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OUR LATEST ARTICLES Merlin's Library Filter by Category > Subscribe 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 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 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

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 Bill Coon Head of Construction Read More Bill Atkinson, CEM Senior Project Engineer Read More Jacques Cantin, PE Senior Project Manager, PE Read More Lynn Appollis-Laurent, PE Director, Technical Services Read More Raafe Khan Head of Energy Storage and Emerging Markets Read More Mark Warner Senior Project Manager Read More Andrew Leslie Senior Project Engineer Read More Taylor Parsons Director, Technical Advisory Read More Aaron King, PE Director of Programs & Policy Read More Michelle Aguirre Project Manager Read More Nimisha Shah Associate Analyst Read More

< Back Bill Coon Head of Construction Bill is Camelot’s Head of Construction and oversees all aspects of solar and storage construction and installation quality. This work includes construction monitoring, field supervision, and QA inspection of clean energy construction projects. Bill has over 20 years in the construction field and prior to joining Camelot oversaw QA and safety for a solar construction company and spent time as a construction project manager, solar inspector, and engineer. Bill has a Bachelor’s Degree in Mechanical Engineering from Syracuse University. Bill also holds Installer, Inspector, Commissioning, and Maintenance certifications from the North American Board of Certified Energy Professionals (NABCEP) and is a licensed electrician. bill.coon@camelotenergygroup.com

< Back Nimisha Shah Associate Analyst Nimisha Shah is an Associate Analyst at Camelot Energy Group, where she focuses on researching energy markets, analyzing industry trends, and building analytical models that help support strategic and clean energy decisions. Her work involves translating complex financial, operational, and market data into clear insights that guide market positioning, business strategy, and decision-making within the evolving energy sector. She is particularly interested in how data and analytics can drive more informed and sustainable energy solutions in a rapidly changing industry. She recently earned her Master’s in Business Analytics from University of Massachusetts Amherst and holds a Bachelor’s degree in Financial Management from United States International University Africa. Her background in analytics and finance allows her to approach energy markets with both a strategic and data-driven perspective. Outside of work, she enjoys spending time in nature, exploring new food spots, and experiencing different cultures through travel and cuisine. Growing up in Nairobi gave her a strong appreciation for staying connected to nature and finding balance outside of work. nimisha.shah@camelotenergygroup.com

Mar 27, 2026 From lab to grid: making LDES bankable The grid already faces multi-hour and multi-day imbalances caused by transmission constraints, renewable intermittency, and extreme weather volatility. The rapid addition of data centers further complicates this situation, adding peak load to an already stressed grid. As the traditional 2-4 hour storage market tightens, and large-AI-based loads demand a higher degree of reliability and redundancy, long-duration energy storage (LDES) is gaining serious attention from developers, Independent Power Producers (IPPs), utilities, and investors. LDES matters now more than ever because: Renewable penetration is accelerating , leading to increased curtailment. Industrial electrification is increasing baseload demand , adding stress to transmission and distribution systems. Peak load is growing , leading to overbuilding of generation. Extreme weather is stressing grids globally , increasing the need for flexibility. Contrary to popular belief, LDES is not a future solution. The technologies exist today, but have yet to be successfully field-tested in long-term projects. When deploying LDES at scale, the deciding factors will be cost, performance, and commercial viability, which will all determine the market’s true winners and losers. The chemistry war: A distraction from the real issue Energy storage professionals have debated which chemistry or brand name is ideal for long-duration applications. This debate, while lively, is besides the point. Industry efforts should focus on technology-agnostic procurement – picking the technology that fits the use case. While most markets still anchor to the 4-hour lithium-ion benchmark, reflecting yesterday’s grid needs, intraday needs exceed 4 hours, and multi-day reliability events are increasing. Lithium currently wins on performance and experience, with ~90% round-trip efficiency, a mature bankability profile, and proven deployment at scale. However, lithium performs best for 4-hour use cases (or less) and 15-20 year technical life expectations. If efficiency, upfront capital outlay, and energy density are critical to the project, lithium-ion typically wins. But when fire safety, total cost of ownership, a fully or primarily domestic supply chain, or >8-hour discharge needs dominate, a non-lithium technology may be superior. “The longer the better” is the right answer for most LDES projects, but each deployment will have varying problems and solutions. Longer doesn’t just mean longer discharge duration, but also a longer calendar life. Duration should be defined by system need, not by lithium’s historical average, and the right chemistry cocktail should be tailored not to industry standard but to individual use cases. Scaling too fast will break things Despite record installation numbers, the long-term degradation performance of utility-scale storage remains uncertain. Most assets are underwritten on lab-based, accelerated testing, so we truly don’t understand how these systems are expected to perform between years 10 and 20 of their operating lives. The utility-scale storage industry is little more than a decade old, and no battery fleet has reached end-of-life. At this stage, decommissioning frameworks remain theoretical rather than concrete. Commissioning engineers and project managers currently rely on performance metrics documented by accelerated lab testing instead of real-world use cases and stressors. Furthermore, few asset owners of deployed projects possess true fleet-level transparency regarding battery health and key dispatch metrics. Taken together, these factors make project failure – or faster-than-promised degradation – highly likely. Depending on the project structure, some teams will catch and fix these issues over time. However, many won’t have a fix available to them due to the rapid evolution of cell form factors and subsystem hardware and software architecture. With storage remaining untested in long-term, real-world projects, industry skepticism remains a hurdle. Overcoming this will require LDES demonstrating real-world degradation performance, ease of integration, enhanced safety, lower lifecycle costs, and reliability comparable to lithium. Long-term financial viability also matters. Buyers need confidence that the supplier will be around for multiple decades to provide technical support, spare parts, and warranty response. We also need to ensure that we close the gap between economic forecasts and operational realities, and how risk is underwritten. Hopefully, with deployment and manufacturing scale, the economics will follow, making LDES the right choice for energy generation projects and facilities. Policy frameworks shape LDES deployment now, but they remain far behind Historically, ancillary service markets have been the early proving ground for energy storage around the world. Because these products reward fast response over short time windows—typically minutes to about an hour—short-duration batteries had a built-in advantage: they could follow rapid control signals and deliver frequent, shallow charge-and-discharge cycles that align well with today’s battery performance. But as growing renewable generation pushes fossil “thermal” plants further down the dispatch order and into a more backup role, the grid increasingly needs LDES to do what fast services can’t: capture excess clean energy that would otherwise be curtailed, provide resilience and flexibility during longer imbalances, and help keep the lowest-cost electricity available when it’s needed. That said, the current ancillary service market designs reward speed, not endurance. If fundamental price signals evolve to incentivize lower-cost, longer-duration assets that perform at a high reliability standard, the market will rise to the challenge. LDES needs clear market incentives. Those signals may show up over time, but capacity markets could help make long-term projects financeable now. The recent federal policy changes promoting domestic manufacturing now reshape the equation. Lithium-ion supply chains remain heavily dependent on both mining and processing outside the U.S.. With new FEOC guidance under the OBBB and tariff policy implementation, any critical mineral material that can be found domestically gains a huge homefield advantage in cost and tax credit eligibility. Many lithium alternatives in LDES, such as zinc and sodium, draw on U.S. deposits. While gaining traction, these technologies remain untested at a mass scale and still lack the affordability and performance of lithium-ion. Policy levers can accelerate innovation and encourage market adoption, and policymakers have many in the works. LDES provides essential infrastructure. As the grid incorporates more renewable energy sources and retires older fossil fuel facilities, only massive deployment and integration of LDES can guarantee grid reliability. The technology exists; companies are building it, and deployments are happening. Yet cost competitiveness, efficiency gaps, and operability at commercial scale remain real barriers. Companies that can combine cost discipline, bankability, and execution excellence will define the next era of grid infrastructure, and we need it sooner rather than later. As featured in ESS News. What's your take? Email 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

< Back Bill Atkinson, CEM Senior Project Engineer Bill is a Senior Engineer with over 17 years of experience in the renewable energy and energy storage industry. During that time, Bill has worked extensively developing and implementing rigorous quality assurance and inspection processes for clean energy incentive programs and Bill has inspected more than 530MW of PV and energy storage systems. Bill has performed hundreds of design reviews, technology evaluations, major agreement reviews, and site assessments. Bill is a Certified Energy Manager, Certified PV System Inspector, and holds a B.S. in Community and Regional Planning and Sustainable Technology from Appalachian State University. bill.atkinson@camelotenergygroup.com

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

Aug 26, 2025 Constructability Part 2 In the last Camelot Energy Group constructability article, we discussed the importance of gathering detailed topography data as it is critical to reduce costly redesigns, permitting delays, and unexpected construction obstacles and issues. In this second constructability article, we are going to go through some considerations that owners and developers need to be taking when putting together project layouts and designs to set the project up for permitting, construction, and long-term success. As we discussed in the last article, in the early stages of development, a preliminary design is typically put together using the sometimes minimal public information on hand. The goal of this initial design is to verify project feasibility, usually in the form of DC and AC system size. Where a lot of project designers go astray is that they primarily focus on module layout and creating as large of a project as possible without considering the other layout considerations that are critical for the project’s success. Doing the due diligence and putting together an accurate and realistic project should always be the goal! Even during the early stages of a project, there are specific layout considerations that should be discussed and ironed out, including site and construction access, medium voltage configurations, module layout, equipment pad locations, wetland locations and mitigations, and overall site hydrology. Site Access: The Forgotten Risk Multiplier Once a potential parcel is identified and a preliminary module layout has been put together, the project team then needs to verify how the site will be accessed for construction and long-term asset management. Project sites will also need access ahead of construction mobilization to do onsite testing for racking as well as for potential tree clearing and site work. Site access may sound simple, but without de-risking how the project will receive racking, modules, transformers, and other equipment, the project is at risk of facing multiple critical constructability issues. The first thing that needs to be considered is the location of the site’s main entrance. Even projects that are adjacent to a paved road can present challenges, including: Steep topography requiring grading or retaining walls Stream crossings and culverts needing hydraulic analysis Public utility crossings that may require additional design complexities and coordination Local DOT requirements for driveway permits, signage, or acceleration/deceleration lanes It’s important to remember that large semi-trucks, some carrying oversized loads, will need to safely turn into the project site so if the approach angle or turning radius isn’t addressed early, retrofits or access delays can quickly erode construction schedules and budget. Designing the Site Access Road Once the site entrance is located, the project’s access road needs to be laid out with construction, operations, and safety in mind. A well-designed access road doesn’t just connect points A and B it facilitates: Efficient traffic flow for potentially hundreds of daily deliveries Safe two-way traffic for large trucks Designated turnarounds for dead-ends or tight sites Clear routing to temporary laydown and permanent O&M areas Where possible, the road should follow natural contours to reduce earthwork. Additionally, early geotechnical investigations can prevent surprises during grading, particularly in regions with expansive clays, bedrock, or high groundwater tables. The design should also consider future maintenance equipment and weather impacts. Medium Voltage Routing: Hidden Cost Driver The next consideration that needs to be well thought out is how medium or high voltage will be routed and interconnected. This affects not just cost, but also the construction timeline and long-term reliability. Generally, there are two ways of routing MV cables: overhead or underground. There are pros and cons to both: Overhead lines are typically less expensive per foot and faster to install in soft or forested terrain but may require FAA filings (if near airports), additional tree clearing, and more extensive permitting. Underground lines reduce visual impact and are more protected but come with higher costs, greater trenching needs, and longer lead times on materials like duct banks or vaults. Additional onsite testing may also be required to verify sub surface conditions will be acceptable for trenching. Where feasible, routing the MV lines along the site access road reduces the number of disturbed areas, consolidates construction zones, and limits environmental impacts. This “co-location” strategy also minimizes total site clearing and road crossings, saving time, money, and permitting effort. Siting Equipment Pads with Precision Once the site access and MV routing are aligned, the focus shifts to the strategic siting of equipment pads, usually housing inverters, transformers, switchgear, and potentially Battery Energy Storage Equipment. Pads must be located with multiple variables in mind: DC home run distances : Minimize string length to reduce voltage drop and avoid oversized cabling. Voltage drop : Particularly on larger sites, both DC and AC voltage drop must be calculated during the 30% design stage to optimize cable size and verify the site configuration is cost effective. Drainage : Pads should not be sited in low areas where water naturally collects, leading to pooling, flooding, and potentially failed equipment. Like we discussed in our first constructability article, the site’s topography should be considered to avoid storm water run-off issues. Water and electricity don’t go well together! Access : These pads must remain accessible post-construction for maintenance vehicles and emergency responders. This includes making room for service clearances, crane access (for transformer/BESS replacement), and pull-off areas. Wetland and Hydrology Impacts: Early Action Avoids Late Pain Finally, no layout is complete without overlaying wetland, floodplain, and surface water data. Many projects mistakenly treat this as a permitting detail rather than a constructability issue. Ignoring hydrology can lead to: Equipment and roads placed in flood-prone areas Unforeseen permitting delays (jurisdictional waters, buffer zones, etc.) Costly re-routing of cable trenches or roads Long-term operational headaches related to erosion or access loss Construction delays and potentially expensive construction tactics Projects should engage qualified wetland consultants early and plan for buffers that not only comply with regulations but allow for construction maneuvering and long-term asset protection. Having a Civil Engineering firm put together a Storm Water Prevention Plan in parallel with the preliminary layout should be a standard task of any project’s development. Closing Thoughts and a look ahead While it's common for early-stage project designs to focus on maximizing DC and AC capacity, this singular focus often overlooks critical infrastructure and constructability elements. Without simultaneously considering site access, medium voltage routing, and strategic equipment pad siting, even the most efficient module layout can become unbuildable or result in major cost overruns. These oversights can lead to unexpected grading requirements, excessive cable runs, inefficient traffic flow during construction, and even the need for complete redesigns. Integrating these considerations ensures the design is not only optimized for energy production but also practical, buildable, and financially viable over the project's lifecycle. At Camelot Energy Group, we work with owners and developers to make sure these decisions are integrated into the layout process early, reducing project risk and setting the stage for a streamlined construction phase and long-term performance. In upcoming “Constructability” articles, we will dive deeper into other critical factors, including geotechnical challenges and how to de risk the issues that may be lurking under the surface of your next project! Stay tuned for more constructability insights from the Camelot Energy Group! Mark Warner < Back Back

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

< Back Mark Warner Senior Project Manager Mark Warner, a Project Manager at Camelot Energy Group, has over 5 years of experience in the renewable energy development and EPC contractor space. Mark has extensive background in project development, siting, energy analysis, design, construction planning, and permitting for commercial and utility-scale solar projects. Mark holds a Bachelor of Science Degree in Mechanical Engineering Technology from the University of Maine. mark.warner@camelotenergygroup.com

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