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

Aug 30, 2024 Solar Availability Series Part 3 Welcome back for Part 3 of Camelot’s series on solar availability, which is an appropriately-hot topic as the industry continues to mature. If you’re just joining us for the series, please checkout Part 1 and Part 2 of this series. We’ve set the groundwork with how availabilities are calculated and reported along with the current state of IE assumptions. Today we’ll touch on ways of maximizing availability (minimizing downtime). This topic could be its own series, so we’ll focus on the bigger picture. If you’re curious about Camelot’s stance on availability assumptions as an IE, be on the lookout for future parts in this series. Thank you for joining us! The most impactful sources of downtime come from major component failures such as from inverters, which put entire blocks of a system offline at the same time, although more minor events can still bring smaller portions of the site down. We’ll focus primarily on the most impactful contributors to downtime here. There are two broad, controllable factors which impact availability: The frequency of downtime events , driven by component failure rates and the need for planned maintenance. The quality of the engineering and proactive maintenance is important for this piece; and The duration of downtime events , driven by staffing, readiness of replacements, and other primarily-O&M considerations. Reducing the Frequency and Duration of Downtime Events During Operations Owners and O&M providers and can have a significant impact on both the frequency and duration of downtime events at an operational project once it’s been built. Here are a few recommendations for ensuring success: Follow a Robust O&M Agreement. The O&M agreement should be closely followed during operations, which unfortunately does not always occur. The agreement should be robust and include elements of the items below. More recommendations for O&M agreements are also included in the next section. Predictive Maintenance: Utilize data analytics to predict potential equipment failures before they occur. By analyzing trends and historical data, O&M teams can identify patterns that signal imminent issues, allowing for timely interventions. Sufficient Preventive Maintenance: Schedule regular maintenance based on equipment manufacturers' guidelines and site-specific conditions. This includes checking electrical connections and inspecting mechanical systems such as trackers. Of note, energy-based availabilities can be optimized by scheduling maintenance events during periods of expectedly-low production. The time-based availability metric might be the same, but the smaller energy loss means a higher energy-based availability. Spare Parts Management: Maintain a well-stocked inventory of critical spare parts on-site or at a nearby location. This ensures that replacements can be done swiftly without waiting for parts to be ordered and delivered. Follow manufacturer recommended list and review periodically as components may become less available over time. Strong Vendor Relationships: Collaborate closely with equipment manufacturers and vendors to gain access to the latest updates, best practices, and support services. This can also help in negotiating favorable terms for spare parts and service agreements. Third-Party Audits: Engage third-parties to review the performance of the O&M program periodically. External audits can provide fresh insights and identify areas for improvement that internal teams might overlook. Training: conduct regular staff training and testing to ensure readiness for major component failures and extreme weather events. An inverter fire which caused system-wide availabilities to drop for a significant period of time Reducing the Frequency and Duration of Downtime Events During Development O&M activities may be the most visible contributor to a Project’s operational success, but they are not everything. An ace car mechanic can still see more issues with an old, poorly-built junker than a novice will see with a durable, high-end car. Camelot encourages developers to have a mindset of ensuring long-term operational success, which leads to fewer issues and less-impactful downtime. For this, we offer a few broad suggestions: Environmental Impacts: Consider site suitability at an early stage. Evaluate potential environmental risks such as wildlife interference, extreme wind speeds, natural disasters, and erosion which could affect the project’s operation and maintenance. Durable Components : Select robust inverters, transformers, racking systems, and other components designed to withstand harsh environmental conditions and have low failure rates. This often means evaluating cost tradeoffs for more expensive components. Exceed Codes and Standards: At a minimum, ensure the project complies with all local, regional, and international standards for safety, performance, and environmental impact. Even more importantly, most EPC agreements only require code compliance, and code is not about longevity of the asset, it is about safety. As such, make sure your EPC Agreement reflects materials, methods, and design standards consistent with the planned (and financed) useful life. Access: Ensure the site has adequate access for maintenance personnel, which can impact the duration of downtime events. Make major equipment accessible near site roadways and ensure roads are wide enough to facilitate easy use of cranes and other heavy kit. Design the site to allow for spacing between components so that specialized equipment isn’t required for access and repair. Remote Monitoring Infrastructure : Deploy advanced SCADA (Supervisory Control and Data Acquisition) systems to monitor the performance of the solar farm in real-time. This allows for quick identification of issues before they lead to significant downtime. Contract with Reliable O&M providers : Developers will elect to engage with O&M providers during the later stages of development, and should do their due diligence on prospective providers to ensure they will have the right capabilities. The O&M contract should be comprehensive and include elements of the list in the prior section. A few of the most impactful items include: Availability Guarantees: The agreement should include specific availability targets. These targets set clear expectations for how often the solar plant should be operational, and should be tied to incentives to increase the chance of compliance and incentivize high availability. Maintenance Schedules and Protocols , including preventative maintenance schedules, corrective maintenance procedures, and component replacement protocols. Regular Reporting Requirements: The agreement should mandate regular performance reports, including availability, downtime events, maintenance activities, and any corrective actions taken. Transparency in reporting helps project owners monitor O&M effectiveness. For more details on ways of ensuring optimal operations at a solar project, Camelot has released a couple of related articles, including Navigating the Testing and Commissioning Process for Solar Projects , and Tips and Tricks for Procuring PV Modules in 2024 and Beyond . For quick examples of some of the more notable mistakes made in construction/operations which directly lead to lower availabilities, you can follow us on our ongoing Field Failure Series (FFS) . The next article in this series will cover Camelot’s balanced approach when advising our clients on availability expectations for our projects. In the meantime, for questions and more details about Camelot Energy Group and our distinct attitude towards these issues, please reach out at info@camelotenergygroup.com . About Camelot Energy Group is a technical and strategic advisor to owners and investors in clean energy and energy storage projects, programs, and infrastructure. Guided by our core values of courage, empathy, integrity, and service we seek to support the energy needs of a just, sustainable, and equitable future. Our team has experience in supporting 7+GW of solar PV and 10+ GWh of energy storage and offers expertise in technology, codes and standards, engineering, public programs, project finance, installation methods, quality assurance, safety, contract negotiation, and related topics. Our services are tailored to a providing a different kind of consulting experience that emphasizes the humanity of our clients and team members, resulting in a high quality bespoke service, delivered with focus, attention, and purpose. Key services include: -Technical due diligence of projects and technologies -Owner’s representative and engineer support -Strategic planning -Training and coaching -Codes and standards consulting -Contract negotiation and support < Back Back

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

< Back Mark Warner 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

< Back Raafe Khan Head of Energy Storage Raafe is Camelot's Head of Energy Storage 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

< Back Michelle Aguirre Project Manager Michelle Aguirre is a Project Manager with over 4 years of experience in managing engineering projects. Michelle has expertise in electrical safety, quality assurance, technical report writing, and project management. Michelle has supported with Technical Advisory, Owner’s Engineering, and Supply Chain services on commercial to utility-scale PV and BESS projects with construction monitoring, technology reviews, and managing the quality assurance and traceability of major equipment. Prior to joining Camelot, Michelle was a Product Safety Engineer at TUV SUD. Michelle is a registered Engineer-in-Training in the state of California and holds a B.S. in Environmental Engineering from the University of California-San Diego. She is actively pursuing the NABCEP PV Installation Professional certification. michelle.aguirre@camelotenergygroup.com

< 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 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

< Back Aaron King, PE Senior Project Engineer Aaron is a Senior Project Engineer at Camelot Energy Group and has over 10 years of experience in the solar and storage industry. Aaron works across Camelot’s Technical Advisory and Owner’s Engineering departments supporting clients on a wide variety of services. He has acted as a project manager and technical lead on different projects and portfolios at all different stages of development from M&A due diligence, design and permitting, construction monitoring, site inspections, testing & commission, and asset management. Aaron started his career designing commercial rooftop systems and solar canopies. Aaron has also worked as a technical PV consultant and owner's engineer with a range of different clients including utilities, property management companies, EPCs, municipalities, state governments, and large universities. Aaron is a licensed Professional Electrical Engineer (Power) in the state of Massachusetts and holds a M.S. in Energy Systems Engineering from Northeastern University and a B.S. in Mechanical Engineering from Johns Hopkins University. aaron.king@camelotenergygroup.com

< 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