Massachusetts Releases Draft 83E RFP - Clean Peak Market Outlook

It’s here! On May 5, the Department of Energy Resources (DOER) issued a draft Request for Proposals (RFP) seeking Clean Peak Energy Certificates (CPECs) from qualified energy storage resources under Section 83E. The solicitation, which has a tentative due date of September 10, aims to procure up to 1,500 MW of mid-duration energy storage capacity. Also on May 5, DOER filed the draft RFP with the Massachusetts Department of Public Utilities (DPU), seeking its approval of the proposed solicitation.

This is the first in a series of staggered procurements designed to secure 5 GW of storage capacity by 2030. While this initial solicitation of 1,500 MW is only for mid-duration storage (4-10 hours) and only for CPECs, subsequent solicitations will be for both CPECs and “energy services” and will include long-duration (10-24 hours) and multi-day (24 hours+) storage. See our previous post for further discussion of Section 83E overall.

At a high level, the design of the solicitation is very similar to previous Section 83 solicitations (e.g., the Section 83C solicitations for offshore wind). While much of what was in the draft solicitation is in line with the Clean Peak Market Outlook (CPMO) team’s expectations and previous Section 83 solicitations, there were a few surprises and notable items we’ll highlight upfront:

Eligibility limited to transmission-connected resources. The solicitation is limited to resources that are connected to the transmission system (defined as above 69 kV) and are sized from 40 MW up to 1,000 MW. The decision to exclude smaller, distribution-connected resources may have been driven, in part, by the logistical challenges associated with including a large number of smaller projects in the solicitation, given the detailed proposal requirements, significant resource that will be required to review all of the proposals, and the requirement for the DPU to individually approve each contract.
Contract term: The solicitation cites the statute’s language that contract terms may be for a period of up to 30 years; the solicitation, however, goes on to state that bidders are “encouraged to submit bids with an up to 20-year contract term” and to state that no contract that extends beyond December 31, 2050 will be considered.
Timeline. S. 2967 specified that 1,500 MW “shall be procured by July 31, 2025.” DOER’s draft timeline includes an RFP release on July 31, with submissions due on September 10, selection completed by December 9, and contract negotiations completed and projects submitted to DPU by April 24, 2026.
Price cap. While recent Section 83 solicitations did not cap bid prices at the relevant Alternative Compliance Payment (ACP) rate, the proposed Section 83E solicitation does, limiting bid prices to 97.75% of the ACP in the applicable compliance year.
Flexible eligibility requirements. While the draft solicitation requires bidders to demonstrate viability as a threshold requirement, there are few hard lines for what this must include. The RFP does require bidders to be able to demonstrate site control (which can include an irrevocable option for site control).
No pricing indices or contingencies. Rapid changes in commodity and equipment prices have led to large projects (primarily offshore wind) not being able to honor prices submitted through various state solicitations. This has led some states (e.g., NY) to include options for large-scale renewable bids to be pegged to various reference prices or indices. While the shorter development timeline of storage mitigates these risks somewhat, the enormous uncertainty surrounding trade tariffs and, to a lesser extent, the future of the Investment Tax Credit (ITC) still leaves storage developers exposed to significant risks. The draft solicitation explicitly states that no indexed or contingent bids will be allowed.
Pay-as-bid structure. Given that all Section 83 solicitations have adopted a pay-as-bid structure, this decision was not unexpected; still, because the original, 2021 DOER straw proposal for a CPEC solicitation proposed a uniform clearing price structure, there was some uncertainty around this question. Of course, the choice of a pay-as-bid structure will have important implications for bidding strategies.
Potential coordination with other state solicitations. The solicitation considers the possibility of coordinating with other states. Our take is that this is included only because this option was discussed in the enabling statute; given that the resources must be connected to the MA electric power system, we see the probability of another state becoming involved as near zero.

Key Process Overview

The draft RFP outlines a three-stage selection process:

1. Eligibility and Threshold Review – An initial screen to confirm technical, financial, and permitting readiness.
2. Quantitative and Qualitative Evaluation – Ranking of eligible bids based on cost and additional policy criteria.
3. Final Selection and Contracting – Shortlisted projects move to contract negotiations, and ultimately, DPU approval.

The table below shows the proposed timeline. Issuance of the RFP is contingent upon DPU approval. Given the statutory deadline, we would expect that the DPU would strive for a procedural schedule that enables DOER to release the RFP on July 31; still, delays at the DPU are certainly possible and would push back the schedule below.

Event	Anticipated Dates
Issue RFP	July 31, 2025
Bidders Conference	August 14, 2025
Deadline for Submission of Questions	August 21, 2025
Due Date for Submission of Confidential and Public Proposals	September 10, 2025
Selection of Projects/Commence Negotiations	December 9, 2025
Execute Long Term Contracts and Memorandum of Understanding (MOU) with DOER	March 27, 2026
Submit Long Term Contracts for DPU Approval	April 24, 2026

Eligibility and Threshold Criteria

The RFP strikes an interesting balance – it sets high expectations for project viability and bidder experience, while including a modest number of concrete requirements (e.g., it doesn’t require that projects have progressed to a specific stage in the ISO-NE interconnection process, though it requires that studies approximating ISO-NE studies have been completed). This likely reflects a desire to maintain a competitive solicitation, with a large number of potentially eligible bidders and projects, while procuring a large volume (1,500 MW) of resources.

Core Eligibility Requirements

The primary eligibility requirements are:

Project Size: Must range from 40 MW to 1,000 MW.
Duration: Must provide 4 to 10 hours of continuous dispatch at full capacity
Commercial Operation Date: Must reach operation by January 1, 2030.
Interconnection: Must interconnect at transmission voltage and commit to ISO-NE’s Capacity Capability Interconnection Standard, although resources are not obligated to bid into the forward capacity market (FCM).
Contract Scope: Bids must be for environmental attributes only (no energy or capacity). CPEC pricing must not exceed 97.75% of ACP in the given compliance year.
Site Control: Required for all proposed project locations and interconnection routes.
Geographic Scope: Projects must be located in ISO-NE and deliver to Massachusetts GIS accounts.
Bid Fee: A non-refundable $500/MW is required upon submission.

Threshold Requirements

In order to pass the Stage One screening, projects must demonstrate that they meet the following threshold requirements (note that this list is a summary, and is not exhaustive):

Financial Viability: How the long-term attribute contract enables project financing (or refinancing). The Evaluation Team will “take into account whether a bid is associated with an existing energy storage system” when evaluating this criterion, which would seem to suggest that existing systems that would not be refinanced on the basis of being awarded a contract would not fail this threshold requirement.
Technical Feasibility: Use of commercially available technology and realistic development timelines.
Permitting Pathway: A clear roadmap to securing local, state, and federal approvals, though the solicitation does not require that specific permits already be secured.
Ability to Finance the Project: Bidders must provide information on existing or planned capital structure, specific capital providers, expected non-CPEC project revenues, and other relevant information.
Developer Experience: A demonstrated track record with similar-scale projects.
Community and Equity Commitments: Clear benefits to environmental justice communities, transitioning fossil fuel communities, and diverse local workforces.
Risk Allocation: Bidders must assume full project risk, including development, construction, and interconnection. Proposed alterations to the standard contract forms should not run afoul of this requirement.

Evaluation Criteria: Price Still Leads

While the RFP dedicates extensive attention to environmental justice, workforce diversity, and economic development, the scoring rubric underscores a central reality: price is still king. The Stage Two evaluation allocates 80 percent of the total score to quantitative criteria.

The draft solicitation states that real levelized dollars per CPEC, or “another metric to be determined by the Evaluation Team prior to evaluation of bids” will be the metric used for quantitative evaluation. Exactly how that metric will be calculated is not fully clear, however, the solicitation states that “proposals will be evaluated on both direct contract price costs and benefits and other costs and benefits as outlined below to retail consumers.” It’s clear that contract price will be a primary driver, but the weighting and approach to considering other factors (e.g., the potential value of non-CPEC environmental values and indirect, quantifiable economic costs and benefits) in the quantitative evaluation (driving 80% of the overall project score) is unclear. We expect that stakeholders will seek clarification on this point, either at the DPU prior to the release of the RFP or during the solicitation’s Q&A process.

The remaining 20 percent reflects qualitative considerations, including a host of considerations, such as community benefits, policy alignment, bidder experience, project viability, and other potential miscellaneous costs and benefits.

The Evaluation Team will then select proposals to proceed to Stage Three based on their Stage Two total score (quantitative + qualitative scores), cost effectiveness of these proposals, and total MW of proposals relative to the 1,500 MW target.

In Stage Three, the Evaluation Team will select projects to proceed to contract negotiation. The selection will be driven primarily by the Stage Two score, though the solicitation notes that the Evaluation Team may, at its discretion, consider other factors, such as portfolio effects, contributions towards local grid resilience and reliability, or other benefits or risks not otherwise fully captured.

The overall result:

Stage One eliminates projects that are too speculative, poorly sited, or unlikely to succeed.
Stage Two strongly favors low-cost, ready-to-build bids that also offer policy co-benefits.
Stage Three provides the Evaluation Team with an opportunity to apply greater discretion, considering portfolio effects or other factors they feel are not reflected in the Stage Two scoring. Our assumption is that the most likely driver of DOER applying discretion not based on Stage Two scoring criteria would be related to having too many leading projects clustered in a single geographic area, as too many of these projects being selected could reduce the viability of the projects in this area (interconnection challenges, reduced arbitrage potential, etc.).

In short, the RFP favors de-risked projects, but among those, cost will likely be the deciding factor.

Contracting and Contract Approval

Proposals selected during Stage Three will proceed to contracting with the EDCs. While contract templates are referenced in the draft solicitation, they were not included; they will be when the solicitation itself is released. While the solicitation allows bidders to propose changes to the templates, there is a strong preference for bidders to limit their proposed changes to non-substantive items.

The EDCs expect to submit contracts to the DPU within 45 days of execution. The DPU has six months to approve, reject, or approve with modifications the contracts. If the DPU approves a contract with modifications, the EDC may choose to terminate the contract if it determines that any of the modifications are “unsatisfactory to the Distribution Company.” The solicitation specifically notes that this would include a denial by the DPU of a 2.25 percent of contract value remuneration to the EDCs.

Proposal Requirements

The draft solicitation includes a proposal template. Most items are in line with previous Section 83 solicitations; this means a considerable amount of detail will be required. Some unique or onerous proposal requirements include:

Inclusion of a charge/discharge profile for the project
Description of assumptions for project costs, as well as assumptions on the availability of the ITC
Description of anticipated revenue streams
Estimated number of jobs created, duration of employment, anticipated compensation, etc., during the construction and operation of the project

Next Steps in Release of Solicitation

As noted above, DOER filed the draft solicitation with the DPU on May 5^th. Based on previous comparable dockets (e.g., Docket No. 17-103, in which the DPU reviewed the proposed approach for the first Section 83C solicitation), we would expect the DPU to seek public comments and potentially issue information requests. Based on our review of comparable previous dockets, it seems possible that the DPU could issue an Order in two months or less.

Strategic Implications

The design of the bid has interesting implications for how bidders can craft competitive bids. Standard Subscribers to CPMO can participate in our upcoming briefings, in which we’ll dive into our analysis of the upcoming solicitations, providing actionable intelligence on how to craft competitive proposals, as we simulate the outcomes of the solicitations.

If you are considering or intending to bid into the Section 83E solicitation, reach out to us today to discuss a CPMO subscription.