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On July 1, 2026 H5175 in the State of Massachusetts was amended is an emergency bill that was drafted by the House Ways and Means Committee as a replacement to formerly H4744.

On July 1, 2026 this H5175 was given a second reading, amended by substitution, given third reading, and then passed to be engrossed in the Senate.

As reported previously, H4744 was an omnibus of new drafts of a number of bills that was assembled by the Joint Telecommunications, Utilities, and Energy Committee.

Many of H5175 bill provisions would directly 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;
• establish the following requirements for supplier auto-renewal contracts: (i) receipt of written affirmative consent by the customer within 45 days before the expiration of the customer’s contract; (ii) renewal notices approximately 60, 30, and 15 days prior to renewal; (iii) clear disclosure in the 30-day notice of the renewal rate, term, and opt-out method; (iv) independent third-party verification for all in-person and telephonic sales; and (v) that the renewal not move the customer from a fixed-rate contract to a variable rate contract;
• prohibit suppliers from: (i) offering rates to low-income residential customers that exceed the trailing 12-month average default service rate; (ii) offering variable rates to residential customers other than seasonal variable rates adjusted no more than twice a year and time of use rates; (iii) paying incentive-based compensation for enrolling customers; and (iv) imposing cancellation or early termination fees;
• require that if a supplier offers a renewable or green product containing energy attributes other than those that qualify for a Department of Environmental Protection (DEP) clean energy standard: (i) the supplier disclose in plain language that they will acquire and retire RECs or other energy attributes on behalf of the customer rather than supplying electricity directly from renewable generating units; (i) the disclosure identify the resource types and geographic origins of the RECs to be retired, if known, or else for a substantially similar product over the prior 12 months; (iii) the RECs are tracked by a system that assigns unique serial numbers, records issuance, transfers, and retirements, and prevents double-counting; and (iv) the supplier reports to DPU annually the amount, type, and location of attributes retired on behalf of residential customers and percentage of supply purchased in excess of the supplier’s annual CEP and RPS obligations, which information will be published on the DPU website;
• require that suppliers submit quarterly reports to DPU detailing each rate charged to residential retail customers in the previous quarter, including the number of non-low- and low-income residential customers charged each rate;
• require DPU to maintain a residential retail electricity supply comparison website that includes: (i) the current, and where possible, future default service rate available; (ii) default supply rate of any available municipal aggregation offering; (iii) the contract term, renewable or clean energy content, and additional products and services included as part of all products listed; (iv) the estimated monthly cost per customer; and (v) the information collected in suppliers’ quarterly reports;
• require suppliers to list at least one product available to residential customers on the DPU comparison website;
• require that suppliers provide written notice to DPU at least 30 days in advance of any assignment or transfer of customers;
• require that DPU publish, at least quarterly, data on complaints it receives on each supplier;
• 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 require it to make the above information, aggregated, publicly available on its website;
• 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;
• amend the Alternative Energy Portfolio Standard (APS) to remove biomass and combined heat and power from the list of eligible sources as of 1/1/28;
• 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; and
• 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

The bill impacts include:

• 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 and, if a tariff-based mechanism is proposed, to include both energy and environmental attributes;
• 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 “Commonwealth 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;
• 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 after 5/13/25 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;
• 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;
• 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 DPU to identify and review the reconciliation charges for each electric and gas utility to evaluate whether they can be revised or eliminated in order to reduce ratepayer bills and to issue such directives by 7/1/27;
• direct DPU to commence a proceeding by 1/1/27 to investigate establishing maximum thresholds for month-to-month changes in charges assessed to electric and gas customers and to establish such thresholds by 7/1/27; and
• 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.