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H5151 was given first reading in the Senate and referred to Ways and Means Committee (3/2/26).

On February 27, 2026 the bill was published as amended. See companion bill H5175.

H5151 given third reading in the House, amended, and passed to be engrossed by the House (2/26/26). See updated Description.

Bill reported from House Steering, Policy, and Scheduling Committee, given second reading in the House, and substituted with H5151 (2/26/26).

House Ways and Means Committee favorably reported a draft of H5151 for replacement of H4744 and the draft was referred to House Steering, Policy, and Scheduling Committee (2/25/26).

As reported previously this bill, formerly H4744 was anemergency bill was drafted by the House Ways and Means Committee as a replacement of H4744, which was itself an omnibus of new drafts of a number of bills that was assembled by the Joint Telecommunications, Utilities, and Energy Committee.

This massive bill would impact suppliers including:

• authorize cities and towns, by a vote of their town meeting or legislative body, to prohibit any supplier, energy marketer, or energy broker from either executing new contracts or renewing existing contracts for generation services with any individual residential customer except as part of a municipal aggregation plan;
• prohibit suppliers from servicing low-income residential customers actively enrolled in an R2 tariff;
• prohibit suppliers from automatically renewing a residential customer’s fixed-rate contract to a variable rate contract;
• establish the following requirements for supplier auto-renewal contracts: (i) affirmative consent by the customer; (ii) renewal notices clearly disclosing the renewal rate, term, and opt-out method at least 60 and 30 days prior to renewal; and (iii) a final reminder at least 15 days prior to renewal;
• prohibit suppliers from offering variable rates other than a seasonal variable rate and time of use rate;
• require suppliers to conduct third-party verification for enrollments through in-person and telephonic sales;
• prohibit suppliers from imposing cancellation or early termination fees;
• extend the period in which a customer may initiate an unauthorized switching complaint from 30 days to two years;
• increase the maximum civil penalty DPU may impose on retail suppliers from $25,000 to $100,000 per violation per day and the multiple violation cap from $5 million to $10 million;
• require that suppliers offering voluntary renewable or green products: (i) disclose in plain language, prior to enrollment, that the customer will acquire and retire RECs or other clean energy attributes, not receive electricity directly from renewable generating units; (ii) disclose the resource type and geographic origin of RECs to be retired; (iii) source all RECs from a certificate tracking system that assigns a unique serial number, records issuance, transfer, and retirement, and prevents double counting; and (iv) annually report the amount, type, and location of attributes retired on behalf of residential customers, and the percentage retired in excess of applicable portfolio requirements;
• specify that information reported quarterly to DOER by utilities, suppliers, and aggregators includes, but is not limited to: (i) number of customers; (ii) load served; (iii) amounts billed to customers in dollars; (iv) renewable and clean energy attribute certificate purchases, and (v) supply product offerings;
• eliminate the requirement that DOER produce an annual rate comparison report but authorize it to make the above information, aggregated, publicly available on its website;
• end the Alternative Energy Portfolio Standard (APS) with applications submitted by 12/31/27;
• authorize DPU to set a non-uniform percentage discount for suppliers choosing the complete billing method based on the supplier’s amount of uncollectable bills or average number of customers in arears;
• revise licensing for brokers, marketers, and suppliers to: (i) cap the annual fee at $10,000; and (ii) require a $5 million bond conditioned on performance of duties as a retail supplier for at least one year;
• deem energy marketers to be legal agents of suppliers and require suppliers to directly provide appropriate training to marketers;
• authorize DOER and Department of Environmental Protection, at their discretion, to reduce suppliers’ portfolio standard minimum obligations proportional to eligible environmental attributes retired by DOER;
• require DPU to maintain a residential supply comparison website that includes at least the following: (i) the current, and where possible, future default service rate available; (ii) the default supply rate of any municipal aggregation offering available; (iii) product contract terms; (iv) product percentages of renewable or clean energy content; (v) all additional products and services included as part of the product; and (vi) the estimated monthly cost;
• requires suppliers to list at least one product available to residential customers on the DPU comparison website;
• require suppliers to report quarterly to DPU the number of low and non-low income customers charged each rate charged to residential retail customers in the previous quarter;
• require that suppliers submit quarterly reports of each rate charged to residential retail customers including the number of low-income and non-low-income residential customers charged each rate, by rate class, and that DPU publish average rates charged to customer classes and aggregate numbers of customers on its website;
• require that suppliers annually report data on clean or renewable energy attributes retired in connection with the generation service provide to individual residential retail customers, and that DPU publish this information on its website;
• require licensing of distributed energy resource (DER) providers subject to: (i) rules, regulations, and an application fee to be determined by DPU; and (ii) an annual licensing fee of up to $1,000;
• require all residential or community solar salespersons (salespersons) to annually register with DPU for a fee of up to $250;
• authorize DPU to fine salespersons operating without a certificate of registration up to $5,000 per violation;
• require salespersons: (i) prior to engaging in any sales or marketing, state the name of the DER provider and, if applicable, DER energy marketer on whose behalf they are selling; (ii) wear an identification badge with their name, photo, company name, company license number, and salesperson registration number; (iii) only make non-scheduled sales visits to residences between 9:00 a.m. and 8:00 p.m.; (iv) not wear apparel, carry equipment or distribute materials that includes the logo of an electric utility, retail supplier, or governmental agency; and (v) not use any language suggesting a relationship with an electric utility, retail supplier, or governmental agency that does not exist;
• direct DPU to develop a code of conduct and necessary regulations for DER providers, salespersons, and the marketing and sale of DERs and related products and authorize it, for any violations of the code or regulations, to: (i) revoke or place conditions on the violator’s license; and (ii) assess a civil penalty of up to $2,500 per violation per day, up to a maximum total of $50,000 for a related series of violations;
• direct DPU to develop consumer disclosure forms to be provided by a DER provider prior to any sale or subscription agreement with a residential customer, which must include: (i) the payment schedule for upfront costs; (ii) system design assumptions, including size, estimated first year production, estimated annual system production degradation, presence of energy storage, energy storage capacity, and a description of equipment needed to provide backup power; (iii) disclosure of the extent to which system maintenance and repairs are included in the agreement; (iv) description of any warranties for repair of any damage to the consumer’s residence during installation or removal; (v) description or location in the agreement of any performance or production guarantees; (vi) an estimated start and completion date; (vii) a brief description of the basis for any savings estimates provided; (viii) disclosure regarding retention or ownership of any RECs or other environmental attributes; and (ix) a specified statement regarding the possibility of no or lower-than-expected savings;
• specify information that must be included in disclosure forms for: (i) purchase of residential solar electric systems; (ii) lease of residential solar electric systems; (iii) power purchase agreements; and (iv) community solar subscription agreements;
• require that agreements offered by DER providers: (i) adhere to state residential contracting agreement requirements; (ii) include specified information for each type of agreement; and (iii) are retained by the provider for the length of the agreement or at least four years following execution;
• allow consumers to cancel purchases of residential solar systems or community solar subscription agreements without penalty for at least five business days and require that salespersons verbally explain this right to the consumer;
• require a DER provider that sells itself to another company, within 90 days of completion of the transaction, to notify DPU and all consumers with whom it has an agreement of the sale and contact information and website of the new company;
• require suppliers to notify DPU at least 30 days prior to assignment or transfer of their supplier license and authorize DPU to deny or place conditions on the transaction; and
• require DPU publish supplier and utility complaint data at least quarterly.

The bill would also:

• require DPU to maintain a retail residential customer bill assessment dashboard providing: (i) visual representations of current and historical rate components; (ii) a summary explanation of each bill component and corresponding utility cost recovery mechanism; (iii) an analysis of the benefits of clean energy, greenhouse gas (GHG) reduction, energy efficiency (EE), and demand response (DR), and any other programs, procurements, or investments funded by customers;
• establish a Division of Clean Energy Procurement within DOER and require that division to: (i) develop resource solicitation plans, to include at least 10GW apiece of solar and offshore wind generation by 12/31/40; (ii) conduct related procurements through a competitive bidding process; and (iii) contract with clean energy generation and energy services providers for environmental attributes or energy services established pursuant to GHG emissions limits;
• authorize DOER to develop an energy storage incentive program;
• require at least 70% of RPS alternative compliance payments to be returned to ratepayers, effective 7/1/29;
• authorize DOER to develop an energy storage incentive program and, if a tariff-based mechanism is proposed, to include both energy and environmental attributes;
• regarding siting and permitting of small clean energy infrastructure, require DOER to include use of surplus interconnection service as part of the standards for site suitability guidance;
• direct DOER to establish an offshore wind pre-development and project acceleration program enabling partnership with developers through co-investment or other mechanisms in pre-development activities specific to individual projects
• direct DOER to develop a “state smart solar permitting platform” to process permit applications for residential solar energy systems and associated equipment, including photovoltaic panels, energy storage systems (ESSs), main electrical panel upgrades and main breaker deratings, that provide electrical power to detached 1- and 2-family dwellings, and that automates plan review and permitting;
• require municipalities to allow for application submission through the state smart solar permitting platform or an alternative automated platform satisfying the same functions;
• direct DOER to develop and implement a solar renewable energy generation incentive program that supports diverse installation types and sizes, including community and low-income solar facilities, and where the environmental attributes of solar photovoltaic facilities receiving its incentives are eligible for use by suppliers to meet portfolio standard minimum obligations;
• require electric-sector modernization programs (ESMPs) to include: (i) a load management and virtual power plant (VPP) plan; (ii) information on the flexible interconnection program; and (iii) a description of the integration of these plans with other distribution system planning efforts;
• permit utilities to require a surety bond or letter of credit, but not cash payments, for interconnection costs prior to commencement of construction of required upgrades;
• require gas utilities to implement opt-out “default budget billing” for residential customers: (i) equalizing payments over 12 months; (ii) with reconciliation occurring during a non-peak month by default; and (iii) with a customer option to equalize reconciliation over 12 months;
• remove the transition kWh charge from calculation of all net metering (NM) credits;
• add to the calculation of “neighborhood net metering credits” the transmission kWh charge, not including demand side management and renewable energy kWh charges;
• define “supply rate net metering facility” as any non-cap-exempt NM facility that submitted an interconnection application prior to 11/1/25 and was authorized to interconnect after 1/1/26;
• define “supply rate net metering credit” as equal to the excess kWh by TOU billing period multiplied by the difference between the utility’s default service kWh charge in the customer’s ISO-NE load zone and the utility’s costs associated with: (i) the requirements of RPS, AES, CES, and any Department of Environmental Protection portfolio standard; and (ii) the utility’s basic service administrative cost factor;
• exempt portable solar generation devices from interconnection and NM program requirements and prohibit utilities from requiring for such devices: (i) approval for installation; (ii) fees or charges; and (iii) additional controls or equipment;
• permit gas companies to own and operate geothermal heat loops for individual customers;
• extend requirements to provide discounted rates for low-income and eligible moderate-income customers to gas companies;
• require DPU to establish rules for determining eligibility for low- and moderate-income rates, to include at least income verification;
• require the climate compliance plans for gas companies to include comprehensive “just transition plans” for transitioning of gas workers to other employment, amended biennially;
• require each utility to offer a DPU-approved flexible interconnection program, to be as consistent as possible between utilities, that maximizes deployment of DERs while minimizing costs and require a stakeholder process for requests to modify an approved program;
• require utilities to offer a comprehensive process for interconnection of vehicle-to-grid (V2G) systems at residential buildings based on DPU guidance;
• authorize utilities to offer “energy project” programs, to be integrated with their three-year EE plans, that allow customers to invest, through an opt-in tariff on their bills, in non-fossil fuel related EE upgrades, high-efficiency electric heat pumps, ESSs, DR equipment, or on-site solar energy generation equipment designed to provide immediate and ongoing customer savings;
• direct DPU to review and accept utility proposals to deliver renewable natural gas produced by anaerobic digesters or landfills to individual C&I customers;
• direct DOER to conduct a review of the RPS program to consider its effectiveness and possible improvements, submitting a report to the legislature within 12 months of the bill’s effective date;
• require new or expanded data centers designed to have a load of at least 20MW to procure sufficient electricity using at least 80% renewable energy resources and, if seeking a permit for fossil-fuel generation backup equipment, demonstrate the infeasibility of battery energy storage facilities on their site;
• require electric utilities to establish data center tariffs designed to: (i) ensure protection of non-data center ratepayers from resultant increased costs; and (ii) incentivize data centers to develop and utilize methods to increase energy efficiency;
• repeal a state law requiring new nuclear facilities be approved by a statewide ballot initiative;
• establish an electric rates task force to make recommendations to the legislature and Energy and Environmental affairs and require it to produce a report by 9/30/27 that analyzes the cost components of electricity rates, their increases over the previous 10 years, and projected increases over the next five years and makes recommendations for both short- and long-term relief for residential and commercial ratepayers;
• direct the Inspector General to conduct, and report by 7/1/27 the results of, a comprehensive review of the Mass Save program and its performance and growth, including relative to its original goals, and make recommendations, potentially including remodeling or reorganization of the program;
• direct the EE investment plan program administrators to require income verification for eligible customers and renters in designated equity communities, including requiring landlords to provide documentation that at least 50% of their occupied dwelling units are rented to households meeting the applicable income eligibility requirements, to qualify for comprehensive moderate-income rebates and incentives, and require a landlord of a rental property;
• require all utilities and municipal aggregators with approved 2025-2027 EE plans to file a mid-term modification to its approved plan by 7/1/26 resulting in ratepayer savings of at least $1 million; and
• extends a deadline for utilities to enter into long-term contracts for ~5.6GW of offshore wind energy generation from 6/30/27 to 6/30/29.