Massachusetts 83E Round I Contracts: Initial 1,068 MW Portfolio Heads to DPU, with Rhynland Still Pending

The Massachusetts electric distribution companies (EDCs) have filed the first group of long-term contracts (Dockets 26-87, 26-88, and 26-89) from the Section 83E Round I mid-duration energy storage procurement for Department of Public Utilities (DPU) approval. The contracts cover 1,068 MW of selected storage capacity across three projects: Jupiter Power’s Trimount project in Everett, MA, and Flatiron Energy’s Energizar and Salt Cod projects in Chelsea and Somerset, MA, respectively.

The filings mark a major milestone for first Section 83E procurement, which targeted 1,500 MW of mid-duration energy storage resources with durations between four and ten hours. The portfolio, however, does not include Rhynland Energy’s River Mill Storage project, which DOER also selected in December 2025. The EDCs said that project may be submitted later, depending on the outcome of ISO-NE’s Transitional Cluster Study process.

Background/Summary

As discussed, on prior occasions in this blog, contracts are Storage Environmental Attribute Purchase Agreements. Under these agreements, the EDCs buy percentage entitlements to Clean Peak Energy Credits (CPECs) produced by, or associated with, the contracted storage facilities under the Massachusetts Clean Peak Standard (CPS).

The filed contracts include:

• Trimount I and II, which (when combined) comprise a 700 MW/2,800 MWh project located at the same Point of Interconnection as the Mystic Generating Station in Everett, MA and developed by Jupiter Power. The project is divided into two contract blocks, one for 200 MW and one for 500 MW. Both contracts provide a fixed price of $36.40/CPEC for 20 years, covering 100% of the project’s total capacity.
• Salt Cod, a 168 MW/672 MWh project located in Somerset, MA and developed by Flatiron Energy. The agreement identifies the project as using Tesla equipment and interconnecting with National Grid at 115 kV at the Pottersville Substation. The contract provides a fixed price of $20.40/CPEC for 20 years, covering 100% of the project’s total capacity.
• Energizar, a 250 MW/1,000 MWh project located in Chelsea, MA and developed by Flatiron Energy. The agreement identifies the project as a lithium iron phosphate battery system using Fluence SmartStack technology, with 1,247 MWh of nominal energy capacity. Unlike the others, the Energizar contract covers 80% of the project’s total CPEC output at a fixed price of $32.75/CPEC over 12 years (rather than 100% and 20 years for the others).

The most notable omission is Rhynland Energy’s River Mill Storage project (500 MW/2000 MWh), which DOER selected in December 2025 as part of the Section 83E Round I procurement. In joint testimony, the EDCs said Rhynland requested more time to evaluate initial interconnection upgrade cost estimates identified in ISO-NE’s Transitional Cluster Study interim report.

The parties agreed to wait for ISO-NE to determine whether those costs change in the final Transitional Cluster Study report, currently scheduled for August 6, 2026. However, delays are possible if projects withdraw because of unexpectedly high upgrade costs. The EDCs said they filed the executed Jupiter Power and Flatiron Energy contracts first so those projects would not be held up while the Rhynland issue is resolved.

Their approach preserves the possibility that additional Round I capacity could be submitted for DPU approval later, while giving Rhynland and the EDCs room to assess final cluster study results and network upgrade costs. It also highlights the potential cost exposure facing large-scale storage projects in New England’s interconnection process.

DOER Supports Approval: DOER submitted direct testimony supporting approval of the executed contracts. DOER recommended that the DPU approve the contracts, stating that the projects are cost-effective, in the public interest, and selected through a fair, open, and competitive solicitation process.

DOER said the approximately 1,068 MW portfolio before the DPU is projected to provide more than $516 million in total direct savings to ratepayers over the life of the contracts. DOER also noted that they have  executed memoranda of understanding with Flatiron Energy and Jupiter Power on June 30, 2026. Those MOUs require annual reporting on economic development commitments, diversity, equity, and inclusion plan goals, and impacts to environmental justice populations. According to DOER, all winning bidders included workforce diversity and supplier diversity plans in their bids.

Contract Structure and Development Risk Allocation: The contracts include development milestones, delay provisions, and project-size protections that are generally consistent with the risk allocation expected for long-term storage procurements. Sellers may extend unachieved critical milestone dates for up to two six-month periods by posting additional development-period security (as noted above). The contracts impose daily delay damages if projects miss their guaranteed commercial operation dates.

Per section 3.1 Critical Milestones, projects will be permitted to elect to extend critical milestone dates by up to two (2) six-month periods from the applicable date set forth in the contract. As part of an election to extend critical milestone dates, the project will be required to post an additional Development Period Security specified in each contract.

Project	Guaranteed COD	Non-force majeure extension
Trimount I	June 1, 2029	June 1, 2030
Trimount II	Dec 31, 2029	Dec 31, 2030
Salt Cod	Dec 31, 2028	Dec 31, 2029
Energizar	Sep 1, 2027	Sep 1, 2028

Note that contractual parties have the right to extend critical milestones by an additional twelve (12) months due to force majeure events, which generally qualify as actions that are beyond the control of contracting parties, as specified in section 3.10 of the contracts.

The agreements allow a project to reach commercial operation with a reduced nameplate capacity, provided the actual facility size is at least 90% of the proposed facility size and the other commercial operation requirements are satisfied. In that case, the nameplate capacity and contract maximum amount are permanently reduced to reflect the capacity deficiency.

Importantly, the contracts preserve the seller’s right to sell energy, capacity, ancillary services, and other non-CPEC products outside the Section 83E contract. The contracts also require participation in ISO-NE’s Forward Capacity Auction qualification process, preserving the expectation that these resources will participate in regional wholesale markets while monetizing CPECs through the Section 83E contract.

The sellers remain responsible for interconnection and network upgrade costs, including interconnection at a level sufficient to satisfy both the Network Capability Interconnection Standard and the Capacity Capability Interconnection Standard under ISO-NE rules.

CPEC Market Assumptions and Price Risk: In its quantitative evaluation report, DNV stated that the evaluation utilized the Alternative Compliance Payment (ACP) as the base case for CPEC market value, reasoning that the ACP would likely be the marginal CPEC price based on current market conditions and expected market developments, including federal policy changes. That said, DNV’s report also showed that the evaluation team only assumed that the CPS market would likely remain in deficit through the first Section 83E procurement round.

Thus, the evaluation team’s logic – perhaps unsurprisingly – hinges on the idea that higher CPEC prices increase benefits to ratepayers associated with long-term CPEC contracts PS market being short, long-term CPEC contracts can benefit ratepayers by avoiding higher CPS compliance costs. Alternatively, future additions of eligible storage, including resources procured through Section 83E, could increase CPEC supply above minimum standard requirements and reduce projected customer benefits if market prices fall below the ACP. The EDCs also identified this uncertainty as a market risk.

Lessons for Future Procurements: The DNV report also identified several lessons learned that may influence future Section 83E procurements. DNV said future procurements could benefit from more prescriptive bidder data requests related to operational profiles, degradation and maintenance assumptions, system peak assumptions, contract capacity relative to total energy storage system capacity, and efficiency assumptions so we may see increased informational requirement in future procurement rounds.

DNV also noted that bidders commonly overbuild energy storage projects. In future evaluations, DNV suggested asking bidders to state more clearly whether proposed capacity is overbuilt and how that overbuild supports CPS generation or other revenue opportunities. Additionally, the assumption around base case CPEC value may be revisited to reflect a scenario where future additions of energy storage narrows the supply gap and reduces CPEC pricing.

These points could be relevant to future procurements as Massachusetts moves into Section 83E Round II, where procurement structure, CPEC valuation, project eligibility, and wholesale market participation are already active areas of debate.[1]

Conclusion/Next Steps: The July 2 filings are the first major contract-approval step for Massachusetts’ Section 83E storage procurement framework.

The filings leave several issues to watch. First, and as noted above, Rhynland’s River Mill Storage project remains unresolved pending final ISO-NE cluster study results, meaning the final Round I contracted portfolio may still change. Second, the contracts place material interconnection and network upgrade cost risk on sellers, a point that could become increasingly important as storage projects move through New England’s interconnection process. Third, the projected ratepayer benefits of the filed contracts depend heavily on CPEC market assumptions, particularly the expectation that the CPS market remains short and that the ACP continues to serve as a reasonable proxy for marginal CPEC value. We note that ratepayer benefits do not extend past the CPEC market because the contracts are solely for CPECs – if energy services were procured, the contracts would have potentially greater ratepayer benefits.

We will continue to update subscribers on the resolution of these contracts and their impact on the CPS market through our CPMO deliverables. If you haven’t done so already, please register for our next Project Strategy Briefing, scheduled for July 23. To learn more about CPMO subscription offerings and Massachusetts Clean Peak and storage market analysis, please contact Bob Grace, Jim Kennerly, or Madeline Frierson.

Footnote:

[1] We note, though, that this consideration may also be present if the Indexed Storage Credit (ISC) structure is approved by the DPU for CPS-eligible projects in Round 2, given that the Reference Energy Arbitrage Price (REAP) used for calculating a strike price is calculated based on the system’s as-bid rated duration.