Status:
Launching
Key Timelines
RFP Open
July 31, 2025
Questions Due
August 21, 2025
Proposals Due
September 10, 2025
December 9, 2025
As Massachusetts prepares to launch its first large-scale procurement for mid-duration energy storage under Section 83E, developers and energy stakeholders have responded in force. The 2025 RFP represents a critical moment in the state’s decarbonization efforts, with a goal of deploying 1,500 MW of storage that supports environmental attributes through the Clean Peak Standard.
To ensure a competitive and effective program, more than a dozen developers and public officials submitted detailed comments to the Department of Public Utilities. Their feedback reveals consistent themes—such as concern over restrictive eligibility requirements and inflexible contract terms—as well as thoughtful recommendations for strengthening market access, financing certainty, and deployment speed. Below is a breakdown of the most pressing topics raised in the public comments, organized by theme with representative excerpts from each party.
🔹 Summary
Several commenters strongly oppose the current RFP requirement that only projects ≥40 MW and connected at the transmission level are eligible to participate. Developers argue that this restriction undermines competition, excludes viable distributed-scale and mid-sized storage projects, and hinders Clean Peak compliance by limiting the pool of qualifying resources. They recommend broadening eligibility to include distribution-connected, retail-level, and smaller-scale storage projects that meet technical standards and provide localized grid and reliability benefits.
Excerpts by Commenter
Nexamp
“We strongly urge DOER and the filing parties to expand the procurement scope by removing the minimum 40 MW requirement and allow any transmission interconnecting storage project to participate... This approach is inherently anti-competitive and risks excluding valuable projects that could otherwise provide cost-effective services.”
ENGIE
“ENGIE is specifically concerned with the 40 MW transmission-level connection minimum requirements for resources to be eligible to bid into the RFP. This requirement will impact ENGIE’s, and other distributed BESS developers’… ability to participate in the RFP and to contribute to the development of BESS in the Commonwealth.”
New Leaf Energy
“We urge the RFP Drafting Parties to reconsider the decision to limit the Round 1 Solicitation to resources 40MW and above… Distribution-connected storage can provide a range of ratepayer benefits, however without access to long-term contracts it is not possible to finance the construction of these resources.”
Longroad Energy
“The draft Section 83E 2025 RFP… includes a requirement that all projects must meet the Capacity Capability Interconnection Standard (or equivalent). This requirement was included in prior solicitations… however it does not seem to be appropriate for a procurement limited to environmental attributes.”
Jupiter Power
“Jupiter respectfully urges the evaluation and selection teams to give final ISO-NE studies significantly more value over studies that are preliminary and/or conducted by third parties… Projects should not be penalized simply for interconnecting at a distribution-level or being under 40 MW if they meet all Clean Peak delivery requirements.”
Rhynland Energy
“Rhynland recommends against a firm Commercial Operation Date deadline or, at a minimum, provides flexibility for extended timelines to construct interconnection facilities and network upgrades that are beyond the control of the developer.”
🔹 Summary
A major point of contention is the RFP’s requirement that projects must meet the Capacity Capability Interconnection Standard (CCIS), effectively excluding projects seeking to interconnect via Surplus Interconnection Service (SIS). Developers and advocacy groups argue that SIS provides a cost-effective, lower-impact, and faster pathway to interconnection and should be allowed, especially since the 2025 RFP is limited to environmental attributes, not capacity. In contrast, the Independent Evaluator and some policymakers emphasize that CCIS ensures deliverability, fairness in evaluation, and avoids modeling complexities under current time constraints.
Excerpts by Commenter
Longroad Energy
“The draft Section 83E 2025 RFP… includes a requirement that all projects must meet the Capacity Capability Interconnection Standard (or equivalent)… [but] it does not seem to be appropriate for a procurement limited to environmental attributes… Including a CCIS requirement in a CPEC-only RFP is expected to significantly reduce the pool of projects that can submit conforming bids and raise the bid prices.”
JERA Americas
“JERA agrees that a technical conference to explore the benefits of Surplus Interconnection Service would be beneficial… so long as it does not cause undue delay to the overall procurement process or prevent the inclusion of SIS as a qualifying interconnection option in this solicitation.”
Power Advisory
“In the IE’s opinion requiring projects to connect at a CCIS better accommodates the objectives of ensuring consistency in the evaluation process and achieving the aggressive schedule outlined in the RFP… [SIS] would require the use of a market simulation model to assess congestion, which could significantly extend evaluation timelines.”
Chair Mark Cusack (Public Official)
“As the RFP is currently written, SIS is not allowed. This is because the 83E RFP requires that these battery storage systems have a Capacity Capability Interconnection Standard… Stakeholders have said that it appears inappropriate to place the high deliverability requirements of CCIS on the 2025 83E solicitation.”
Longroad Energy
“Longroad wishes to express support for the request made in the initial comments… for a technical conference on the interconnection requirements… Multiple commenters raised concerns related to the CCIS requirement… A technical conference would provide an opportunity for a review of the suitability of such a requirement.”
🔹 Summary
Many developers express concern over the RFP’s requirement for fixed, non-adjustable pricing, regardless of future changes in federal tax incentives (e.g., ITC), import tariffs, or other macroeconomic conditions. They argue this exposes projects to material risk, discourages participation, and leads to inflated bids or project attrition. Several commenters recommend implementing a price adjustment mechanism or indexed repricing, similar to offshore wind procurements (e.g., MA 83C IV), to ensure project viability and cost-effectiveness for ratepayers.
Excerpts by Commenter
Flatiron Energy
“Flatiron respectfully requests that DPU include a one-time price adjustment mechanism to account for material changes in inflation, tariff policy, and federal tax or other policy regimes… Without such a mechanism, bidders may either overprice bids or be unable to build awarded projects, leading to attrition.”
Longroad Energy
“The current unprecedented political uncertainty around potential changes in federal tax credits and import tariffs makes it very difficult for developers to fully absorb the risk of future changes in law… We recommend allowing contractual provisions to deal with potential future changes in the federal laws… such as price adjustments subject to caps.”
Jupiter Power
“Federal policy uncertainty may significantly raise the cost of developing an energy storage system… Jupiter urges DOER and the Filing Parties to amend the RFP to include a price protection adjustment mechanism, similar to the mechanism employed in the most recent offshore wind RFP (Section 83C IV).”
Rhynland Energy
“Rhynland recommends the procurement provide a mechanism for repricing bids in the event there are material changes in law, such as modifications to federal tax credit rates (or eligibility) and tariff rates… Without a repricing mechanism, projects may prove to be economically unviable.”
🔹 Summary
Several commenters critique the RFP’s current 80/20 scoring split between quantitative (price) and qualitative factors. They argue this structure undervalues project maturity, which is critical for ensuring awarded projects are actually built on time and on budget. Commenters recommend shifting the balance to 70/30 or 65/35, or at minimum, assigning more explicit weight to project readiness and risk mitigation within the qualitative scoring categories.
Excerpts by Commenter
Flatiron Energy
“Given the significant value of mature projects to program success, Flatiron suggests that the DPU increase the weighting of Qualitative Factors to 30 points, and allocate additional weight to project maturity… This can reduce administrative burden and keep costs low for ratepayers.”
Jupiter Power
“Jupiter and other storage industry commentors have previously recommended a 65/35 split to quantitative vs qualitative evaluation weights to provide greater emphasis on project viability… Project maturity in particular relies on project readiness, site control, permitting status, bidder experience, and other qualitative factors.”
Rhynland Energy
(Implied through broader concerns around project readiness and bid standardization; not an explicit scoring proposal, but supports maturity and financial viability as evaluation priorities.)
🔹 Summary
Developers raised serious concerns about the RFP’s high non-refundable bid fee of $500/MW, which they argue is well above industry norms and could limit participation, especially from smaller or earlier-stage projects. Commenters also call for flexibility to submit bid variants (e.g., different durations or price options) without paying additional bid fees, citing industry precedents where multiple variants are allowed per project at no or low additional cost.
Excerpts by Commenter
Jupiter Power
“The proposed bid fee is significant, many times above the typical range of $10,000–$15,000 per bid… A broad interpretation of ‘variant of another bid’ will limit the options available to the evaluation and selection teams and may increase costs to ratepayers. Jupiter suggests that a single bid involving only one BESS may include up to four options…”
Rhynland Energy
“The non-refundable bid fee of $500/MW is exceptionally expensive when compared to other competitive procurements… Rhynland believes the proposed bid fee is cost-prohibitive and will force many developers to refrain from participating… Allowing bid variants without incurring additional bid fees would improve the evaluation team’s ability to optimize benefits and costs to ratepayers.”
🔹 Summary
A key dispute emerged over whether existing energy storage systems—especially those that do not require new financing—should be allowed to participate in the 83E procurement. The current interpretation by filing parties appears to exclude these resources, which several legislators and stakeholders argue is a misreading of legislative intent. They clarify that existing systems were explicitly included in the law to maximize competition and allow for repowering or capacity expansions, thereby benefiting ratepayers.
Excerpts by Commenter
Power Advisory
“Incremental capacity at an existing energy storage system will be lower cost than capacity from a new energy storage system… This suggests that the bidder would be able to offer a lower CPEC contract price and offer greater direct and indirect economic benefits than a new energy storage system.”
Rep. Jeffrey Roy (Public Official)
“The recent reply comments… took a narrow view as to the participation of existing energy storage resources… We specifically included language to enable existing storage resources to participate in the procurement, regardless of financing status or need… with the goal of ensuring that Massachusetts ratepayers will benefit from competing technologies and projects.”
Rep. Bradley Jones (Public Official)
“Explicit inclusion of existing energy storage as eligible to participate in each of the 83E solicitations was untethered from financing requirements… Existing resources are capable of providing additional services… and allowing such assets to compete can leverage those opportunities at a lower cost to ratepayers.”
🔹 Summary
Multiple commenters request clarification on how CPEC delivery obligations will be handled under long-term contracts. Concerns include whether there will be penalties for underperformance, how excess CPECs will be treated (especially around the right of first refusal), and how delivery schedules will be evaluated. Developers emphasize that without clear mechanics, bidders cannot confidently price their offers or assess financial risk.
Excerpts by Commenter
Flatiron Energy
“The RFP should specify whether there are damages for underproduction against the delivery schedule, availability guarantees, or other mechanisms related to project underperformance… The RFP should provide additional clarity… on how the planned production/delivery profile from a given project will be used in the evaluation process.”
Jupiter Power
“Jupiter respectfully requests that DOER… clarify that the annual delivery schedule allows the bidder the flexibility to provide different amounts of CPECs each month… Clarify what, if any, other environmental attributes standalone mid-duration BESS are eligible to produce… Clarify the meaning of ‘actual products delivered,’ specifically when payments are due and what they apply to.”
🔹 Summary
Commenters generally support having a defined Commercial Operation Date (COD) deadline, but argue that the proposed requirement of COD by January 1, 2030 is too aggressive given real-world development barriers. These include ISO-NE interconnection backlogs, supply chain delays, and uncertain permitting timelines. Developers urge extending the deadline to December 31, 2030 or allowing flexibility in cases where project delays are outside the developer’s control.
Excerpts by Commenter
Flatiron Energy
“We respectfully request that the COD deadline be extended to no earlier than December 31, 2030… A December 2030 deadline would provide the flexibility needed to responsibly and efficiently bring fully contracted projects online, while still ensuring that the State fulfills its requirements…”
Rhynland Energy
“Rhynland recommends against a firm Commercial Operation Date deadline or, at a minimum, provides flexibility for extended timelines to construct interconnection facilities and network upgrades that are beyond the control of the developer.”
🔹 Summary
Some developers emphasized the urgent need for greater clarity on future solicitations and long-term program design beyond the 2025 RFP. They warn that limiting the initial procurement to 40+ MW transmission-connected projects leaves distribution-connected and mid-sized developers without a viable path forward, undermining investment. These commenters request clear timelines or commitments for future DG-inclusive RFPs, standard contract structures, or tariff programs, to reduce policy uncertainty and allow developers to plan effectively.
Excerpts by Commenter
Nexamp
“If future procurements are intended to include DG projects, that intent must be clearly stated now… Developers and investors need policy certainty to plan, develop, and finance DG assets… A clear timeline and commitment to inclusive future procurements will help ensure the Commonwealth maintains a healthy and diversified clean energy portfolio.”
ENGIE
“Long-term contracting is essential to potentially buffer against prospective macroeconomic impacts… Allowing distributed BESS to contract long-term through the Section 83E RFP would put these projects on a level-playing field… ENGIE urges the Department to include procurement opportunities for distributed BESS and to enable future participation.”
🔹 Summary
Some commenters highlight the lack of support for retail-level (non-wholesale market) energy storage projects in the current RFP structure. These smaller systems—often colocated with community solar or sited behind-the-meter—face unique challenges in monetizing Clean Peak Energy Certificates (CPECs) without access to tailored incentives or standard contracts. Developers call for the creation of a parallel retail-focused program, potentially modeled after frameworks like New York’s Value of Distributed Energy Resources (VDER), to unlock local grid and equity benefits from retail-scale deployments.
Excerpts by Commenter
Nexamp
“We encourage establishment of a parallel procurement or incentive program that supports retail-level energy storage projects… The CPS program works well for transmission-connected resources, but retail projects—especially those not participating directly in wholesale markets—require tailored policies such as a Value of Distributed Energy Resources (VDER) framework.”
🔹 Summary
One commenter stresses that the RFP must explicitly support financing for eligible projects, as required by the 2024 Climate Act. The concern is that without language affirming that the long-term contracts can facilitate financing—including for existing projects seeking upgrades or repowering—the program risks excluding projects that could deliver meaningful value. Clear contract structures that unlock capital are seen as critical to ensuring successful deployment under this solicitation.
Excerpts by Commenter
Flatiron Energy
“DPU should approve Section 2.2.2.1: Facilitate Financing of Energy Storage Systems of the RFP. This section is necessary under the 2024 Climate Act… An existing project could enter into a contract to finance upsizing the project’s capacity or require financing to repower a retired project.”