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OUR LATEST ARTICLES Merlin's Library Filter by Category > Subscribe Energy Markets Dec 30, 2025 PJM Interconnection > 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

Dec 30, 2025 PJM Interconnection 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 Source : PJM THE BOTTOM LINE Source : PJM 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 years 2026/2027 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 data centers, 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 Source : PJM EFFECTIVE LOAD CARRYING CAPABILITY Source : PJM • 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 Source : PJM • 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 new 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 these 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. MARKET EVOLUTION • The Federal Energy Regulatory Commission this year also approved a PJM-proposed expansion of Surplus Interconnection Service to augment the operating efficiency and availability of existing resources, and the Reliability Resource Initiative, which attracted 11,000 MW of nameplate capacity in proposed, shovel-ready, high reliability generation projects. • PJM has also asked FERC for amendments to the rules on Capacity Interconnection Rights (CIRs) that would facilitate an expedited interconnection process to utilize the CIRs of a deactivating resource. • Recognizing that electricity demand is increasing faster than generation is being added, PJM is working on multiple fronts to further streamline the Interconnection Study processes. This includes our collaboration with Google/Tapestry, to leverage artificial intelligence to further streamline the study process and reduce study timelines. Raafe Khan < 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

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

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 Senior Project Manager Read More Lynn Appollis-Laurent Director, Owner's Engineering Read More Raafe Khan Head of Energy Storage Read More Mark Warner Project Manager Read More Taylor Parsons Director, Technical Advisory Read More Aaron King, PE Senior Project Engineer Read More Michelle Aguirre Project Manager Read More

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

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

< 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

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

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

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

Sep 11, 2024 Solar Availability Series Part 4 Welcome back for Part 4 of Camelot’s series on solar availability. If you’re just joining us for the series, here are some links to parts 1 , 2 , and 3 . We’ve set the groundwork with a summary of the ongoing validation efforts from IEs, and the resulting changes the industry is making to their assumptions. We’ll revisit their reasoning here. We’ve also described how availabilities are calculated and reported, and touched on ways of maximizing availability by minimizing downtime. If you’ve followed along with the last few parts and you’ve been waiting for our own stance as an Independent Engineer (IE), look no further! Thank you for joining us. Re-Setting the Scene Until somewhat recently, the utility-scale solar industry didn’t have the kind of established history needed to accurately predict or validate what long-term average availabilities will be at newly-proposed projects. Engineering judgement said that a relatively simple solar project would see the equivalent of about 3-5 days of total site outages per year, leading to expected availabilities of about 98.5% to 99.2%. For modeling simplicity, most everyone assumed a relatively consistent availability throughout a project’s lifetime. However, as projects became operational, the industry started to question itself. Especially early in new projects’ operational lives, downtime was high and availabilities were lower than expected due to teething issues. Even after the initial startup period, many folks started seeing trends with their average availability levels below what they had hoped. Over the last year we have started to see the beginnings of some robust data-backed approaches to redefining availability assumptions, aided by all the new operating data which is available to us. There have been three IEs who have recently updated their assumptions based on aggregated data from the projects they supported. ICF led the charge with its performance paper published by kWh Analytics in 2023. DNV and Natural Power followed suit with their own methodology updates in early 2024. Others with access to the data have weighed in as well, from NREL to kWh Analytics. Here, we focus in on the results of the IE validations, each of which took slightly different approaches and used different data sets. The table below summarizes the projects which went into the IEs’ comparisons, and some key comments from their results. We’d like to highlight a few key findings from this comparison: Every IE relied on data from monthly operating reports produced by the operators, which are rarely independently calculated or verified. As described in part 2 of this series, there is no single, standard way that availabilities are defined or reported across the industry. The conclusions from these studies should be interpreted carefully, especially because the data QC processes have not been explicitly described. DNV’s analysis used more data and resulted in recommendations which are more clearly tailored to the sites. ICF found that fixed tilt systems showed lower availabilities than tracker systems while DNV found the opposite. Despite every IE noting lower availabilities early in a project’s life, only DNV adjusted their recommendation to treat the first year differently from other years. No IE has taken a stance on availability changes later in a project’s life yet. Here is a summary of the IE’s post-validation default availability recommendations. As you can see, only DNV makes a distinction between different kinds of projects at this time, though every IE noted that they are open to changing their assumptions based on project-specific data such as operator or technology history. In practice, however, IEs are often reluctant to deviate from their standard assumptions, as this requires going out on a proverbial limb. While that conservatism is understandable, it may be producing unintended consequences. For instance, if an IE will not give “credit” for more robust technology choices or operating strategies, then owners have little incentive to consider any options but those that can be considered “bankable” at the lowest possible cost. This approach penalizes owners for considering better than baseline equipment, spending more on O&M, or otherwise looking for creative solutions to improve availability. The need for more data was a theme repeated by each company, and this will likely ring true for as long as we do this kind of work. Our availability assumptions will need to be updated regularly, just like we update our approaches to Energy Yield Analyses. Camelot’s Recommendations The Camelot team is compiling the data needed to supplement these studies and validate our conclusions, and we welcome the opportunity to work with industry partners on this effort. In the meantime, we base our own recommendations off the meta-study described above and in Part 1. Without further ado, here is our own take on availability projections: Until we have more information, we should not be differentiating between different mounting types . ICF’s and DNV’s observations contradicted each other. It’s likely other factors influenced the analyses, especially the sample sizes and quality of the input data. The factors which can impact downtime should be studied further, which means collecting more data, ensuring its accuracy, and capturing all potentially-relevant project details. In addition to mounting types, the difference between inverter technologies must be studied further as one of the primary sources of downtime observed at operating sites. For instance, the higher availability noted by DNV on smaller fixed-tilt sites than larger fixed-tilt sites may indicate a reliability advantage for string inverters over relatively small sites with central inverters. This would align with our general experience with operating sites but the data to positively confirm this is not yet available in sufficient quantity. The major sources of downtime should be studied and modeled separately . Using an overall system availability as a metric can muddy the waters significantly, especially when trying to tease out the impact of different design decisions on future performance. When performing energy yield analyses for wind energy projects, some IEs will include assumptions for balance of plant availability, grid availability, and turbine availability separately. Not only can this improve our validations (data allowing), but it will improve the way we assess technology tradeoffs at the design stage. Swapping out a more robust system for a less-robust one should impact only the downtime assumption for that system. Camelot recommends the industry work towards a bottom-up availability model based on historical failure/downtime data at the module, tracker, inverter, MV, HV, and BOS levels. These levels correspond with likely failure points within the system and provide a lowest common denominator that can be adjusted during project design to optimize expected availability. Ensuring this approach has buy-in from IEs will provide a financial incentive to specify better equipment and design better sites. Year-1 availability should be modeled separately from later years due to initial startup issues observed in each validation. Nearly all financial models are already set up to account for annually-varying losses, so adjusting our assumptions based on the clear signals we see from the data appears to be a no brainer. The industry should start modeling a ramp-down in availability later in projects’ life, as DNV may have alluded to, because component failure rates impact availability trends. Without more data, it is difficult to say the magnitude of the decreases because of the other factors at play. However, based on our experience modeling availability at other infrastructure projects, Camelot considers it reasonable to model availability as a ramp-down as a project nears the end of its design life. The “bathtub curve” shown below is an Engineering concept which supports this idea. It shows how infant mortality failures likely contributed to the observed availabilities in the first 6-12 months of operation, and highlights the further need for more operational data as projects age. This is applicable to individual components in many physical systems. Aggregated across an entire system and accounting for typical replacements and maintenance, one might expect to see a flatter availability curve, but with some consideration for early- and late-stage failures. We have seen this already with 10-15 year old PV sites, where owners struggle to obtain compatible replacement equipment that can be “dropped in” to replace original equipment onsite. As technology continues evolving quickly, we can expect new module types, inverter technologies, sensing devices, and code requirements to all play a role in the maintainability of PV sites in the late stages of their useful life. Camelot’s Balanced Approach The summary below provides a graphical representation of each IE’s default availability recommendations over time, and includes Camelot’s own recommended defaults (when no other project-specific information is available). We note the following: Camelot’s approach accounts for the size impacts observed by DNV, which appears to be a strong signal in the data, but does not differentiate between technologies until more information is made available supporting the distinction. Much like DNV, Camelot’s recommended availability starts slightly lower in year 1 before reaching steady operations, as is supported by all studies. We recommend modeling availability declines after year 20 based on several factors, including the bathtub curve concept described above, the typical useful life for major components, and our expectation that the impacts of mid-life failures will likely offset by the efficiencies gained from experience during operations. While we see this assumption as a necessary recognition of late-stage wear-out failures, it’s worth noting that its impacts on a financial model are muted by the time value of money. On average, Camelot’s assumptions are less pessimistic than ICF, and strike a balance between the assumptions reported by Natural Power and DNV. Camelot will consider quantitative adjustment to our base availability assumptions for sponsor efforts that materially result in increased reliability, such as: Demonstrating better than average historical availability for project- specific equipment (e.g., inverters) through operational data (as described in item 3 above) Adding incentives to O&M Agreements for increased availability, beyond simply guaranteed levels Purchasing extra spare parts for more vulnerable system components likely to need frequent replacing Investing in predictive analytics and above-market O&M services to reduce the frequency and severity of unplanned maintenance events While these recommendations may be Camelot’s “default” values, as an IE which cares heavily about the accuracy of our projections, we will always consider factors such as operator experience or the relative track record of the technologies deployed at each site. As the saying goes, “show us the data.” Before we close, it is important to underscore an important point. Recent reporting that indicates PV projects are falling short of expected availability is a call to action for all of us. It is a call to action for more data, better analysis, and a deeper understanding of what causes PV systems to underperform. It is, notably, not a call to action for unnuanced conservatism. Simply whacking a few points off availability is, in our view, insufficient to the task of ensuring a better-performing PV fleet and it creates blind spots. We hope our fellow IEs will join us in not simply erring on the side of conservatism but, rather, will continue to advance our knowledge of these issues and build better, and more nuanced models that reward innovation, investment, and effort. We hope you’ve found this series to be helpful, and we welcome the opportunity to partner with any of our readers who would be able to support with future efforts. Although this is the last of our solar availability series for now, we fully intend to revisit the topic in the future. For our storage-oriented audience, you can expect a similar discussion on availability assumptions for BESS technologies in upcoming articles. 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