In May 2026, as discussed in Part I and Part II of our Section 83E Round II Series, the Massachusetts Department of Energy Resources (DOER) and the electric distribution companies (EDCs) divided on whether to propose an Indexed Storage Credit (ISC) framework in their Draft Request for Proposals (RFP) that would have introduced an Energy Services contract structure, potentially expanding the possible participation pathway for non-Clean Peak Standard (CPS) resources. They haven’t closed the door to this mechanism yet for future procurements, and they are looking for further analysis before allowing such structure to move forward.

This blog post discusses the final treatment of those issues by the Department of Public Utilities (DPU), the resulting Environmental Attributes-only Round II solicitation, and the implications for bidders and future Massachusetts storage procurements.

Background: On July 27, 2026, the Massachusetts Department of Public Utilities (DPU) issued an Order in Docket 26-75 partially approving the timetable and method proposed by DOER and the EDCs for Round II of the 83E Solicitation. The DPU approved a procurement for clean peak energy credits (CPECs), but directed DOER and the EDCs to remove all provisions related to the proposed ISC and Energy Services framework. However, DPU did not determine that an ISC was unauthorized under Section 83E. Instead, it deferred consideration of an Energy Services mechanism while DOER and the EDCs further develop the concept for a potential future procurement.

Consistent with the Order, DOER and the EDCs published the Final RFP on July 31. The Final RFP seeks up to approximately 1,000 MW of mid-duration (defined as 4-10 hours) energy storage capacity through long-term contracts. Eligible projects must achieve commercial operation by December 31, 2032.  The solicitation also includes a nonbinding target of 250 MW to 300 MW for distribution-connected projects.

DPU Defers the Energy Services and ISC Question: For all RFPs following Round I, the Section 83E requires each procurement to consider Environmental Attributes, Energy Services, or a combination of both. DOER supported including the ISC as a means of providing a broader revenue hedge and creating a participation pathway for resources that may not qualify to generate CPECs. As noted above, the EDCs opposed its use in Round II, citing unresolved legal, technical, modeling, and cost-recovery concerns.

DPU ultimately determined (in line with the EDCs’ preferences) that Section 83E requires consideration of Energy Services but does not require every solicitation (following the first one, which was required to be attribute-only) to procure them. DPU also declined to determine whether the ISC as initially proposed for Round II satisfies the statutory definition of Energy Services, finding that the record was not sufficiently developed to evaluate the competing positions of DOER and the EDCs, or compare the ISC with alternative structures.

To enhance the record, DPU ordered DOER and the EDCs to continue evaluating the ISC or other Energy Services mechanisms and submit joint progress reports on October 30, 2026, January 29, 2027, and March 31, 2027; stakeholder engagement is expected.

Based on the Order, it is clear that for DPU to approve an ISC structure for a future procurement round, any future proposal must include a more complete explanation of how the reference energy value is calculated, how the settlement would perform under different market conditions, how ratepayer benefits would be measured, and how EDC cost-recovery risk would be addressed. The stakeholder process will also need to consider whether non-CPS-eligible projects should participate and what public benefits should be required from existing resources receiving long-term revenue support.

Final RFP/CPEC Pricing Implications: With the Energy Services provisions removed, bidders must propose fixed annual prices for CPECs or other eligible Environmental Attributes. Payments will be based on attributes delivered under the contract. CPEC prices are capped at 97.75% of the applicable CPS Alternative Compliance Payment (ACP) — $65 per CPEC from 2026 – 2032 and $45 per CPEC from 2033 – 2050.

Round I provides the first observable benchmark for Section 83E Environmental Attribute contract pricing, with selected project prices ranging from $20.40/CPEC to $36.40/CPEC. However, the Round I contracts are not directly comparable. Trimount ($36.40/CPEC) and Salt Cod ($20.40/CPEC) sell 100% of contracted CPEC output for 20 years, while Energizar  ($32.75/CPEC) sells 80% of its CPEC output for 12 years. Projects also differ in size, location, interconnection exposure, development schedules, and financing assumptions.

The Environmental Attributes-only structure is also easier to administer than the proposed ISC because settlement is tied to delivered attributes rather than a modeled energy-market reference value. That said, developers (as in Round I), will continue to bear merchant exposure associated with energy, capacity, and ancillary services revenues. A fixed CPEC contract can reduce uncertainty around Environmental Attribute revenue, but it does not stabilize the project’s broader market earnings.

The CPEC-only structure may also affect bid pricing and financing. Since developers retain merchant exposure to energy, capacity, and ancillary services revenues, bidders may incorporate a greater risk premium into their proposed CPEC prices than under a broader revenue hedge such as an ISC. Simply put, if less revenue is hedged, the resulting increase in project risk could be reflected in higher financing costs and, in turn, higher bid prices. That said, the overall impact on ratepayer costs relative to an ISC is uncertain and depends on the magnitude of that risk premium and the foregone monetized wholesale market-derived benefits.

The firm December 31, 2032 commercial operation deadline may represent one of the most consequential risks in the Final RFP. To this end, bidders must demonstrate credible schedules for permitting, interconnection, financing, equipment procurement, construction, and testing. At the same time, recent Transitional Cluster Study results indicate that certain required network upgrades could take years to complete, materially constraining the ability of affected projects to achieve commercial operation by 2032 and leaving limited room for restudies, permitting delays, supply-chain constraints, or construction setbacks. Once we have analyzed the results we will provide a follow-up Blog Post on the impacts of the final results of the TCS. As a result, projects with substantial interconnection exposure may need to incorporate additional schedule, cost, and financing risk into their CPEC bids, while some projects may ultimately determine that the required commercial operation date is not achievable.

This risk was already made plain in the final set of contracted projects in Section 83E Round I. Rhynland Energy’s 500 MW River Mill Storage project, which DOER selected in December 2025, was not included in the initial group of executed contracts submitted to the DPU after Rhynland requested additional time to evaluate interconnection upgrade cost estimates identified through ISO-NE’s Transitional Cluster Study process. The project’s experience illustrates how unexpectedly high interconnection costs and uncertain upgrade timelines can affect contract execution and project viability even after a project has been selected through a Section 83E procurement.

Distribution-Connected and Existing Projects: Round II expands the Section 83E framework by allowing distribution-connected projects to participate. The Final RFP includes a 250 MW to 300 MW procurement target for those projects, although the target is not a carve-out and the Selection Team is not required to select any particular amount of distribution-connected capacity.

The DPU approved the proposed >1 MW minimum bid size and applicable site-control requirements for Distribution Projects, while allowing bidders to submit multiple Distribution Projects as part of a portfolio and to establish contingency relationships among those proposals. It also declined to provide additional scoring weight for distribution-connected resources.

In addition, distribution-connected projects participating in an applicable EDC tariff, flexible interconnection offering, pilot, or similar program remain eligible if they satisfy the RFP’s operational and contractual obligations. This clarification appears intended for projects participating in National Grid’s Active Resource Integration pilot. However, we note that other provisions of the Round 2 RFP exclude solar-plus-storage projects participating in the Solar Massachusetts Renewable Target (SMART) program, and selected distribution-connected projects must accept standard, non-negotiable long-term contracts.

In its order, DPU also confirmed that existing storage systems may compete if they can provide the product being solicited and satisfy the applicable threshold requirements, and do not need to demonstrate that a contract is necessary to support initial project financing, and requirements such as site control may not apply in the same manner to an operating resource.

The practical issue for existing projects is product eligibility. A facility that began operating before January 1, 2019, and has no eligible incremental capacity cannot generate CPECs and therefore has no Environmental Attribute to offer in this procurement. New incremental capacity at an existing facility may still qualify if it satisfies the applicable requirements.

We note, though, that the decision to defer the potential ISC to future procurement rounds narrows the commercial pathway for non-CPS-eligible resources, including certain existing pumped-storage facilities. Those projects are not excluded solely because they already operate. Their ability to compete depends on whether they can deliver an eligible CPEC. A future Energy Services structure could reopen participation for a broader group of existing resources, but the terms of that participation remain unresolved.

Evaluation, Interconnection, and Contract Process: The DPU approved the proposed allocation of 75 points to quantitative criteria and 25 points to qualitative criteria but declined stakeholder recommendations to place greater weight on qualitative factors, deciding to defer to the Evaluation Team’s determination that the 75/25 split is appropriate.

Economics will remain the principal scoring factor, although qualitative criteria may affect rankings where proposals have similar evaluated costs. Interconnection progress is also likely to receive significant attention. A low-priced bid may still be disadvantaged if its upgrade assumptions, queue position, or commercial operation schedule are not credible.

DPU approved the use of surplus interconnection service (SIS) where the original interconnecting customer receives Capacity Network Resource Interconnection Service (CNRIS). DPU also declined to require a separate public review of the transmission-connected form contracts before Round II proceeds. It found that bidders will have opportunities to raise substantive issues during negotiations and in the later DPU contract-approval proceedings.

Finally, for distribution-connected projects, the DPU found the EDCs’ separate stakeholder review of the form contract documents sufficient for Round II. For future solicitations, the EDCs must provide transmission-connected form contracts to the Independent Evaluator at least two weeks before filing a draft RFP and must file the non-negotiable distribution-connected contract with future draft solicitations.

Schedule: The Final RFP establishes the following schedule:

Event	Anticipated Date
Final RFP issued	July 31, 2026
Bidders’ conference	August 13, 2026
Deadline for bidder questions	August 20, 2026
Confidential and public proposals due	September 10, 2026
Project selection and commencement of negotiations	January 27, 2027
Execution of long-term contracts and Memoranda of Understanding with DOER	April 28, 2027
Submission of long-term contracts to the DPU	May 26, 2027

The period between issuance of the Final RFP and the proposal deadline is relatively short. Bidders will need to finalize pricing, interconnection assumptions, financing plans, development schedules, and threshold documentation before September 10.

Conclusion/Next Steps

The Final Round II RFP advances Massachusetts’ storage procurement program under a contract structure that is familiar to bidders and easier to implement within the current schedule. It confirms the eligibility of distribution-connected projects, establishes a nonbinding distribution target, preserves participation for existing systems that can deliver eligible attributes, and maintains the December 31, 2032, commercial operation deadline.

The policy work now shifts toward Round III. The October 2026, January 2027, and March 2027 progress reports will indicate whether DOER and the EDCs are developing an ISC or another Energy Services structure that can address financing needs, statutory requirements, ratepayer protections, and the treatment of non-CPS-eligible resources.

Massachusetts has chosen the simpler procurement structure for Round II. The remaining question is whether the stakeholder process can produce a broader storage revenue product that is sufficiently developed for the next solicitation.

Want to know what the Round II decision means for the CPEC price outlook? CPMO subscribers have access to our updated CPEC forecast, including our new Round II Base Case and analysis of the factors that could affect future CPS supply-demand balances and CPEC prices. To learn more about CPMO subscription offerings and Massachusetts Clean Peak and storage market analysis, please contact Bob Grace, Jim Kennerly, or Madeline Frierson.

As discussed in Part I in our 83E Round II Series, the Massachusetts Department of Energy Resources (DOER) and the electric distribution companies (EDCs) have released the Draft Request for Proposals (RFP) for the second round of Section 83E mid-duration energy storage procurements, introducing several significant structural and policy changes relative to Round I. Relative to Round I, the solicitation significantly expands interconnection requirements, operational disclosure obligations, safety planning standards, and environmental justice and workforce development expectations.

While the first part in this series covered the proposed Indexed Storage Credit (ISC) mechanism for energy services, Part II of our series is a deeper dive focused on the procurement mechanics of the Draft RFP, including 1) proposed contract structures, 2) evaluation methodology, 3) interconnection standards, 4) safety requirements, and 5) the overall solicitation schedule proposed by DOER and the electric distribution companies. We also highlight an emerging and substantial disagreement between DOER and the EDCs regarding the viability of an ISC structure, and the impact this disagreement could have on the Round 2 procurement writ large.

Procurement Details

Contract Structures: The Draft RFP proposed two alternative contract structures: an environmental attributes-only framework and an energy services framework. We describe these in more detail below.

Environmental Attribute-Only Contracts Framework: Under this framework, and consistent with the Round I process, projects bidding long-term contracts (LTKs) for environmental attributes must propose fixed $/CPEC pricing structures. Prices may either:

• Remain constant over the contract term
• Include a one-time step-down reflecting the reduction in the Clean Peak Energy Standard (CPS) Alternative Compliance Payment (ACP) after 2032
• Escalate or decline according to a predefined schedule

As also included in Round I, the procurement continues to prohibit inflation-adjusted pricing structures.  The Draft RFP would cap annual CPEC prices at 97.75% of the applicable ACP established under the CPS regulations. Transmission-connected projects eligible under the CPS may submit bids under either of the contract structures outlined above. Distribution-connected projects, however, would only be eligible to submit Environmental Attribute LTK proposals.

Indexed Storage Credit/Energy Services Contracts Framework: Under this framework, bidders would propose a Storage Strike Price in $/MWh. Payments would be determined by the difference between that strike price and the Reference Energy Arbitrage Price (REAP), which estimates achievable ISO-NE day-ahead market revenues.The structure resembles a contract-for-differences framework tied to wholesale energy market outcomes. DOER appears to view the structure as satisfying the statutory “Energy Services” requirement because compensation is directly linked to storage operation and wholesale market participation rather than solely to the production of Environmental Attributes.

The Draft RFP states that projects which are CPS eligible and contracted under the Energy Services framework would agree to transfer the associated CPECs to the buyers. The Draft RFP proposes different REAP calculation methodologies depending on the project’s storage duration and whether the project qualifies under the CPS.

There are three scenarios described in Appendix I of the Draft RFP to calculate the REAP:

• Non-CPS Eligible Projects: For a 4-hour duration resource, the Daily REAP is determined by pairing the Top 4 priced hours with the Bottom 4 priced hours, which is divided by the Round-Trip Efficiency (RTE) and finding the difference between the pairs for each day. The number of top and bottom hours used in the calculation is dictated by the duration of the resource. This Daily REAP is averaged over the number of days in settlement period. If the REAP is negative, for a pair of hours no value is included in the summation for that pair of hours.
• Less than/equal to 4-hour duration CPS eligible projects: Similarly to the above, the REAP is determined by pairing hours until the duration is met, but for CPS eligible projects the pair of hours is determined by the CPS discharging hours and the Bottom Priced CPS Charging Hours over the RTE. Under the proposed ISC construct, CPECs would effectively be bundled into the broader Energy Services compensation framework rather than compensated through a separate standalone CPEC payment.
• Greater than or equal to 4-hour duration CPS-Eligible Projects: These alternative combines both methodologies mentioned above. For the first four pair of hours the REAP is calculated as described in the CPS eligible projects, for the rest of the duration a top-bottom hour approach is included in the summation (excluding hours already included in the first 4 pair of hours). As the solicitation is for mid-duration storage, the maximum number of pairs is 10.

The settlement for a monthly period is calculated as:

Evaluation Process: The solicitation would utilize a three-stage evaluation framework similar to Round I.

Stage One: Eligibility/Threshold Requirements: Projects must demonstrate:

• Technical and logistical viability;
• Site control;
• Financial capability;
• Interconnection progress (demonstration of valid Interconnection Request for Capacity Network Resource Interconnection Service, or commitment to submit such an Interconnection Request in the Fall 2026 Cluster Entry Window);
• Safety planning;
• Environmental justice commitments;
• Diversity, equity, and inclusion plans; and
• Credible schedules for financing, permitting, and construction.

All bidders must submit a non-refundable bid fee equal to $500/MW based on proposed Full Rated Capacity. Round I only permitted transmission-connected projects sized between 40 MW and 1,000 MW. The Round II Draft RFP materially alters eligibility by allowing Distribution Projects larger than 1 MW and by reducing the maximum eligible Transmission Project size from 1,000 MW to 700 MW. The Draft RFP also introduces several new eligibility requirements specific to Distribution Projects, including participation in utility Wholesale Distribution Access Tariffs, if eligible, and future Operational Parameters for Energy Storage Systems (OPESS) tariffs pending before the DPU. Due to the inclusion of distribution-scale projects, the Round II Draft RFP significantly expands interconnection and deliverability requirements relative to Round I, particularly for distribution-connected resources. While Round I focused almost exclusively on transmission-level CCIS-equivalent interconnection obligations, Round II retains those requirements but additionally introduces eCNRC requirements for Distribution Projects and explicitly references distribution-level interconnection applications, OPESS tariffs, and FERC Wholesale Distribution Tariffs.

Stage Two: Quantitative and Qualitative Evaluation: Stage Two scoring will allocate up to 75 points to quantitative criteria, and up to 25 points to qualitative criteria. This represents a shift from the Round I Draft RFP, which contemplated an 80/20 weighting between quantitative and qualitative criteria.

Quantitative evaluation will assess:

• Contract costs and benefits;
• Avoided CPEC prices considering impacts on CPEC supply and demand dynamics;
• Potential impacts on capacity and ancillary services markets;
• Energy arbitrage value; and
• Other indirect impacts on supply and demand dynamics which affect ratepayers.

Qualitative evaluation criteria include:

• Environmental justice and low-income community benefits;
• Economic development and workforce diversity;
• Interconnection and project readiness;
• Reliability and resiliency benefits;
• Safety planning and stakeholder engagement;
• Siting and permitting progress; and
• Contract risk allocation.

Notably, the Evaluation Team indicated that it intends to place significant weight on interconnection progress and executed Interconnection Service Agreements for Distribution Projects. While the overall three-stage evaluation structure remains largely unchanged from Round I, the Round II Draft RFP significantly expands the scope of qualitative evaluation factors and operational disclosure requirements. Round II places materially greater emphasis on safety planning, environmental justice commitments, workforce diversity, operational transparency, and interconnection readiness than Round I.

The Draft RFP also signals increased scrutiny of executed interconnection agreements and queue-position risk analyses, particularly for Distribution Projects. Several procedural allowances for Distribution Projects appear for the first time in Round II. Unlike Round I, the Draft RFP allows Distribution Projects to submit portfolio-style bid packages with shared bidder response materials and permits contingency relationships among Distribution Project proposals within the solicitation.

Stage Three: Final Selection:  In Stage Three, the Evaluation Team may exercise discretion beyond numerical scoring to evaluate:

• Portfolio diversity;
• Geographic concentration;
• Grid resiliency and transmission/distribution system needs;
• Ratepayer bill impacts;
• Project viability risks; and
• Contributions toward Commonwealth policy objectives, including GWSA targets and economic development.

Safety, Environmental Justice, and DEI Requirements: The Draft RFP substantially expands the role of safety, environmental justice, and workforce diversity requirements compared to prior Massachusetts clean energy procurements.

Bidders must submit detailed safety plans addressing:

• Fire protection;
• Hazard mitigation;
• Emergency response procedures;
• Explosion control;
• Safety training;
• Underwriters Laboratories (UL) certifications; and
• Prior safety incidents involving proposed technologies.

Projects must also demonstrate meaningful benefits to environmental justice populations, low-income ratepayers, and transitioning fossil fuel communities. Examples cited in the Draft RFP include:

• Reducing energy burdens;
• Providing direct funding or rate relief;
• Supporting workforce development;
• Creating economic opportunities in disadvantaged communities; and
• Conducting targeted stakeholder outreach.

Selected projects will be required to execute a Memorandum of Understanding (MOU) with DOER memorializing economic development, environmental justice, and diversity commitments.

Additional RFP Details: While each project will still be evaluated individually, bidders may make Distribution Projects contingent upon other projects within the same solicitation. The Draft RFP also places increased emphasis on interconnection readiness and system upgrade transparency. Transmission projects must demonstrate a path toward Capacity Capability Interconnection Standard (CCIS)-equivalent interconnection and provide supporting studies approximating ISO-NE analyses. Distribution Projects must similarly demonstrate a path toward equivalent Capacity Network Resource Capability (eCNRC, a measure of capacity deliverability). The Evaluation Team also strongly encourages bidders without a Qualification Determination Notification from ISO-NE to provide scenario analyses showing how changes in the queue could impact interconnection costs. Our understanding is that this provision is intended to allow the evaluator to understand the potential range of interconnection cost outcomes for the project.

The solicitation also introduces significant operational and safety-related disclosure requirements. Bidders must provide detailed operational schedules for charging and discharging cycles, anticipated Environmental Attribute and/or Energy Services delivery schedules, and augmentation assumptions over the life of the project. In addition, projects must submit extensive safety documentation, including fire protection plans, hazard mitigation analyses, emergency response plans, and information regarding prior thermal or fire events involving the proposed technology platform.

Although Round I included qualitative evaluation criteria related to environmental justice and economic development, the Round II Draft RFP substantially expands the level of required documentation and specificity. Round II requires significantly more detailed safety disclosures, including fire protection planning, hazard mitigation, emergency response protocols, UL certifications, and prior incident reporting related to the proposed technology platform.

Schedule

The Drafting Parties proposed the procurement schedule in the table below.

Event	Anticipated Date
Issue RFP	July 31, 2026
Bidders Conference	August 13, 2026
Deadline for Submission of Questions	August 20, 2026
Due Date for Submission of Confidential and Public Proposals	September 10, 2026
Selection of Projects/Commence Negotiations	January 27, 2027
Execute Long Term Contracts and MOU (Memorandum of Understanding) with DOER	April 28, 2028
Submit Long Term Contracts for DPU Approval	May 26, 2027

DOER/EDC Disagreements Regarding Potential ISC Structure

The CPMO Team also notes that recent filings before the Massachusetts Department of Public Utilities (DPU) Docket 26-75 indicate substantial differences of opinion between DOER and the EDCs regarding the details of a potential Indexed Storage Credit (ISC) mechanism.

Specifically, on May 21, 2026, the EDCs filed a Letter, and an attached Memorandum written by Eversource, which explain in detail the EDC’s reasoning for opposing the proposed ISC. The DPU has now filed a Notice of Filing and Request for Comments on this issue – public comments are due on or before 5 pm on Friday, June 5, 2026.

Substance of the Disagreement: In the filings, the EDCs recommend moving forward with a narrower procurement for environmental attributes while seeking legislative changes to clearly authorize ISC-style storage contracts. Specifically, the EDCs disagree with DOER that the proposed Indexed Storage Credit can clearly be treated as an “energy service” under the statute. The distribution companies’ core concern are that an ISC structure:

• Could pay storage resources for market participation and grid-charging behavior that is not necessarily tied to delivering clean energy, reducing clean-energy costs, or improving clean-energy reliability; and
• Creates a much more complex contracting structure compared to the Round I Environmental Attribute-only contracts, and opens the door to non-CPS eligible projects to participate in Round II.

In response to DOER’s claims that if the procurement evaluation can demonstrate benefits related to the delivery of clean energy, the EDCs argue that while DOER’s modeling may show expected system benefits, such a finding would not give the EDCs sufficient legal certainty to prove compliance over the life of the contracts (or the certainty that a future DPU could disallow cost recovery). As a result, the EDCs are concerned that DOER’s approach would leave utilities bearing significant legal and regulatory risk.

Analysis: Section 83E explicitly suggests procurements shall consider inclusion of environmental attributes, energy services, or a combination of both.Given this, the CPMO team’s view is that, although the EDCs have identified a cogent potential risk, it is unlikely that the DPU would reject an ISC structure outright as inconsistent with Section 83E. Given the Healey Administration’s and EEA’s strong emphasis on affordability (and relatedly, reduction of financing and other procurement costs/risks), we believe the more likely outcome is approval of an ISC, but potentially with guardrails to address the EDCs’ statutory concerns. Such guardrails could include limits on how much capacity can come from existing standalone systems without a clear connection to facilitating clean energy or CPS-eligible projects.

Nevertheless, it is also possible (though, in our view, less likely) that the DPU could view an attribute-only procurement as a safe near-term resolution to the dispute, especially given expectations that the General Court will pass legislation in Fall 2026 giving DOER broader clean energy procurement authority that would reduce or eliminate the statutory contracting risk the EDCs would otherwise bear under the current structure, so long as that authority could potentially remain open to existing resources.

Conclusion

Relative to Round I, the Round II Draft RFP reflects a broader and more sophisticated procurement framework for mid-duration energy storage in Massachusetts. The proposal expands eligibility pathways, increases interconnection, operational, and safety requirements, and places greater emphasis on environmental justice, workforce diversity, and project readiness. It also reflects DOER’s effort to balance multiple objectives, including reducing financing costs, improving system reliability, supporting environmental justice communities, and maintaining flexibility as storage technologies and market structures evolve. However, in light of the EDCs’ objections, the Draft RFP remains subject to at least some potential change prior to DPU approval.

The CPMO team will continue monitoring developments in Massachusetts’ Section 83E storage procurements, including DPU guidance, DOER filings, stakeholder comments, project eligibility requirements, contract design, treatment of existing storage resources, and the proposed Indexed Storage Credit framework. Key developments and potential outcomes will be covered in our next June Market Outlook Briefing.

To learn more about CPMO subscription offerings and Massachusetts Clean Peak and storage market analysis, please contact Bob Grace, Jim Kennerly, or Madeline Frierson.

The Massachusetts Department of Energy Resources (DOER) and the electric distribution companies (EDCs) have released the Draft Request for Proposals (RFP) for the second round of Section 83E mid-duration energy storage procurements, introducing several significant structural and policy changes relative to Round I. Most notably, the Draft RFP proposes a potential Indexed Storage Credit (ISC) framework tied to “Energy Services,” which could materially expand project eligibility and alter how storage revenues are compensated under long-term contracts.

This first part of our two-part analysis focuses on the proposed ISC structure, the legal and policy questions currently before the Department of Public Utilities (DPU), and the implications for existing and non-CPS eligible storage resources. Part Two will examine the procurement mechanics of the Draft RFP, including contract structures, evaluation criteria, interconnection requirements, and safety and environmental justice provisions.

Background/Summary: On May 8, 2026, in DPU Docket 26-75, DOER and the EDCs posted the RFP for approval under Section 83E of Chapter 169 (83E Round 2 RFP). The Draft RFP is also available on the Massachusetts Clean Energy Website. 

As drafted, the RFP seeks to procure up to 1,000 MW of mid-duration energy storage (MDES) capacity through long-term contracts. Eligible projects must be between four and ten hours duration and achieve commercial operations by December 31, 2032.  The RFP includes a 250 MW to 300 MW target for distribution-connected projects, though the Selection Team is not required to select any particular mix of distribution or transmission projects. Eligible projects include transmission-connected projects between 40 MW and 700 MW and distribution-connected projects greater than 1 MW. Round II also extends the allowable commercial operation date from January 1, 2030 in Round I to December 31, 2032, reflecting the more complex interconnection and development timelines now facing storage projects in New England.

You may recall that on January 16, DOER, the EDCs, and the Massachusetts Attorney General’s Office (AGO)—collectively RFP Drafting Parties—issued a Request for Public Comment (RPC) regarding the 83E Round 2 RFP. The Drafting Parties explicitly noted in a commenter guideline that they were exploring an Indexed Storage Credit (ISC) structure for this procurement round to accommodate the procurement of Energy Services beyond Environmental Credits, namely Clean Peak Energy Credits (CPECs), the compliance attribute for the Clean Peak Standard (CPS). DOER published the public comments to this request here.

Proposed ISC/Energy Services Framework: By some distance, the proposed ISC framework represents the single largest structural departure from Round I. The Round I Final RFP only permitted Environmental Attribute contracts tied to fixed $/CPEC pricing. In the Draft RFP, DOER refers to environmental attribute long-term contracts as a fixed $/CPEC structure and refers to the ISC structure as a long-term contract for energy services. Describing the ISC structure, DOER asserted that CPECs would be transferred for free as part of the energy services bundle under the ISC construct. In our view, both structures are effectively contracts for CPECs; however, the ISC model would correlate CPEC compensation with a strike-price mechanism and representative wholesale energy market revenues. This approach shares energy price risk between the developer and the buyer by smoothing the impact of deviations between forecast and realized market values, whereas a fixed-price environmental attributes-only structure results in a more rigid hedge on the CPEC revenue a project generates without consideration of other market performance.

Procuring Energy Services Opens the Door to a Broader Suite of Energy Storage: In its filling to DPU, DOER asked DPU to clarify whether the RFP can include Energy Services and thus adopt an ISC model for the auction. The draft RFP contains highlighted language for an ISC mechanism, under which a bidder would propose a storage strike price indexed to the ISO-NE day-ahead energy market. If DPU suggests removing the highlighted language, the RFP would effectively become an Environmental Attributes Only RFP. The central policy issue in the proceeding is whether Section 83E permits – or potentially requires – the procurement to include compensation structures tied to “Energy Services,” rather than limiting compensation solely to the procurement of Environmental Attributes such as CPECs.

The inclusion of an ISC construct appears to be DOER’s attempt to meet the statutory requirement to consider energy services, in addition to addressing stakeholder desire for a more robust hedging instrument against merchant energy revenues. That said, not only does the ISC provide a more robust hedge for financing, it also provides a participation pathway for non-CPS eligible projects. In fact, DOER specifically defines formulas for how the ISC structure is applied to non-CPS eligible projects in the Draft RFP. Indeed, DOER directly references this outcome in its Cover Letter submitted with the Draft RFP, where DOER requests DPU to provide clarity on whether the RFP must solicit energy contracts, given the consequence of opening eligibility to non-CPS projects.

EDC Disagreements with ISC Structure/Approach and Participation of Non-CPS Eligible Projects: Although the DPU filing does not fully outline the EDCs’ rationale, the filing makes clear that the EDCs disagree with the proposed ISC structure, arguing that the procurement should be limited to Environmental Attributes, similar to 83E Round I, because it provides a more straightforward compliance procurement mechanism and given that the proposed ISC construct would both open the Procurement to non-CPS eligible projects and effectively expose ratepayers to wholesale energy market outcomes. However, Section 83E, subsections (b) and (d), state that “Each procurement shall consider inclusion of environmental attributes, energy services or a combination of both” and that “the distribution companies shall consider long-term contracts for energy services, for environmental attributes and for a combination of both.” Accordingly, DOER and the EDCs are required to consider energy services, but they are not required to enter contracts that include them. As shown in the comments posted above, project developers have encouraged the inclusion of such services in their comments, arguing that they could reduce project risk exposure and improve access to financing. However, it is unclear whether the EDCs would sign contracts that include services they do not wish to procure, or what the mechanism is to force them to do so if they choose not to.

Analysis Regarding Existing Project Inclusion: The CPMO Team notes that the concept of non-CPS eligible projects participating in Section 83E procurements is not new. As previously discussed in one of our CPMO blogs, when DPU issued its order on the Draft RFP for Round I, it ordered a change to the RFP to explicitly state that existing energy storage systems were eligible for Round I. A participation pathway in 83E Round II for non-CPS eligible resources (via the ISC construct) removes the locational and COD vintage requirements inflicted by CPS-eligibility and enables participation of an estimated 1.9 GWs of existing projects namely Bear Swamp and Northfield Pumped Hydro stations and Cranberry Point Energy Storage. As a result, existing pumped hydro projects may still need to demonstrate that the contract supports continued investment in the facility, such as upgrades, modernization, augmentation, operational enhancements, relicensing, or other reliability and storage-related improvements that advance the objectives of Section 83E.

The first solicitation under Section 83E, currently in the contract execution stage (as discussed in our CPMO blog), mandated that the procurement seek environmental attributes only. Though the Round I RFP explicitly allowed existing storage facilities to participate, it did not establish a clear commercial participation pathway for non-CPS eligible projects comparable to the proposed ISC framework. Under the proposed ISC construct, however, non-CPS eligible resources could participate directly through REAP-based settlement structures described in Appendix I of the Draft RFP.

Furthermore, in July 2025, State Representatives Bradley Jones (R) and Jeffrey Roy (D), respectively, submitted letters to Massachusetts Department of Public Utilities Chair James Van Nostrand regarding the first 83E storage solicitation. The letters highlighted that the statute, S. 2967 –  Act, Promoting A Clean Energy Grid, Advancing Equity And Protecting Ratepayers, includes text which intentionally states that existing energy storage shall be eligible to participate in Section 83E procurements. Given this precedent, it is reasonable to assume that DOER could be attempting to accommodate existing projects – including those that are not eligible under CPS – since such participation is both permitted and encouraged by Section 83E.

Although it remains unclear how the DPU will interpret the obligation to “consider” energy services, the statute does not appear to require procurements to include environmental attributes exclusively beyond the initial 1,500 MW tranche. Instead, the statutory language preserves procurement flexibility for DOER and the EDCs. Combined with the legislative clarifications provided by Representatives Jones and Roy, this suggests that the DPU is likely to allow procurements that incorporate energy services, even if such structures are not mandated. However, we note that it is not clear what mechanism exists to compel the EDCs to contract for such services, if it were to refuse to do so.

Proposed Schedule: The Drafting Parties proposed the procurement schedule in the table below.

Event	Anticipated Date
Issue RFP	July 31, 2026
Bidders Conference	August 13, 2026
Deadline for Submission of Questions	August 20, 2026
Due Date for Submission of Confidential and Public Proposals	September 10, 2026
Selection of Projects/Commence Negotiations	January 27, 2027
Execute Long Term Contracts and MOU (Memorandum of Understanding) with DOER	April 28, 2028
Submit Long Term Contracts for DPU Approval	May 26, 2027

Conclusion/Next Steps: The proposed ISC framework represents an impactful change to Massachusetts energy storage procurement, yet it is not surprising given the statutory language. By attempting to incorporate “Energy Services” compensation into the Section 83E framework, DOER appears to be testing a more flexible procurement structure that could broaden project eligibility, expand participation by existing storage facilities, and provide developers with a more comprehensive hedge against merchant market risk.

At the same time, the proposal raises significant legal and regulatory questions regarding the scope of Section 83E authority, the treatment of non-CPS eligible projects, and the extent to which Massachusetts ratepayers should be exposed to wholesale market outcomes through long-term storage contracts. The DPU’s forthcoming guidance will likely determine not only the final structure of this solicitation, but also the direction of future storage procurements in Massachusetts.

In Part Two of this series, we examine the operational and procurement mechanics of the Draft RFP itself, including the proposed contract structures, evaluation process, interconnection requirements, safety provisions, and expanded environmental justice and DEI obligations.

To learn more about CPMO subscription offerings and Massachusetts Clean Peak and storage market analysis, please contact Bob Grace, Jim Kennerly, or Madeline Frierson.

As previously discussed in our blog series, on July 31, 2025, the Massachusetts Department of Public Utilities (DPU) issued the final version of the 83E Request for Proposals (RFP) requiring Electric Distribution Companies (EDCs) to work with the Massachusetts Department of Energy Resources (DOER) to procure 1,500 MW of mid-duration (4-10 hours) energy storage. While stakeholders had pressed for broader modifications to the Draft RFP, the DPU adopted only a few targeted clarifications. In this blog post we present a summary of the bids submitted by developers.

Round 1 Bids Summary

Project Name	Owner	Town/City	Size (MW)	Duration (h)	Expected COD
Agawam Energy Center	Longroad Energy	Agawam	250	4	N/A
Bear Swamp Pumped Hydro	Brookfield Asset Management	Florida	88	4.5	Operating
Brough Energy Storage	CleanCapital	Cheshire	N/A	N/A	5/2029
Energizar	FlatIron Energy	Chelsea	250*	4	9/1/2027
Hammersmith	FlatIron Energy	N/A	225	4	12/31/2029
Hecate Energy Ward Hill Energy Center	Hecate Energy & CME	Haverhill	310	4	1/1/2029
Hillman Energy Center	East Point Energy	Tewksbury	125	4	Q4 2029
Merlin Storage	CleanCapital	N/A	N/A	N/A	5/2029
Partridge Storage	CleanCapital	Pittsfield	N/A	N/A	5/2029
Revolution	FlatIron Energy	N/A	N/A	4	N/A
River Mill Storage	Rhynland Energy	Tyngsborough	500	4	2028
Salt Cod	FlatIron Energy	Somerset	N/A	4	12/31/2028
Trimount ESS	Jupiter Power	Everett	700	4	6/1/2029

On September 10, 2025, DOER and the EDCs published redacted summaries of all Round 1 bids. Thirteen projects, totaling approximately 1,500 MW, were submitted, all of which are transmission-connected. Only Bear Swamp is a non-battery resource.

Round 2 Updates

DOER confirmed that subsequent solicitations will include distribution-connected resources. On July 31, DOER, the EDCs, and the Attorney General’s Office (RFP Drafting Parties) released a Request for Public Comment (RPC) on the Round 2 (83E II) solicitation, aiming to procure roughly 1 GW of additional mid-duration energy storage.

The Clean Peak Market Outlook (CPMO) team continues to monitor every stage of Massachusetts’ evolving Section 83E mid-duration storage procurements from DPU orders to DOER Q&A clarifications and stakeholder responses. Our subscriber-only analysis provides detailed tracking of bids, project eligibility, and insights valuable to contracting strategies.

An extended version of this blog post covering detailed stakeholder comments on Round 2, including eligibility, valuation, financing, aggregation, and contract structure, is available exclusively to Clean Peak Market Outlook (CPMO) subscribers.

To access the full version and receive ongoing coverage of Massachusetts’ mid-duration storage procurements, contact Bob Grace, Jim Kennerly or Madeline Frierson to learn more about CPMO subscription options.

As we covered in detail in our prior blog Post: Massachusetts Releases Draft 83E RFP 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.

On May 16, 2025, the Massachusetts Department of Public Utilities (DPU) requested comment on the draft RFP to procure 1,500 MW of mid-duration storage under Section 83E. Stakeholder comments and agency responses filed on May 30 and June 6 respectively  in the solicitation proceeding (Docket 25-59) reveal key uncertainties with significant implications project eligibility, solicitation timing, and future access to long-term contracts for distribution-connected resources. With stakeholder comments and agency replies now filed in DPU Docket 25-59, several key assumptions in our June Market Outlook Briefing have been reinforced, while others may need rethinking.

Key Developments

Push to Align Bid Due Dates with ISO-NE Study Fees: BlueWave proposed delaying bid submissions until October 10, when ISO-NE’s Transitional Cluster Study (TCS) deposits are due. Their reasoning is that giving developers time to assess study costs could prevent speculative bids and reduce later attrition. The draft RFP currently sets a bid deadline for September 10, which is a full month before study fee information becomes available. While DOER and the EDCs have not indicated plans to change the date, this proposal may gain traction with others who are concerned about late-stage drop-offs. In the June briefing, like BlueWave, our team also highlighted the high attrition risk associated with un-hedgeable interconnection costs and a compressed bid window.

Distribution-Connected Storage: On Deck for Future Rounds: In one of their most notable disclosures, the EDCs and DOER explicitly affirmed their intent for distribution-connected resources to be eligible in future Section 83E solicitations. For the present procurement round, they said there wasn’t time to resolve logistical and legal complexities. Our team interprets this as a significant statement of intent, especially given past ambiguity about whether these smaller-scale resources would be included at all under the 83E framework. For developers and aggregators with pipeline projects in up to 40 MW, this should be a signal to more carefully consider the possibility of bidding into for future rounds.

Financing Requirements Could Limit Existing Projects: The EDCs and DOER  reiterated that projects that have already secured financing may not be eligible to participate, based on the statutory requirement that long-term contracts must foster new development of Energy Storage. The RFP explicitly says that: “The bidder should specify how a Long-Term Contract for Environmental Attributes resulting from this RFP process would either permit it to finance the proposed project that would otherwise not be financeable or assist it in obtaining financing for its project.” Our team notes that this is potentially a significant constraint for existing energy storage resources. The agencies did acknowledge that refinancing might count, but they offered little clarity on how the Evaluation Team will determine whether a contract meaningfully supports “refinancing” versus simply subsidizing an already-funded asset. This leaves a gray area for retrofit and expansion projects trying to assess their own eligibility. Importantly, consideration of whether a long-term contract enables financing or not could complicate the eligibility of projects that have not commenced operation or construction, but may have secured financing. Until this uncertainty is resolved, it could also slow progress towards project financing, if developers believe that securing financing could compromise their eligibility for this and future solicitations.The net effect: existing resources might technically be eligible but practically excluded unless they can document a compelling need for contract-based support.

We’re Here to Help

Recent developments around the 83E solicitation underscore the complexity, and opportunity for developers, load-serving entities, and policymakers alike. Through CPMO’s market intelligence, we distill evolving policy signals, synthesize market expectations, and offer forward-looking modeling to help subscribers navigate and respond to these shifts. In our upcoming July briefing, we’ll take a deeper dive into the 83E solicitation’s implications, including what stakeholders should expect in the final RFP and how to prepare for future rounds. If your team is evaluating Clean Peak exposure or considering bids in this or upcoming solicitations, we invite you to reach out to the CPMO team to learn how our insights can support your strategy and decision-making.