” that ranges between 0.025 – 0.077 $/kWh. The exact adder value is dependent on the max power output of the ESS and the duration, with the maximum adder being granted to projects with 100% of the max power of the PV system and 6 hours duration and the minimum adder being granted to projects with max 25% of max PV power and 2 hour duration. The incentive of the Energy Storage adder is applied to all power generated by the system, independent of the use case of the ESS. There is a requirement that each year the ESS must be cycled a minimum of 52 times to maintain eligibility for this adder.** * The new straw proposal published 7/29/24 specifies only projects over 1MW AC will require ESS ** The new straw proposal published 7/29/24 increases this requirement to 156 cycles per year and adds the requirement that the ESS is online and able to discharge 85% of the time during summer and winter months. Figure 4: Energy Storage Adder Matrix Massachusetts Clean Peak Energy Program Overview The Massachusetts Clean Peak Energy Standard (CPS) is a first-of-its-kind program designed to encourage the use of clean energy during peak electricity demand periods. Managed by the Massachusetts DOER, the program incentivizes renewable energy systems and energy storage solutions that contribute to grid stability and reduce reliance on fossil fuel-based power during high-demand hours. How the Program Works Clean Peak Energy Certificates (CPECs): Eligible resources earn Clean Peak Energy Certificates (CPECs) by generating or dispatching energy during defined Seasonal Peak Periods and the Actual Monthly System Peak, as specified by the Massachusetts Department of Energy Resources (MA DOER). CPECs can be traded in the market to electricity suppliers required to meet clean peak compliance obligations. Various applicable multipliers align CPEC generation with time periods and resource attributes that have the highest impact. For instance, higher multipliers are assigned for summer and winter months (4x) compared to other season months (1x). The Actual Monthly System Peak is weighted disproportionately to incentivize project owners to optimize performance during the peak hour of a given month, which determines the infrastructure sizing requirements. Hybrid Solar + ESS projects that are enrolled in the SMART program can also participate in the Clean Peak program and generate CPECs. However, these projects are awarded a 0.3 multiplier for all CPECs generated, effectively derating the value of their incentive by 70%. Eligible Resources: Wind turbines with storage. Solar PV systems paired with energy storage. Standalone storage systems charged with renewable energy. Demand response resources that reduce load during peak periods. Figure 5 – Energy Storage Charging Windows for Solar-Based Charging Hours Defined Peak Periods: Peak hours are established seasonally to reflect times of highest grid demand. These periods typically occur during late afternoon to early evening hour Figure 6 – Clean Peak Season (CPS) Windows Market-Driven Prices: The value of CPECs fluctuates based on market supply and demand, providing financial incentives for participating resources. Things To Note CPEC Revenues CPEC revenues are designed to incentivize clean energy generation during peak demand periods and can apply to projects that include solar paired with energy storage systems (solar + storage), as these systems are particularly effective at delivering energy during peak periods. Standalone solar projects can still qualify for CPEC revenues, but their ability to maximize these revenues is typically limited compared to solar-plus-storage systems, which offers greater flexibility in aligning energy delivery with peak periods because storage enhances the ability to participate in the Clean Peak Standard (CPS) program. By storing solar energy and dispatching it during peak demand hours, hybrid systems can generate additional CPEC revenues, making them a financially attractive option. ACP Rate Changes The DOER has implemented significant updates to the Alternative Compliance Payment (ACP) rate as part of its emergency rulemaking. The ACP rate will remain at $45/MWh through Compliance Year 2025. However, starting in 2026, the rate will increase to $65/MWh and stay at this level until 2032. After 2032, the ACP will return to $45/MWh, where it will remain through 2050. This marks a major departure from the original regulations, which planned for a declining ACP rate, dropping to $4.96 by the end of the policy period. While the higher ACP rate is expected to boost market prices, there is still a risk of steep price drops if surpluses exceed the banking limits of load-serving entities. Figure 7 – CPS Alternative Compliance Payment (ACP) Rates Near-Term Resource Multiplier (NTRM) DOER has also introduced a new NTRM under the CPS. The NTRM will provide a 2x multiplier on CPECs for up to 50 MW of qualified energy storage systems for a duration of 10 years. To qualify, the QESS must be a standalone, front-of-the-meter system interconnected to the distribution system, with a commercial operation date between January 1, 2019, and January 1, 2027. Additionally, it must not have received a Statement of Qualification before January 1, 2025, or the Distribution Credit Multiplier. Ownership is restricted to prevent any single entity from controlling more than 50% (25 MW) of the program’s capacity. DOER released the NTRM application on January 7, 2025[SS3] . Applications submitted by January 21, 2025, will be prioritized based on interconnection service agreement dates. Any applications received after this deadline will be reviewed on a first-come, first-served basis. These updates aim to encourage the development of energy storage systems while addressing previous concerns about market pricing and resource deployment under the CPS. Conclusions Looking forward, Massachusetts aims to expand and refine the SMART & Clean Peak Program to adapt to emerging technologies and evolving market conditions. By integrating solar energy with battery storage and enhancing equitable access, the program continues to serve as a model for other states aiming to transition to a clean energy future. For those considering solar or hybrid projects in the state, the program offers a valuable opportunity to contribute to sustainability while enjoying financial benefits. Stay tuned for Part 2, where we will discuss the revenue stack for hybrid projects, containing a combination of the SMART Program & Clean Peak Program. If you're interested in assessing solar, energy storage, and/or hybrid projects in ISO-NE’s MA SMART Program, feel free to reach out to us at info@camelotenergygroup.com . About Camelot Energy Group is a technical and strategic advisor to owners and investors in clean energy and energy storage projects, programs, and infrastructure. Guided by our core values of courage, empathy, integrity, and service we seek to support the energy needs of a just, sustainable, and equitable future. Our team has experience in supporting 7+GW of solar PV and 10+ GWh of energy storage and offers expertise in technology, codes and standards, engineering, public programs, project finance, installation methods, quality assurance, safety, contract negotiation, and related topics. Our services are tailored to a providing a different kind of consulting experience that emphasizes the humanity of our clients and team members, resulting in a high-quality bespoke service, delivered with focus, attention, and purpose. Key services include: -Technical due diligence of projects and technologies -Owner’s representative and engineer support -Strategic planning -Training and coaching -Codes and standards consulting -Contract negotiation and support. < Back Back

Nov 6, 2025 The Future of Grid - Scale Storage Grid forming projects: Should developers want to design grid-forming inverters they will need to engineer their systems differently. This means that auxiliary loads and losses will be higher, and economics will need to be re-casted to account for SoC-loss during standby operation and forming operation In addition, the following challenges must be navigated: Transformer inrush control POW switching or V/f pre-flux ramp for soft energization Over-voltage issues Handling reactive power absorption Resonance and harmonics Damping network oscillations and ensuring stable short-circuit response Frequency and load pick-up challenges Stabilizing V/f during cold load pickup and staged block loading Operational sequencing Q-droop hierarchy, staged energization, etc. validated via EMT and HIL tests Synchronization issues Smooth ramping, droop control, etc. Ramp rate tuning Staged load pickup and reserve margins Raafe Khan and Shawn Shaw < Back Back

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

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

Dec 4, 2025 CAISO Market Operations CAISO Market Refresh CAISO is the second largest renewable energy market by deployment, just marginally behind TX, however, operating in CAISO isn’t trivial – the market works in a few layers, and all required capacity is procured in the DA market However, two additional balancing markets run throughout the day – the Integrated Forward Market (IFM) and the Fifteen Minute Market (FMM) Source: CAISO OASIS Data Integrated Forward Market (IFM): Bidding starts in the IFM the morning before the day starts and all operators submit bids for DA and AS for each operating hour. However, BESS with Resource Adequacy (RA) contracts are required to make bids for every hour Fifteen Minute Market (FMM): Once the day begins, FMM gets to work. Operators must submit bids 75 minutes prior to each operating hour. This is also referred to as the 75-minute lockout period FMM capacity is cleared in 15-minute increments Real-Time Dispatch (RTD): RTD works in 5-minute intervals and CAISO uses this to address sudden system wide issues like outages, demand spikes, etc. FMM awards can be adjusted in both directions in RT, and this can cause uncertainty about the immediate operating hours. It is important to note that assets with firm AS obligations must have 60-minutes of SoC in the IFM and 30-minutes of SoC in the RTM to deliver and avoid penalties. Key Market Mechanisms & Initiatives Extended Day-Ahead Market (EDAM): This is a major ongoing initiative to expand the real-time WEIM into a day-ahead market. Status: The EDAM is scheduled to launch in May 2026, with PacifiCorp and Portland General Electric as initial participants. Stakeholder workshops are ongoing to finalize tariff clarifications and implementation details. Source: U.S Energy Information Administration Flexible Ramping Product (FRP): This market mechanism is designed to manage the significant net load variability caused by high solar and wind integration. Function: It procures capacity to handle forecasted movement and uncertainty in net load (total load minus solar/wind generation) in the real-time market. Performance & Challenges: The CAISO net load can swing more than 20 GW in a single hour. While beneficial for grid stability, the FRP rarely presents consistent, high-value revenue opportunities for most battery energy storage systems (BESS) as prices are often zero due to sufficient available capacity. The Department of Market Monitoring has previously identified implementation errors in the product's demand curve calculations that resulted in under-procurement of upward capacity during critical ramps. FRP addresses real-time variability across the Western grid, with CAISO facing some of the steepest ramps Source: U.S EIA SP15 hosts nearly 75% of CAISO’s battery storage, reflecting where solar growth and ramping needs are most concentrated. This regional buildout plays a major role in shaping real-time flexibility and FRP activity across the grid. As storage scales further, SP15 increasingly influences CAISO’s price formation and operational dynamics. Source: CPUC Master Resource Database Ancillary service prices in SP15 have declined sharply as battery storage has scaled across CAISO. With increased competition, services like RegUp, Spin, and Non-Spin offer far less revenue than previous years. This shift pushes storage operators to rely more on energy arbitrage and real-time market opportunities. Source: CAISO OASIS Data With ancillary service prices declining, energy arbitrage now makes up the largest share of CAISO BESS revenue. Growing solar-driven volatility has increased DA–RT spreads, making arbitrage more valuable. As a result, storage operators rely more on price forecasting and real-time optimization to capture returns. Source: CAISO Special Data TB4 opportunities come from predictable daily price swings in CAISO, where low midday prices encourage charging and high evening prices reward discharging. This spreads-based strategy is a major revenue driver for batteries under tolling agreements. Capturing these spreads consistently requires strong forecasting, SOC planning, and real-time optimization. Source: CAISO OASIS Data California utilities and CCAs are rapidly increasing their TB4-settled procurement, growing from under 2 GW in 2023 to over 3.5 GW by 2025. TB4 contracts shift real-time operational risk from offtakers to independent power producers (IPPs). This structure gives utilities financial certainty while requiring storage operators to manage price volatility and dispatch performance. The growing adoption of TB4 highlights the market’s move toward financially settled performance-driven contracting for BESS. Source: CPUC Fillings Raafe Khan < Back Back

Aug 8, 2025 Camelot Unpacks UL 9540 – Part 2 In Part 1 of our Camelot Unpacks UL 9540 series, we tackled some of the most common misconceptions about this critical Battery Energy Storage System (BESS) Standard - misconceptions that can easily derail schedules, inflate costs, or cause compliance headaches. Now, it’s time to move from myth-busting to the nuts and bolts. In Part 2, we’ll walk through some key questions regarding the requirements baked into UL 9540, highlight when and why it’s required, and shed light on the often-misunderstood Field Listing process. Whether you’re overseeing a project, supplying equipment, or working on the financing side, this is the knowledge that keeps your BESS project both compliant and bankable. What does UL 9540 include? While no product certification is ever a perfect guarantee of safety, the UL 9540 Standard is fairly broad in its scope as it's intended for an ESS as a whole, with key tests summarized below. These tests are additional to compliance requirements related to materials, construction, software, electrical design, fire safety design, noise levels, and more. These tests are also additional to any component-level tests required. For example, UL 1973 includes about 30 different tests on the battery modules alone, covering a range of potential risks, such as overcharging, over-temperature operation, external fire exposure, and physical impacts. Table 1: UL 9540 Key Tests Test Category Test Name Description   Electrical Safety Grounding & Bonding Ensures low resistance ground path to safely handle potential fault currents   Electrical Safety Electromagnetic Immunity Ensures safety sub-systems are not subject to electromagnetic interference and electrostatic discharge.   Electrical Safety Insulation Resistance Confirms insulation provides suitable impedance to prevent unintended current flow.   Electrical Safety Dielectric Voltage Withstand Confirms the suitability of dielectric materials to prevent current flow without breakdown.   Electrical Safety Impulse Test Assesses resistance to electrical surges. Fire & Thermal Safety Thermal Runaway Propagation Requires testing according to UL 9540A, with results incorporated into the system design. Mechanical Safety Leakage Confirms no leakage occurs when stress-testing liquid coolant systems with elevated pressure levels. Mechanical Safety Strength Confirms that elevated pressure in coolant systems does not cause damage to piping and equipment. Environmental Testing Seismic Confirms no major equipment damage after simulated seismic event. Environmental Testing Salt Fog Confirms resistance to marine environments. Environmental Testing Moisture Resistance Tests to confirm that enclosures properly resist water ingress. Other Operational Tests Normal Operating Verifies that ESS components do not exceed temperature ratings during normal charge/discharge behavior. Key Subordinate Standards Compliance with UL 1973 (Batteries) Ensures battery modules meet safety and performance standards. Key Subordinate Standards Compliance with UL 1741 (Inverters) Tests the safe integration of inverters in the system.   When is UL 9540 Listing Required? Compliance with UL 9540 is required under a number of major Codes, as summarized below. Note that, as of this writing, nearly all locations within the US require compliance with at least one of the Code editions noted below (or a more recent version). There are likely a few local jurisdictions not yet enforcing these Code editions but, essentially, Listing to UL 9540 is a Code requirement nearly anywhere in the US.     Referencing Code First Version Incorporating Listing for BESS Relevant Section(s) NFPA 70: National Electrical Code 2017 706.5 NFPA 1: Fire Code 2018 Chapter 52, which requires compliance with NFPA 855 which, in turn requires UL 9540 Listing in Section 9.2.1 (2023 Edition) IFC: International Fire Code 2018 1207.3.1   Is it Acceptable to Field List a BESS to UL 9540? Certainly, this is quite common and widely accepted. In practice (and in Code) an ESS is "one or more devices, assembled together, capable of storing energy to supply electrical energy at a future time". As you can see, this goes beyond simply the ESS enclosure to include the equipment facilitating connection to the broader electrical system, such as the inverter. Most ESS manufacturers will not have an infinite combination of their product listed with each possible DC converter, inverter, and transformer. As such, Field Listing is widely required to validate the "system" meets relevant Code requirements.   How does Field Listing Work? The term "Field Listing" is a slight misnomer, as the "field" portion is only a small part of the overall review. In fact, completing the Field Listing requires considerable review of documentation and generally requires that all the components of the ESS be Listed to their own respective Standards (see summary above). The Nationally Recognized Testing Laboratory (NRTL) doing the Field Listing will review the documentation and subordinate Listing status of all the major components in order to underpin their final Field Listing. As you can see, a successful Field Listing requires that the ESS uses high quality components that are properly Listed, and the Field Listing is really just validating the site-specific combination of those components (and that those components have been installed/used per their Listing). Once complete, the NRTL will issue a Field Listing that applies only to that specific project or installation. Even if the exact same equipment is used again at another site, a new Field Listing is still required. The pathway from Code requirement to (some of) the underlying Standards is summarized in the figure below. As you can see, a simple UL 9540 Listing has a lot behind it and is a critical element in having a high quality and bankable BESS. Figure 1: Compliance Pathway   Why do the Components Need to be Listed Separately for a Field Listing? Put simply, many of the required tests to List a BESS to UL 9540 are destructive in nature and you would not want them done to your commercial project. For example: UL 9540A testing requires initiating thermal runaway (aka making the system catch fire on purpose) Vibration and Impact Resistance tests may involve damaging your enclosures Overcurrent and overvoltage tests require exposing the BESS to electrical conditions beyond its design As you can imagine, few manufacturers would be willing to honor warranties after you abuse their system in such ways. So, since we can't deliberately set projects on fire in the field, the NRTL will have to rely on the test results used to obtain other component Listings. As shown above, the DC Block is already Listed to UL 9540. In these cases, all of the most strenuous tests have already been completed and found sufficient by a NRTL and the Field Listing can really focus on the combination of components. In some cases, NRTLs may be willing to issue Field Listings based on manufacturer test reports, engineering analyses, and similar documents but this is a very risky prospect and will take considerably longer and increase the cost to the owner. Also, if the NRTL finds they don’t have sufficient basis for granting the Field Listing, they may require additional testing from the manufacturer, leaving your project in a sort of Limbo state for months, if not longer. So, while any combination of ESS components can theoretically be granted a Field Listing, it is far safer to ensure your ESS is a combination of already-Listed components. In particular, using a DC block that is Listed to UL 9540 in its own right is a great way to reduce the risk of significant costs and/or delays in the final Field Listing process. < Back Back

Mar 10, 2025 Constructability Part 1 Constructability refers to the overall ease and efficiency with which a project can be built. This directly influences both the speed of construction, and the cost required to complete the project. It encompasses various aspects of design, planning, procurement, and execution to ensure the project can be built effectively, safely, and within budget and timeline constraints. The Importance of Constructability in Solar and Battery Storage Projects When it comes to solar and battery storage projects, constructability should be considered as early as the site acquisition stage. Typically, during this phase, developers identify a potential land parcel and create a preliminary layout to assess site capacity, estimate annual energy production, and gauge interconnection feasibility using the limited information available. While this is a crucial first step, constructability concerns are often overlooked or insufficiently analyzed. This can lead to projects with critical constructability challenges advancing through the development process—resulting in wasted time and money on projects with a low likelihood of successful execution. The Camelot Energy team has extensive experience in development, engineering, procurement, and construction, allowing us to help owners and developers identify and address constructability concerns early in a project’s lifecycle. By doing so, we help mitigate late-stage issues, ensuring smoother project execution. This article is the first in a series on "Constructability," where the Camelot team will highlight common challenges and showcase solutions that enable seamless project development and construction. The Ups and Downs of Topography in Renewable Energy Projects One of the most common constructability issues we encounter during the development and construction phases is inadequate attention to topography . The terrain of a project site significantly impacts design feasibility, energy production estimates, and overall constructability. Why Topography Matters Most preliminary project layouts are created using publicly available data, which typically provides only 5’ or 10’ contour intervals. While this offers a rough idea of site conditions, it lacks the precision needed to fully de-risk a project. This limitation is particularly problematic for sites with complex terrain, dense forestation, or proximity to floodplains. For such projects, hiring a professional survey company to conduct a detailed topographic survey (with 2’ contour intervals or finer) is essential. This data enables developers and engineers to validate site conditions accurately and plan accordingly. Using Topography Data in Project Design and Development Once a detailed topographic survey is completed, the preliminary layout—including solar arrays, battery storage units, access roads, fencing, and equipment pads—should be incorporated into computer-aided design (CAD) software . By integrating this data into the design, engineers can assess site suitability and proactively address constructability challenges. At this stage, a slope analysis should be conducted to identify areas of concern. This analysis requires input from multiple disciplines, including civil, structural, and electrical engineers, construction professionals, and racking vendors . Collaboration ensures that all aspects of the project are evaluated, and risks are mitigated early. Key Topography Considerations for Constructability Civil Design Grading requirements to meet design standards Stormwater management and hydrology considerations Access road construction feasibility Equipment pad locations and elevation planning Structural Design Vendor-specific racking slope tolerances Structural calculations for stability and safety Accommodation of varying site elevations Electrical Design Trenching and underground conductor runs Placement of medium-voltage poles and guy wires for overhead lines Routing and protection of underground cables Construction Considerations Water management strategies during construction Temporary erosion control measures Site layout for construction staging areas Placement of office trailers and parking zones Operations & Maintenance (O&M) Planning Long-term vegetation management strategies Ongoing erosion control measures Why Early Topographic Analysis is Essential Topography sets the foundation for every aspect of a renewable energy project—it is the building block of successful development and project design. Identifying and addressing topographic challenges early minimizes risks, helps maintain budget and schedule discipline, and ensures that project goals are met. By taking a proactive approach, developers can avoid costly redesigns, permitting delays, and unexpected construction obstacles. Looking Ahead This article is just the beginning of our series on constructability. In upcoming articles, we will dive deeper into other critical factors affecting constructability, including geotechnical challenges, interconnection hurdles, and procurement risks. Stay tuned for more constructability insights from the Camelot Energy Group! < 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

< Back Shawn Shaw, PE Founder, CEO Shawn Shaw is the founder and CEO of Camelot Energy Group and has over 21 years of experience in the renewable energy and energy storage industry. During that time, Shawn has supported public programs in more than 10 states and acted as technical advisor to many of the largest banks and financiers in the world, providing technical due diligence, owner’s engineering, and independent engineering on well over 8 GW of solar PV and 5 GWh of energy storage projects in the US, Latin America, and Europe, ranging from design and construction of offgrid island power systems to acting as Independent Engineer for financing multiple 400MWh energy storage projects in complex US markets. Shawn has experience working with a wide variety of equipment suppliers, project developers, banks, financiers, government entities, and incentive program administrators. Shawn is a registered electrical engineer (Power Systems) in New York State and holds a B.S. in Applied Physics from Rensselaer Polytechnic Institute. Recently authored Energy Storage Systems: Based on the IBC, IFC, IRC, and NEC in collaboration with the International Code Council. shawn.shaw@camelotenergygroup.com

May 4, 2026 Midcontinent Independent System Operator [MISO] Executive Summary All zones met resource adequacy requirements across all four seasons Summer price fell 36% YoY from $666.50(2025/26) to $424.30 as new capacity additions (+5.6 GW) outpaced retirements Summer surplus recovered from 2.6 GW to4.6 GW, even as PRMR increased by 2.7 GW RBDC in year 2 performed as designed as evidenced by the fact that all seasons cleared above reliability targets. Total Offered Capacity Surplus above Initial PRMR grew 2.0 GW YoY despite PRMR rising 2.7 GW, confirming that new additions outpaced both retirements and higher requirements OMS-MISO survey had projected 1.4–6.1 GW range; actual 4.6 GW (total) / 4.7 GW(waterfall chart) fell within range All Seasons Above Target The sloped demand curve priced incremental reliability value above the minimum instead of collapsing to zero — a fundamental improvement over the prior vertical demand curve design N/C effective summer margin: 12.0%; South:9.7%. Zonal Pricing Dynamics N/C (Z1–Z7): $424.30. South Z8 & Z10:$384.10. South Z9: $412.10 (binding LCR needed more local capacity) Fall, Winter, Spring cleared at uniform system-wide prices No transmission congestion binding outside summer was observed LRZ 9 cleared at $412.10, a $28/MW-day premium over the rest of the South because it faced a binding Local Clearing Requirement, not just a PRMR shortfall This signals insufficient locally deliverable capacity and is a developer siting signal Wind and Solar are Growing But Concerns Mount in the Winter Solar is now 8.6% of summer cleared SAC Accreditation: 50% for Summer/Fall/Spring,5% for Winter. The 5% winter cap is the binding seasonal constraint - solar contributes only 0.8 GW in winter vs 12.2 GW in the summer Wind summer ELCC fell from 20.8% to 18.2%per the LOLE study - a methodology-driven decline, not a fleet reduction. Wind remains critical in winter (7.0% of winter SAC vs. 3.9% summer), filling the gap left by Solar's 5% winter accreditation. Load Growth Summer CPF rose from 122.6 GW (2025) to125.1 GW (2026) - the largest single-year jump in the dataset. PRM held flat at 7.9%; the full 2.5 GW CPF rise translated directly into a 4.8 GW increase in Final PRMR. Member submissions escalated across each survey cycle. High scenario: +7 GW by 2030(2.1% CAGR). Low: +5.5 GW (0.9% CAGR).2025 summer peak was 121 GW. Drivers: data centers, re-shore manufacturing, electrification. Without accelerating additions, 2027/28 risks scarcity-level pricing . Resource Mix Winter PRMR is 6.6 GW (4.8%) below summer. Solar's 5% winter accreditation drops its contribution from 12.2 GW(summer) to 0.8 GW (winter). Gas rises from 38.9% to 41.8% of cleared SAC Coal/Nuclear/Hydro/Oil combined has fallen30% since Summer 2016. Batteries cleared 893.8 MW in summer,870.4 MW in winter. Year-over-year trend:~50 MW (2024/25) → ~500 MW (2025/26) →893.8 MW (2026/27). Summer capacity revenue: $424.30/MW-day × 92 days × 0.95 ≈$37,084/MW-year ($37.08/kW-year). Updated GVTC hourly-discharge methodology in effect for 2026/27. Price Relief, But Still Elevated Annualized prices fell from ~$217/MW-day(2025/26) to $126.19/MW-day (2026/27 N/C) a~42% decline: 2022/23: ~$17/MW-day 2023/24: ~$6/MW-day 2024/25: ~$8/MW-day 2025/26: ~$217/MW-day ← spike 2026/27: $126.19/MW-day ← relief Still ~15x above the 2023-2025 average LSEs and retail customers will see meaningful relief but no return to pre-2025norms CONE Still Far Above Clearing Summer cleared at $424.30 vs. N/C seasonal CONE of $1,453.99/MW-day (29.2%). South CONE: $1,348.59. Annual CONE by zone:$123,250–$142,970/MW-yr New dispatchable thermal cannot be financed on capacity revenue alone Bilateral contracts and ERAS fast-track approvals remain essential ~92% of load was self-supplied or bilaterally contracted before the auction. Only 11,305.4MW of non-self-scheduled capacity cleared in summer out of 142,374.3 MW total committed Direct PRA price exposure is limited but not zero — particularly for retail-choice customers in IL, MI, OH, and other competitive states. Advantage BESSt Solar cleared 12.2 GW in summer but only 0.8 GW in winter (5% accreditation vs. 50%). Summer/winter accreditation gap creates a 15:1 capacity value imbalance. Hybrid solar + BESS structures are commercially advantaged. Future DLOL-based accreditation (in development) may shift these values At $424.30/MW-day × 92 summer days × 0.95 (four-hour credit) = $37,084/MW-year ($37.08/kW-year) in summer capacity revenue alone. Combined with energy arbitrage and ancillary services, this increasingly anchors BESS project economics DR cleared 9,099.5 MW in summer (up from 9,004.4MW) and 7,789.6 MW in winter. Cleared Load Modifying Resources (including BTMG) total 9.1 GW in summer, 7.7 GW in winter MISO's tightened DR compliance means that performance tests will be required, not mock drills. This raises the bar but rewards credible programs 2026 PRA RDBC Offer Curves Things to Watch Thank you for Reading! Kindly contact us hello@camelotenergygroup.com for any questions! Raafe Khan < Back Back

Mar 20, 2025 New Acquisition Opportunity in MISO 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 another new opportunity with our network. It’s for a portfolio of ten hybrid (Solar + BESS) projects and one standalone BESS in MISO, a region where many folks have had development and acquisition interests in projects of these kinds. This unique opportunity comprises ten hybrid projects and one standalone BESS totaling 327 MW of solar with co-located BESS + 200 MW of standalone BESS , available for sale in Illinois, Indiana, Wisconsin, and Michigan, USA. Projects are in mid-stage development. Eight of the eleven projects belong to the DPP 2022 cluster and have received their DPP1 Interconnection Cost Estimates from MISO. Initial development, including CIAs, Wetland Delineations, and Phase 1 ESAs, has been completed. The Projects benefit from long option periods of up to 10 years, providing significant flexibility in development. Geographic diversification across four states helps mitigate idiosyncratic market risks of development. Additional details are provided below. The seller is targeting to receive non-binding offers by March 28th, 2025 – please reach out now if you are interested! The seller’s preference is to transfer the ownership of the entire portfolio but is open to considering proposals for a subset of the portfolio in the interest of maximizing the value and number of projects that achieve commercial operation. Camelot Insights Camelot has recently performed diligence on several projects in MISO and we find that revenues can vary widely based on the system sizing and offtake strategy. Similar hybrid projects present a great opportunity and favorable economics in MISO; the ISO took the lead in 2024 with the highest total hybrid capacity in asset level M&A transactions compared to other ISOs/RTOs. In MISO, both Energy and Capacity account for a significant portion of the total revenue stack. Camelot recommends a thorough review of the revenue stack assumptions for the projects in this portfolio. Capacity Market: As MISO transitions to the Direct Loss of Load (DLOL) accreditation method for its capacity market, the accreditation for certain renewable resources is in flux and should be considered. The DLOL accreditation method evaluates the contributions of different resources primarily based on the availability of class-wide resources during a select set of high-risk hours. This method serves as a practical approximation of marginal Effective Load Carrying Capability (ELCC), potentially affecting how renewable and storage assets are valued within the capacity market. Energy Market : The energy market in MISO plays a crucial role in project economics due to its inherent nodal volatility. The variability in Locational Marginal Pricing (LMP) across nodes can present both risks and opportunities. Projects sited near congested nodes may experience significant price swings, which can create arbitrage opportunities for storage assets, allowing them to capitalize on price spreads. Given these factors, strategic site selection and an in-depth nodal analysis are recommended for maximizing returns in the MISO energy market. Costs & Technical Insights : Camelot also has recent data on CAPEX and OPEX applicable to the region and can perform a wholistic economic analysis of the projects to vet the seller’s assumptions. This, together with an evaluation of technology, designs, and key agreements, can help to refine your valuation and de-risk the technical aspects of the transaction. Please Reach Out Overall, this is an attractive opportunity in a very active market. If you are interested, we would be glad to put you in touch with the seller, and if you decide to pursue and need any help on the due diligence side of things, please reach out to Michelle Aguirre or Shawn Shaw, PE . Upcoming Webinar with Enerdatics Finally, stay tuned for an invite to an upcoming webinar which will be co-hosted by Camelot Energy Group and Enerdatics covering key trends in the US M&A market in 2024, including the growth of BESS and hybrid projects, and the uptick in activity in MISO. < Back Back