RFP Analysis: Massachusetts Section 83E RFP | Long-Term Energy Storage

Executive Summary

This report provides an in-depth market analysis of the Massachusetts Department of Energy Resources' (DOER) draft Request for Proposals (RFP) issued under Section 83E of Chapter 239 of the Acts of 2024. This initial procurement targets 1,500 MW of mid-duration energy storage, marking a foundational event for utility-scale storage in the ISO-New England (ISO-NE) territory. The analysis evaluates the program's monetization pathways, development risks, and strategic implications for prospective bidders.

The primary opportunity is securing a long-term, fixed-price contract for Clean Peak Energy Certificates (CPECs) for up to 20 years. This "environmental attributes only" contract provides a bankable revenue stream, allowing developers to retain full upside from participation in ISO-NE's wholesale energy, capacity, and ancillary services markets. The program's structure, including guaranteed cost recovery and a direct financial incentive for Electric Distribution Companies (EDCs), enhances contract stability and reduces counterparty risk.

However, this opportunity is counterbalanced by substantial execution risks, primarily the cost, timeline, and opacity of the transmission-level interconnection process within ISO-NE. While recent legislation (Chapter 239 of the Acts of 2024) has streamlined siting and permitting, interconnection remains a significant challenge. Transmission interconnection costs for storage projects in the region are high and variable, averaging $230/kW, and are a primary driver of project withdrawal. The ISO-NE interconnection queue is heavily saturated with storage proposals, indicating fierce competition for limited grid capacity.

The RFP's compressed timeline and evaluation criteria strongly favor "de-risked projects" with demonstrated viability. Successful bidders will likely be well-capitalized entities with projects already advanced in the multi-year ISO-NE interconnection study process, providing cost and schedule certainty. Success also requires a sophisticated approach to local stakeholder engagement, particularly with fire officials, and a well-articulated plan for delivering community and environmental justice benefits, as these qualitative factors will be decisive.

Section 1: The Massachusetts Energy Storage Market Landscape

The Section 83E RFP is a direct outcome of ambitious legislative action to reshape the Massachusetts energy grid. Understanding this macro context—the scale of the mandate and the current market development—is essential to framing the strategic opportunity.

1.1 Legislative Action: The Mandate for 5 GW of Storage

Chapter 239 of the Acts of 2024, "An Act Promoting A Clean Energy Grid, Advancing Equity and Protecting Ratepayers," signed in November 2024, establishes the Section 83E procurement authority. This legislation mandates that the Commonwealth's EDCs (Eversource, National Grid, and Unitil) jointly solicit and contract for energy storage systems.

The mandate is unprecedented, directing EDCs to procure approximately 5,000 MW of energy storage capacity by July 31, 2030, providing a durable, multi-year demand signal. The 5 GW mandate is broken down by storage duration:

• 3,500 MW of Mid-Duration Storage (4 to 10 hours)

• 750 MW of Long-Duration Storage (10 to 24 hours)

• 750 MW of Multi-Day Storage (greater than 24 hours), contingent on feasibility.

This RFP represents the first and largest single tranche of this mandate, targeting 1,500 MW of mid-duration storage. Chapter 239 also fundamentally alters the development landscape by establishing a new, streamlined permitting process for energy infrastructure, a critical de-risking element.

1.2 Market Potential & Saturation

This initial Section 83E solicitation specifically targets 1,500 MW of mid-duration storage. The enabling legislation outlines a staggered procurement schedule to meet the broader 5 GW goal:

As of early 2025, Massachusetts had only 644 MWh of installed energy storage, indicating a nascent operational market. However, the development pipeline shows a massive 12,932 MWh of storage. The ISO-NE interconnection queue further reveals intense developer interest, with battery storage accounting for 46% to 51% of the approximately 40 GW of total proposed capacity.

This data highlights a critical dynamic: the market is not saturated with operational assets, but it is highly saturated with proposed projects. The supply of potential projects will far exceed the 1,500 MW demand, creating an intensely competitive environment. The RFP's emphasis on "de-risked projects" and "project viability" directly acknowledges this. The primary differentiator will be development maturity, with projects that have advanced in the multi-year transmission interconnection process possessing a decisive competitive advantage.

Section 2: RFP Monetization and Program Mechanics

The economic viability of projects bidding into the Section 83E RFP depends on a thorough understanding of its unique monetization structure. This section analyzes the primary incentive, indirect price signals, utility financial structure, and charging costs.

2.1 Incentives: Deconstructing the CPEC Revenue Stream

The central incentive is a long-term contract for Clean Peak Energy Certificates (CPECs), compliance instruments for the Massachusetts Clean Peak Standard (CPS). This initial 1,500 MW procurement is explicitly for "environmental attributes only," allowing bidders to retain the asset and participate freely in wholesale electricity markets. Contract terms can be up to 30 years, though the RFP encourages bids up to 20 years.

CPEC generation and revenue are determined by a complex system of multipliers that reward dispatch during periods of highest grid stress (peak demand, high wholesale prices, high marginal emissions rates).

The price of CPECs is capped at 97.75% of the Alternative Compliance Payment (ACP) rate. An emergency rulemaking in October 2024 increased the ACP rate from $45/MWh to $65/MWh for compliance years 2026 through 2032, significantly increasing the maximum potential value of CPEC contracts.

The program allows for revenue stacking. The CPS is compatible with other Massachusetts and ISO-NE programs. Solar-plus-storage projects can also participate in the Solar Massachusetts Renewable Target (SMART) Program, which offers an "energy storage adder." This allows a co-located asset to earn revenue from the Section 83E contract, the SMART adder, and wholesale market participation, creating a highly attractive, multi-layered revenue profile.

2.2 Capacity Price Signal: Navigating ISO-NE Markets

While the Section 83E RFP does not directly procure capacity, it sends an indirect capacity price signal through its interconnection requirements. All proposed projects must interconnect to the transmission system under ISO-NE's Capacity Capability Interconnection Standard. This ensures the project is capable of providing capacity services, even if the owner initially chooses not to participate in the capacity market.

Developers retain the right to offer and sell the asset's capacity into the ISO-NE Forward Capacity Market (FCM), a multi-year forward auction for future reliability needs. The CPEC contract acts as a capital subsidy, providing guaranteed revenue to cover fixed costs, allowing the asset to bid more competitively into the FCM and other wholesale markets, increasing its probability of clearing and securing additional revenue.

2.3 Utility Financial Incentive: Ensuring Program Longevity

A key structural element enhancing the bankability of Section 83E contracts is the financial mechanism designed to ensure active EDC participation. Chapter 239 aligns the interests of the state, utilities, and developers, reducing programmatic and counterparty risk.

The law provides a direct financial incentive for EDCs: an annual remuneration equal to 2.25% of the annual payments made under the contract. This compensates utilities for the financial obligation and transforms them into active partners. Additionally, the legislation guarantees full cost recovery for all payments made under approved long-term contracts. These costs are passed through to distribution customers via a uniform, fully reconciling annual factor in their distribution rates, subject to DPU review.

This dual structure—profit incentive combined with guaranteed cost recovery—is a powerful de-risking feature, ensuring EDCs are motivated to diligently execute and administer contracts, providing high confidence for developers and financiers.

2.4 Charging Tariffs: The Cost of Energy Input

As the Section 83E RFP is for transmission-connected assets participating in wholesale markets, charging costs will be governed by specialized tariffs, not standard retail rates. Accurately modeling these costs is critical.

Standalone energy storage systems are a new class of grid participant, and tariff structures are evolving. FERC approved National Grid's new Wholesale Distribution Tariff (WDT) in March 2024 for standalone storage connected to the distribution system but participating in wholesale markets. This tariff provides a model for how charging costs will likely be structured, including an as-used peak demand charge, a contract demand charge, and a fixed access charge. National Grid's F-1 Rate formalizes this, with separate charges for primary and secondary voltage interconnections (e.g., for primary voltage: $20.94/month access, $0.51/kW contract demand, $7.28/kW as-used peak demand).

A project's financial model must account for two input costs: the energy itself (procured from ISO-NE wholesale market during low-priced hours) and the cost of delivering that energy through the transmission and distribution system (governed by these wholesale tariffs). Profitability will depend on the spread between delivered charging energy cost and revenue from discharging during peak hours, supplemented by CPEC and capacity market revenues.

Section 3: Project Development and Execution Risks

While the financial mechanics are attractive, successful participation requires navigating a complex and demanding project development landscape. This section analyzes key execution risks and opportunities, from the procurement timeline to permitting and public engagement.

3.1 Time to Notice: The Procurement Timeline

The RFP establishes an aggressive timeline favoring developers with mature, well-defined projects. The schedule demands rapid response and preparation:

The period from final RFP issuance (July 31, 2025) to proposal due date (September 10, 2025) is less than six weeks. The subsequent negotiation period to DPU filing (April 24, 2026) is less than nine months. This compressed schedule implicitly requires bidders to have completed significant pre-development work, including site selection, preliminary design, and, critically, initiation of the interconnection process. Projects must achieve commercial operation by January 1, 2030, accommodating the multi-year interconnection study and construction timeline.

3.2 Zoning and Siting: The New Permitting Paradigm

Chapter 239 of the Acts of 2024 has created a fundamentally new and streamlined permitting paradigm, significantly de-risking development in Massachusetts. This legislation directly addresses historical "permitting risks."

The law establishes a consolidated permitting process with clear, statutory deadlines, bifurcated by project size (100 MWh threshold):

This new regime provides unprecedented timeline certainty. If the authority fails to issue a decision within the deadline, the permit is deemed constructively approved with standard conditions. While streamlining approvals, it does not entirely preempt local control. Massachusetts General Law Chapter 40A, Section 3, prevents municipalities from enacting bylaws that "prohibit or unreasonably regulate" solar energy systems, a protection the Attorney General's Office has consistently extended to energy storage, providing a strong backstop against unreasonable local opposition.

3.3 Fire Permitting: Navigating Safety and Code Compliance

While the new state law streamlines zoning and environmental permitting, fire safety permitting remains a distinct and locally controlled process, a critical path item. The Authority Having Jurisdiction (AHJ) for fire safety is the local fire department.

Compliance is governed by the Massachusetts Comprehensive Fire Safety Code (527 CMR 1.00), which incorporates NFPA 855, the Standard for the Installation of Stationary Energy Storage Systems. Developers must submit comprehensive construction documents to the AHJ for review and approval prior to installation, including:

• Detailed site and layout diagrams.

• Specifications for hourly fire-resistant-rated assemblies.

• Manufacturer's specifications, ratings, and listings (UL 9540 listing is mandatory).

• Detailed plans for fire suppression, detection, ventilation, and thermal management systems.

Local jurisdictions often impose specific requirements beyond the statewide code. The separation of this process from the consolidated EFSB or local permit creates a potential pitfall: a developer could secure a consolidated permit only to face delays or costly redesigns from the local fire chief. This underscores the necessity of a two-track engagement strategy: formal state-level permitting complemented by early, proactive, and collaborative engagement with the local fire department to integrate safety considerations into the initial design.

3.4 Public Relations: Community Engagement and Social License

Chapter 239 explicitly elevates the importance of community engagement and equitable development. The law mandates that permitting and RFP evaluation criteria consider community benefit plans, direct benefits to environmental justice populations, and diversity, equity, and inclusion (DEI) plans (including workforce and supplier diversity). This transforms public relations into a core component of a competitive bid.

Best practices for community engagement emphasize forming a broad local coalition, including municipal departments, emergency responders, energy committees, and community groups. Effective public relations requires proactive and transparent communication, addressing common public concerns regarding safety (fire risk), cost, noise, and environmental impacts with clear, factual information.

A powerful strategy is to align the project's objectives with community resilience goals, such as siting projects to provide backup power to critical facilities (hospitals, fire stations, emergency shelters). This approach aligns with the RFP's qualitative evaluation criteria, which prefer proposals supporting grid resiliency in specific geographic locations, building the "social license" necessary for a smooth development process.

Section 4: The Interconnection Challenge

Despite Massachusetts' steps to streamline permitting, interconnecting a large-scale energy storage project to the transmission grid remains the single greatest source of risk, cost, and timeline uncertainty. This process is governed by ISO-New England and the relevant transmission owner (Eversource or National Grid). A thorough understanding of this challenge is paramount.

4.1 Interconnection Capacity Visibility: Finding a Place on the Grid

This RFP is exclusively for transmission-connected resources (69 kV or higher), making publicly available distribution-level hosting capacity maps irrelevant. Visibility into high-voltage transmission system capacity is limited. The primary tool for analysis is the ISO-NE Interconnection Request Queue, which allows developers to identify proposed projects and potential grid congestion.

For direct, site-specific information, developers can engage transmission owners. Eversource, for example, offers pre-application services like preliminary engineering screening reviews, providing an early, non-binding assessment of interconnection feasibility at a specific substation or transmission line point. This is a crucial early step in de-risking a potential project site.

4.2 Interconnection Cost Visibility: Quantifying the Biggest Financial Risk

Interconnection cost is the largest financial variable and risk for utility-scale storage, determined through a multi-stage, multi-year study process (typically over four years) managed by ISO-NE.

Data from a June 2023 Lawrence Berkeley National Laboratory (LBNL) report on 194 ISO-NE project studies reveals stark findings for energy storage:

Interconnection costs are substantial and highly variable, with a strong correlation between high costs and project failure. Withdrawn projects faced, on average, costs over 70% higher than active projects, indicating that unexpected high costs are a primary driver of attrition.

The study process itself requires significant financial commitment, with escalating deposits for each stage (Feasibility Study, System Impact Study (SIS), Facilities Study). For large generators (>20 MW), the initial deposit is $50,000, and the SIS deposit is at least $250,000 or 100% of the estimated study cost.

This combination of a crowded queue, multi-year timeline, and high, uncertain costs creates a formidable barrier to entry, but also a significant competitive advantage for experienced developers who have already advanced a project. The RFP's emphasis on "project viability" signals a preference for bids from projects demonstrating high cost and schedule certainty. Given the January 1, 2030, commercial operation deadline and the four-plus-year interconnection timeline, only projects already in the ISO-NE queue are likely to meet the RFP's requirements.

Section 5: Strategic Outlook and Recommendations

This final section synthesizes the analysis into a strategic outlook for prospective bidders, distilling core opportunities and risks, profiling a likely successful bidder, and providing actionable recommendations.

5.1 Synthesis of Opportunities and Risks

The Massachusetts Section 83E RFP presents a compelling yet challenging opportunity, defined by key dichotomies:

• Massive Mandate vs. Intense Competition: A large and durable market (5,000 MW total target, 1,500 MW in this round) is countered by intense competition from a saturated development pipeline.

• Bankable Contract vs. Market Volatility: The long-term CPEC contract provides stable, bankable revenue, but profitability also relies on successfully monetizing the asset in volatile ISO-NE wholesale markets.

• Streamlined Siting vs. Localized Hurdles: New state law creates a revolutionary, time-bound permitting process, but critical local approvals, particularly from fire departments (NFPA 855), remain outside this streamlined process and require separate engagement.

• Policy Certainty vs. Interconnection Uncertainty: The legislative mandate provides unparalleled policy certainty, but this is undermined by the extreme financial and timeline uncertainty of the transmission-level interconnection process, the greatest barrier to execution.

5.2 Profile of a Successful Bidder

A successful bidder will likely exhibit the following characteristics:

• Advanced Project Status: A well-defined project with site control and an advanced position in the ISO-NE interconnection queue, ideally with a completed System Impact Study (SIS) for firm cost and timeline estimates. This is critical for demonstrating "project viability."

• Financial Strength and Experience: Well-capitalized, capable of funding significant upfront interconnection study costs, required bid security ($500/MW), and substantial network upgrades. A proven track record in financing and constructing large-scale energy infrastructure.

• Deep Siting and Permitting Expertise: Experience in Massachusetts siting and permitting, including navigating the new EFSB consolidated permit process and effective engagement at the local level with planning boards, conservation commissions, and fire department AHJs.

• Sophisticated Revenue and Dispatch Modeling: In-house capability or third-party support to accurately model complex, stacked revenue streams, optimizing CPEC generation, forecasting ISO-NE Forward Capacity Market clearing prices, and projecting revenues from energy arbitrage and ancillary services.

5.3 Strategic Recommendations for RFP Participation

For entities considering a bid into the Section 83E RFP, the following strategic recommendations are advised:

• Prioritize and Emphasize Project De-Risking: The entire bid narrative should focus on project viability and execution certainty. Provide concrete, verifiable evidence of de-risking, including executed site control, ISO-NE queue position, completed interconnection studies, and a detailed plan for all remaining permits.

• Develop a Compelling Qualitative Proposal: While price is 80% of the score, the 20% for qualitative factors will be decisive. Develop a well-researched plan for community benefits, addressing environmental justice communities, and implementing robust diversity, equity, and inclusion initiatives. Partnering with local organizations and labor unions can strengthen this.

• Adopt a Strategic Bid Price: Set the CPEC bid price strategically below the $65/MWh ACP rate ceiling. The optimal price should reflect the project's fully-loaded costs (including firm interconnection upgrades) and projected wholesale market revenues. The CPEC contract should be viewed as the foundational revenue stream, with wholesale market participation providing profit upside.

• Engage Early and Continuously with Local Authorities: Initiate informal, educational meetings with local fire chiefs, planning department staff, and community leaders early in the development process. This proactive engagement builds trust, allows for early identification and mitigation of concerns, and smooths formal permit approvals, especially for the fire permit.