Momentum Q2 | 2026

State / Bill

Description

Categories

California, Residential Heat Pump Systems (SB 222)

🟡 In Progress

Standardizes the heat pump permitting process by creating a pathway for automated permitting, requiring fee transparency, establishing guardrails on setback and noise limits, and prohibiting HOAs from banning heat pumps.

Consumer Protections

California, 

Gas Corporations: Gas Distribution Service Line Replacements: Alternatives  (AB 2313)

🟡 In Progress

Requires gas utilities to offer customers the choice of an incentive in lieu of replacing an old gas service line planned for replacement. The proposed incentive would be capped to ensure that some of the planned pipeline replacement work would be avoided, ensuring a lower overall cost to ratepayers.

Affordability

California, Natural Gas Ratepayer Protection Act (SB 1359)

🟡 In Progress

Requires gas companies to report costs associated with gas infrastructure replacement to the commission and before authorizing cost recovery, the commission shall consider whether cost-effective alternatives such as electrification and nonpipeline alternatives could reasonably avoid or reduce those costs.

Consumer Protections

Illinois, POWER Act (SB4016/HB5513)

🔴 Held

Establishes guardrails for hyperscale data centers including: ensuring infrastructure costs are not shifted to consumers, creating clear standards for interconnection and cost recovery, aligning new demand with clean energy supply, and establishing critical protections to limit pollution and sustainable water use. The POWER Act did not pass during the regular session, but is expected to be taken up during the veto session later this year.

Consumer Protections

Indiana, Electric Utility Affordability (HB 1002)

🟢  Passed

Implements a series of policies to address affordability, including assistance for low-income qualified households and a summer disconnection moratorium for low-income qualified households.

Consumer Protections

Indiana, Various Utility Matters (HB1111)

🔴 Failed

Would have provided more protections against disconnections, including prohibiting a reconnection charge, implementing a summer disconnection moratorium for eligible households.

Consumer Protections

Kentucky, An Act Relating to Utility Disconnection Protections (HB377)

🔴 Held

Would have prohibited winter and summer disconnections when temperatures exceeded a certain limit, establish a certificate of need for households at risk, and limit the days in which disconnections could occur. 

Consumer Protections

Maryland, Investor-Owned Electric, Gas, and Gas and Electric Companies – Cost Recovery – Limitations (HB0001)

🔴 Held

Would have prohibited BGE and other investor-owned utilities from passing along the high costs of executive salaries to Maryland ratepayers. The bill would also add new restrictions on charging customers for events and advertising.

Consumer Protections

Maryland, Utility RELIEF (Reducing Energy Load Inflation for Everyday Families) Act (HB1532/SB841)

🟢 Passed

The Utility RELIEF Act includes building decarbonization provisions that will help lower Marylanders’ energy bills and create jobs by encouraging the adoption of heat pumps, which efficiently deliver both heating and cooling from a single appliance.

These provisions include:

– An allocation of $72.65 million in funding to Maryland’s Residential Energy Equity Program, which will help low- and moderate-income households install modern, efficient, zero-emission heat pumps.

– An update to the state’s Strategic Energy Investment Fund (SEIF) authorizing it to fund loan, grant, rebate, and other incentive programs that support the electrification of Marylanders’ buildings and transportation.

– Direction to the Maryland Energy Administration to develop programs that can provide grants and loans to businesses and homeowners seeking to weatherize, install heat pumps, or otherwise upgrade their buildings to achieve Maryland’s Building Energy Performance standards.

The Utility RELIEF Act also includes provisions regarding utility ratemaking, data center tariffs and registry, creation of a reverse auction to encourage new clean energy generation, and changes to Maryland’s energy efficiency programs.

Affordability

Massachusetts, An Act Relative to Energy Affordability, Clean Power, and Economic Competitiveness (H5151)

🟡In progress

This bill aims to reduce energy burdens on Massachusetts ratepayers, though the approach from the House and Senate diverges. For the House bill, according to the Environmental League of Massachusetts, “the bill removed threats to our Commonwealth’s net-zero climate goals, does not require an affordability test for climate programs, and no longer puts the burden of paying for gas pipelines on electric customers.  While this bill makes meaningful progress, it also proposes cutting $1 billion in funding for Mass Save, which would effectively decimate one of the Commonwealth’s most effective tools for lowering energy bills.” On the other hand, on June 24th, the Senate released its version of the bill that did not include cuts to Mass Save, but would establish more oversight and limit overhead spending for the program. The Senate frames the bill as a hunt for ‘pockets of overspending and overcharging that in some cases are legacies of past policies that have exhausted their usefulness’ within utilities” and notably include the phasing out of the GSEP program (ABC 10 Boston). The house and senate will ultimately negotiate to align the two approaches.      

Affordability

Minnesota, Commission to Promote Affordable Service and Consider Customers’ Ability to Pay Rates Requirement (SF3992/HF3777)

🔴Held

Would have amended Minnesota’s statute to include that when the commission is determining whether utility returns are fair and reasonable, it must consider customers’ ability to pay the rates used to fund the return on equity.

Affordability

New York, Prohibits Termination of Electricity or Heat Services During Forecasts of Extreme Temperatures (S120A)

🟢 Passed, awaiting governor’s signature

Reintroduced from 2025. Prohibits the disconnection of electricity or heat services during extreme weather. 

Consumer Protections

Pennsylvania, An Act Amending Title 66 in Rates and Distribution System, Providing for Return on Equity (HB 2224)

🟡In progress

This bill “would cap the return on equity (ROE) that investor-owned utilities can earn during rate cases…It establishes a formula-based cap tying the default authorized ROE to the 10-year U.S. Treasury bond yield plus two percentage points. It also creates a competitive equity auction process for utilities that challenge the formula, ensuring any approved return reflects actual market conditions.” (Evergreen Action). 

Affordability

Pennsylvania, An Act Amending Title 66 (HB 2333/SB154)

🟡In progress

This bill would reinstate Chapter 14, which establishes consumer protections against disconnections. This bill also amends Chapter 14 to include more protections and extends the sunset date of this Chapter to 2036. 

Consumer Protections

South Carolina, Utility Billing Accountability and Consumer Protection Act (H5282)

🔴 Held

Would have established a series of transparency measures, including PSC approval for billing changes, 90-day advance customer notice, and require utilities to implement consumer protections for rural energy-burdened households.

Consumer Protections

Virginia, Electric Utilities; Energy Efficiency Upgrades, Report (HB2/SB72)

🟢 Passed

This bill will lower low-income energy bills and related air pollution by requiring that utilities create a program to shift low-income customers still stuck on old oil or propane heat over to high-efficiency, lower-polluting electric heat pumps. 

Affordability

Virginia, Income-Qualified Energy Efficiency and Weatherization Task Force, Established, Report (HB3/SB5)

🟢 Passed

Establishes the Income-Qualified Energy Efficiency and Weatherization Task Force to improve coordination across utilities, state agencies, and federal, municipal, and private funding sources to more effectively deliver energy efficiency, weatherization, and weatherization-ready repairs for income-qualified Virginians.

Affordability

Virginia, Electric Utilities; Percentage of Income Payment Program, Eligibility, Delayed Effective Date (HB884)

🟢 Passed

Simplifies the process for accessing the Percentage of Income Payment Program (PIPP), allowing for more households to apply.

Affordability

Virginia, Utilities, Certain; Notice Procedures for Nonpayment (HB1002)

🟢 Passed

Requires utilities to make reasonable efforts to work with customers before disconnection. 

Consumer Protections

Virginia, Electric Utilities; Pilot Programs for Energy Assistance and Weatherization for Certain Individuals (SB253)

🟢 Passed

Extends the sunset date of the annual pilot program conducted by Dominion Energy Virginia and Appalachian Power Company for energy assistance and weatherization for low-income, elderly, and disabled individuals from 2028 to 2038, “directs the SCC to ensure that residential customers do not pay electricity generation and distribution costs to serve data centers”, and reduces regulatory oversight for Dominion’s undergrounding program (Inside Climate News).

Advocates are concerned about the cost impacts on ratepayers given the reduced regulatory oversight of Dominion’s Strategic Underground Program (SUP).

Consumer Protections

Washington, Protecting Tenants from Periods of Extreme Heat (HB2265/SB6200)

🟢 Passed

 This bill affirms tenants’ right to install and use portable cooling devices (Shift Zero). 

Consumer Protections

Washington, Authorizing Community Scaled Weatherization Projects (HB2338/SB6223)

🟢 Passed

According to Shift Zero, “HB 2338 allows agencies that lead weatherization projects to carry out larger, community-scale projects that serve multiple homes and/or apartments under the umbrella of one larger project. This will simplify management, help attract contractors to rural areas in cases where travel costs would be prohibitive for smaller-scale projects, and allow weatherizing agencies to reach more homes faster and at lower cost.”

Affordability

State

Status

LEA Reform Updates

California

Passed

California was the first state to eliminate LEAs in 2022 through regulation, and followed that decision in 2023 with eliminating electric LEAs for new construction mixed-fuel buildings. It is the only state to eliminate electric LEAs for new construction. Since 2023, line extension data collected by the California Public Utility Commission (CPUC) has seen steady gains in all-electric new construction rates (CPUC). In Q4 2025, all-electric new construction rates on the residential side were 73% for PG&E, 48% for SCE and 68% for SDG&E. For the non-residential side, all-electric new construction rates were 89% for PG&E, 76% for SCE, and 48% for SDG&E (CPUC). 

Colorado

Passed / Litigation Pending

Colorado eliminated LEAs in 2023 through legislation (SB23-291), however, in May 2026 Colorado Natural Gas Inc. (CNG) introduced a lawsuit challenging Colorado’s change to its LEA policy. CNG raised two main issues with the statute: 1) it argues that only service line allowances should be eliminated, as main lines and shared infrastructure are “essential to the overall utility system’s basic operation, and its associated costs reflect more than the cost of connecting one new customer” (16). 2) CNG claims that the statute itself violates federal and state Contract and Takings clauses and impairs the regulatory compact that allows CNG to earn a reasonable rate of return on its investments in exchange for the obligation to serve. 

Though SB23-291 is being challenged in the courts, Colorado’s original LEA policy was established by regulation, and did not strictly need legislative action to be revised. Furthermore, while SB23-291 eliminated the monetary incentives given to new gas customers and charged to existing customers, the option for customers to connect to the gas system has not been impacted. Rather, the true economic cost of connecting to the gas system has been revealed.   

D.C.

In progress

D.C. first began discussing the reform of gas LEAs in formal case #1167 via a straw proposal for a gas planning framework that included eliminating LEAs. Within FC#1167, the Public Service Commission (PSC) requested stakeholder comments on establishing a separate gas planning proceeding. 

In March 2026, with support from stakeholders, the PSC initiated FC#1187 (Order No. 22799), “In the matter of the investigation into the implementation of integrated natural gas distribution system planning,” and proposed to follow the Clean Energy Cohort Roadmap developed by the National Association of Regulatory Utility Commissioners (NARUC). Within the roadmap is a recommendation to review system costs that specifically identifies existing LEAs and whether they should be limited or eliminated. Currently, stakeholders are providing comments on the proposed roadmap.  

Illinois

In progress

Gas LEAs remain under active review in IL. The ICC ordered a statewide study after finding that “the historic policy rationale for line extension allowances has changed,” with a final version submitted to the Commission in May 2026. (Illinois Commerce Commission). The study evaluated cost causation, equity, long-term gas demand, and stranded asset risk. It found that utilities use different models, including footage-based allowances, cost-equivalent approaches, revenue-screened approaches, and rider-centered approaches to calculating LEA amounts. 

Despite those differences, the report found a consistent outcome: existing ratepayers, not new connecting customers, bear most line-extension costs. Customer contributions ranged from 0% to roughly 33%, while ratepayer responsibility was the majority in all cases and exceeded 90% for several utilities. The range of line extension costs reported by the utilities also varied widely, as demonstrated in the chart featured below, ranging from $3K to $132K as the average line extension cost. Due to this high cost and disproportionate share between new customers and existing ratepayers, there is a very high degree of cross-subsidization across the majority of the utilities.

The report concluded that Illinois’ current framework does not consistently align cost responsibility with cost causation and results in material cross-subsidization across customer groups. Rather than recommending an immediate end to gas line extensions, however, the report recommends a phased reform path focused on standardized reporting, clearer cost-allocation rules, customer-facing disclosure, minimum customer contribution thresholds, and better treatment of refunds and financial risk. 

Maine

In progress

In May 2025, Maine initiated its Future of Gas proceeding under Docket No. 2025-00145, “Inquiry Regarding Future of Natural Gas.” A major focus within the proceeding is to review gas infrastructure investments, including LEAs, and their climate impacts (Maine Future of Gas).

Maryland

In progress / Delayed

Maryland moved toward eliminating gas LEAs through its Future of Gas proceeding, but this action has recently been delayed. The PSC found that the status quo for funding gas line extensions may no longer align with the state’s greenhouse gas reduction and electrification policies. In June 2025, the PSC ordered staff to draft regulations that would require new gas customers to pay the full upfront cost of extending service, rather than shifting those costs onto existing ratepayers. The Commission framed the change as a neutral cost-causation reform, not a restriction on customer choice: customers could still choose gas service, but without artificial subsidies. The PSC also emphasized stranded-cost risk, noting that new gas extensions may not be fully recovered through rates over the lifetime of the assets and that existing ratepayers should not be left responsible for those costs (Maryland Public Service Commission). 

Massachusetts

In progress

Massachusetts’ LEA deliberations remain active in the utility Climate Compliance Plan dockets. In D.P.U. 20-80-E, the Department proposed eliminating gas line extension allowances by requiring new gas customers to pay the full cost of their own gas connections, and clarified that final determinations would be made in the CCP dockets. The utilities filed revised tariffs and joint testimony on October 20, 2025, arguing that existing LEA/CIAC policies are not subsidies but revenue-based cost-allocation mechanisms, and that eliminating allowances would force new customers to pay twice, raise housing and development costs, create implementation problems, and potentially push some projects toward higher-emitting fuels where electrification is not feasible. Advocates, DOER, and consumer/environmental parties counter that LEAs socialize the risks of new gas infrastructure across existing ratepayers, rely on long-term gas demand assumptions inconsistent with the state’s 2050 climate mandate, and undermine the DPU’s Future of Gas framework by continuing to encourage gas-system expansion. Deliberations on the line extension allowance policy are continuing well into 2026.

Minnesota

In progress/ partial reform

Advocates argue that ending LEAs could save customers an estimated $34 million each year. (Clean Heat Minnesota). Minnesota has now adopted a partial reform package for gas LEAs through its Future of Gas docket, though the official order is still forthcoming. At its June 4, 2026 hearing, the MPUC moved to cap free footage allowances at no more than 75 feet for service lines and 80 feet for mains (155 feet total), unless a utility justifies a different level in a rate case. For reference, existing allowances varied by utility: CenterPoint was listed at up to 175 feet combined main and service and Xcel was already limited up to 155 feet combined main and service. The Commission also prohibited additional residential contribution-in-aid-of- construction waivers (CIAC) beyond the standard allowance, while directing utilities to consult with the Attorney General on whether targeted waivers may be appropriate for customers who cannot afford upfront extension charges. Utilities must update tariffs, report CIAC waivers annually, survey new customers and builders about what heating systems they would have chosen if gas service were unavailable, and revisit LEA policies if gas throughput or average residential gas use declines for three consecutive years. The decision does not substantially lower the amount existing customers can be asked to subsidize but it raises the evidentiary bar for future allowances, and begins tying gas extension policy to declining gas demand, electrification, and stranded-asset risk.

New Jersey

In progress

In March 2023, New Jersey initiated its future of gas proceeding, In the Matter of the Implementation of E.O. 317 Requiring the Development of Natural Gas Utility Plans (Docket # GO23020099) to align the state’s climate goals with utilities operations. Included within the docket was to consider the “elimination of subsidies that encourage unnecessary investment in natural gas infrastructure that is likely to result in stranded costs to customers” (Order). There has been no activity documented in the docket since July 2023. 

New York

Passed / Pending Implementation

Gas LEAs have been eliminated statewide for new residential gas hookups starting in December 2026. Gov. Hochul signed S.8417/A.8888 on Dec. 19, 2025, with a chapter amendment directing implementation in 1 year, ending the “100-foot rule” that required existing ratepayers to subsidize the first 100 feet of new gas lines. The PSC has proposed the revised language for Title 16 of the New York Code of Rules and Regulations Part 230 and solicited comments on the language. 

Oregon

Passed  / Phasing out

Oregon has adopted utility-specific LEA reforms, with phaseouts underway for major gas utilities. Avista’s gas LEA are scheduled to reach $0 by January 2027 and NW Natural’s should reach $0 by November 2027. In its 2026 Integrated Resource Plan (IRP) review, Oregon PUC staff also directed NW Natural to explain how the LEA phaseout will be incorporated into its load forecasting and demand scenarios, making the reform part of longer-term gas planning (OPUC).

Rhode Island

In progress

Gas LEAs are now a live policy issue in Rhode Island. Rhode Island Energy currently provides gas LEAs though reform is being considered through the state’s Future of Gas docket. In 2026, a Senate resolution requested that the Rhode Island PUC terminate gas LEAs as part of Rhode Island Energy’s rate case, Docket 25-45-GE, citing customer cost-shifting and the state’s emissions reduction requirements (Senate Resolution). On June 10, 2026, the Senate approved the resolution, urging the PUC to examine the impact of gas LEAs and determine whether they should be allowed to continue. 

Washington

Passed/ Phasing out

Like Oregon, Washington has adopted utility-specific LEA reforms, with phaseouts complete in January 2025 for Avista and Puget Sound Energy and with Cascade Natural Gas phasing out by March 2027. NW Natural is the remaining large gas utility in Washington that still offers gas LEAs without a phaseout date.

State

Recent Activity

California

Order Instituting Rulemaking to Establish Policies, Processes, and Rules to Ensure Safe and Reliable Gas Systems in California and Perform Long-Term Gas System Planning (R. 24-09-012)

(Part 2, 2024-present under 24-09-012)

(Part 1, 2020-2024 under R.20-01-007)

The CPUC’s “Future of Gas Part 2” rulemaking (R.24-09-012) is intended to guide California’s long-term transition away from the gas system while advancing near-term decarbonization actions. The proceeding implements SB 1221 (2024), which authorizes up to 30 voluntary neighborhood-scale decarbonization pilots and modifies the gas “obligation to serve” by allowing utilities, with CPUC approval, to reduce the customer consent threshold to no less than 67%. The rulemaking is structured in phases addressing interim actions, long-term gas planning, and SB 1221 implementation, including required mapping of planned pipeline replacements and designation of priority decarbonization zones.

In 2025, utilities submitted 10-year pipeline replacement maps and Priority Neighborhood Decarbonization Zones (PNZs) at the census tract level, prioritizing areas with demonstrated local support and a significant concentration of planned gas main replacements, and supplementing them with high-scoring environmental and social justice communities. The PNZ list remains subject to refinement, with the Commission expected to update and finalize the zones by the end of 2026.

In Q1 2026, the Commission refined the issues for SB 1221 implementation, including how utilities must demonstrate community engagement, notice, property-owner consent, and cost recovery for behind-the-meter zero-emission alternatives. And in Q2 2026, the CPUC issued a proposed decision (PD) establishing the application process for SB 1221 pilots. The PD shifts the proceeding from general pilot design toward a structured application framework, with first-round applications due December 15, 2026. The Decision is expected to be voted on in July of 2026. 

Planned Pipeline Replacement Maps: 

• Pacific Gas & Electric map 
• Southern California Gas Company map
• San Diego Gas & Electric map
• Southwest Gas map

Q2 2026 Update 

SB 1221 Proposed Decision & Application Rounds

• On May 29, 2026, the CPUC issued a proposed decision establishing the application process for SB 1221 neighborhood decarbonization pilots, which will take place in three rounds:
  • Round 1: December 15, 2026
  • Round 2: December 15, 2027
  • Round 3: July 1, 2028, if needed to reach the statewide 30-pilot cap
• Pilot slots are allotted to utilities based on 2024 gas demand. PG&E and SoCalGas/SDG&E each receive seven project slots in Round 1 and seven in Round 2. Southwest Gas receives one project slot, and smaller Commission-regulated gas utilities collectively receive one project slot. Utilities may also submit up to three backup proposals in case approved projects do not move forward. Projects with 100% property-owner consent would not count toward the utility-specific caps or the statewide 30-pilot limit.
• Proposed pilots are not required to be located entirely within designated PNZs. Instead, applications must identify any overlap with PNZs or explain how the project location meets relevant criteria, including disadvantaged or low-income communities, environmental and social justice communities, local support, and concentration of planned gas distribution line replacement projects.

Pilot Eligibility, Customer Services, and Cost-Effectiveness

• Utilities must show that each pilot would enable decommissioning of gas infrastructure and provide a zero-emission alternative to gas service. They also must include a description of what services they’ll be providing to customers,  including replacement of gas appliances with appliances powered by the zero-emission alternative and any property remediation needed to safely install new equipment. They also must estimate customer bill impacts and identify complementary programs that could reduce costs.

Customer Outreach, Consent, and Community Engagement

• Utilities must first collect non-binding expressions of interest from owners of at least 67% of properties in the pilot area. Following pilot approval, utilities must then get binding notarized consent from owners before making capital investments. 
• To obtain this consent, utilities must engage affected customers and can fund CBOs where needed to support outreach and engagement.

Behind-the-Meter Cost Recovery and Future Incentives

• Pilots must show that avoided gas infrastructure costs exceed the costs of implementing the zero-emission alternative, alone or in combination with other funding identified in the application. The calculation must include costs such as appliance purchase and installation, necessary property remediation, incremental electric infrastructure upgrades caused by the pilot, and gas infrastructure decommissioning costs. 
• Program administration costs, evaluation costs, replacement appliance O&M costs, and electric upgrades that would have occurred without the pilot are excluded. The Energy Division will develop an avoided gas infrastructure cost template for comment.
• Utilities will establish accounts for administrative and outreach costs associated with developing applications. They can also request balancing accounts for behind-the-meter implementation costs, amortizing those costs  over no more than 10 years. Financing costs for behind-the-meter work may be recovered at either the account interest rate or the utility’s authorized cost of debt.
• To be developed later are issues including a performance-based shareholder incentive mechanism that would help incentive gas utility participation by using some of the cost savings from pilots for shareholder returns. 

Comments on the PD were filed June 18th, 2026 with reply comments filed June 23, 2026.  

What’s Next

• July 2: Vote on proposed decision
• December 31, 2026: CPUC to update initial decarbonization zones 
• April 1, 2027: Round 1 applications due 

Illinois

The Future of Natural Gas and issues associated with decarbonization of the gas distribution system (Docket # 24-0158)

(2024-present)

In March 2024, the ICC launched a statewide Future of Gas proceeding to examine how Illinois gas utilities’ infrastructure plans align with the state’s decarbonization and electrification goals. Following Phase 1 workshops in 2024, Phase 2 is now underway and organized into three subphases: Phase 2A on decarbonization pathways and technologies; Phase 2B on pilot development and decarbonization pathways working groups; and Phase 2C on legislative and regulatory options related to the future of gas.

Q2 2026: 

Phase 2C: Summary of Initial Legislative and Regulatory Proposals

• On June 15, 2026, the ICC released the draft Phase 2C report, which summarizes legislative, regulatory, and policy proposals submitted through the Future of Gas workshop process.
• The proposals submitted by workshop participants are organized into 12 categories: alternative gases, building codes, electrification, emissions standards, energy efficiency, gas and/or electric utility planning, geothermal or thermal energy networks, industrial, line extensions, program proposals, rate design, and other proposals
• Key proposals related to managed gas transition include non-pipeline alternative frameworks, long-term gas planning, integrated gas and electric planning, service-line NPA programs, obligation-to-provide-heat reforms, accelerated depreciation, securitization, performance metrics, gas fixed charge reform, electrification-enabling rates, and phasing out gas line extension allowances.
• The report also includes competing proposals focused on alternative gases, preserving customer energy choice, gas utility participation in electrification and other pilots, cost-benefit requirements, timeline reforms, regulatory takings protections, and interconnection reforms.

Decarbonization Pathways Study Status and Goals

• The decarbonization pathways study is proceeding in parallel with Phase 2C. E3, with Viridis Consulting and BW Research Partnership, was selected in April 2026 to conduct the study, which will evaluate multiple technology and policy pathways for decarbonizing Illinois’ natural gas sector.
• The pathways study will model net-zero or partial net-zero GHG scenarios by 2050, with interim 2035 targets, and assess costs, reliability, equity, infrastructure needs, environmental benefits, customer bills, health and air-quality impacts, and workforce impacts relative to a business-as-usual case.

What’s Next:

• July 15, 2026: Comments on the draft Phase 2C Summary Report are due.
• Summer 2026: Additional Phase 2C workshops are planned to discuss topics requested by workshop participants.
• September 2026: Final pathways study results are expected to be presented to workshop participants.
• October 2026: The final decarbonization pathways study is expected to be released, and stakeholders will have an opportunity to modify legislative and regulatory proposals based on the study results.
• Fall 2026: A final Phase 2C report summarizing feedback is expected.
• By the end of 2026: The final Phase 2C report is expected to be incorporated into the broader Phase 2 Summary Report.

Maine

Inquiry Regarding Future of Natural Gas (Case No. 2025-00145)

(May 2025-present)

The Maine Public Utilities Commission (MPUC) opened a new Future of Gas proceeding to examine how gas utility regulation should align with the State’s statutory greenhouse gas reduction goals (Notice of Inquiry). Maine law requires economy-wide emissions reductions of 45% by 2030 and 80% by 2050 (from 1990 levels), and carbon neutrality by 2045. The Commission is tasked with facilitating emission reductions consistent with these targets while ensuring safe, adequate, and reasonably priced service.

The inquiry seeks to develop a framework to evaluate the climate impacts of gas infrastructure investments and supply commitments, assess alignment with state climate targets, and examine potential future pathways for methane gas. Initial scope comments (June 2025) revealed a clear split among stakeholders: gas utilities emphasized renewable natural gas (RNG) and hydrogen, while the Office of the Public Advocate, the Governor’s Energy Office, and labor and climate groups supported exploration of thermal energy networks (TENs) and other non-pipeline alternatives.

After a January 2026 workshop where E3 reviewed other states’ Future of Gas frameworks and the Office of the Public Advocate presented a matrix-based evaluation tool, the Commission’s February 2026 procedural orders moved the docket into a written-comment phase. 

Q2 2026:

Comments Responding to Procedural Order

• The March 20, 2026 comment round sharpened the core dispute of the proceeding so far: consumer and environmental advocates urged a stronger climate-and-ratepayer-risk screen, while gas utilities pressed for a flexible, fuel-neutral framework that preserves safety, reliability, customer choice, and consideration of alternative fuels like RNG.
• The Office of the Public Advocate’s comments responded to the February procedural orders by supporting a matrix-style framework that would screen future gas investments against policy alignment, cost and rate impacts, stranded-asset risk, technical feasibility, and energy justice.
• Sierra Club’s comments pushed the framework in a more enforceable direction, emphasizing lifecycle GHG accounting, methane impacts, environmental justice, and non-pipeline alternatives such as electrification, demand response, and thermal energy networks.
• The comments from Summit Natural Gas of Maine and the Unitil-affiliated gas utilities cautioned against adopting a rigid scoring matrix that could prejudge utility obligations or underweight safety, reliability, affordability, and customer choice.

What’s Next

• June-Summer 2026: Commission review of the March 20th comment record.
• Summer-Fall 2026: Potential Commission guidance on whether to adopt, modify, or use the matrix-based framework as an informal reference tool.

Maryland 

Case No. 9707

In February 2023, Maryland’s Office of People’s Counsel (OPC) petitioned the Public Service Commission (PSC) to open a Future of Gas proceeding to evaluate whether gas utility planning, practices, and rates remain “just and reasonable” and consistent with the public interest (pg. 7). Following public comments in 2024 and a renewed OPC petition in 2025, the PSC issued an order on June 13, 2025 signaling its intent to eliminate gas line extension allowances (LEAs) for new connections. The PSC reasoned that subsidies encouraging gas system expansion may conflict with Maryland’s climate goals and obscure the true cost of gas service. Staff were directed to propose LEA regulations by December 1, 2025, to be addressed through Rulemaking 92.

On August 20, 2025, the PSC formally opened a comprehensive Future of Gas proceeding (Order 91791) within Case No. 9707 to examine the long-term role of natural gas in light of Maryland’s greenhouse gas reduction and electrification commitments. Citing the Climate Solutions Now Act and the Next Generation Energy Act, the Commission will evaluate:

• Gas system planning practices
• Rate design reforms
• Stranded asset risk
• Limits on system expansion
• Non-pipeline alternatives and alternative fuels
• Leak repair practices
• Integration of emerging technologies and demand-side strategies
• The impact of STRIDE reforms on gas investment decisions
• Whether maintaining current gas consumption levels is compatible with state climate targets

Q2 2026:

Phase II Testimony Record

• In May 2026, organizations and utilities filed testimony for the Future of Gas proceeding. On the environmental and consumer advocate side was Chesapeake Climate Action Network, Maryland Department of the Environment, Maryland Energy Administration, Sierra Club, OPC, and PSC Staff. 
• As a whole, this testimony built the record on the need for gas utility planning to shift from traditional growth-oriented forecasting toward scenario-based planning that accounts for building electrification, declining gas demand, climate-law compliance, customer affordability, and long-term stranded-cost risks.
• OPC’s expert testimony argued that gas utilities should use more rigorous forecasts and project-justification standards before customers fund long-lived infrastructure, and that non-pipeline alternatives and electrification should be compared against pipeline replacement, expansion, and supply-contract costs.
• Environmental and climate-focused testimony from CCAN and Sierra Club emphasized that Maryland’s gas planning rules should be evaluated against state climate requirements, methane and lifecycle emissions, and the risk that continued gas-system investment could leave a shrinking customer base paying for assets that are no longer needed. Their filings supported stronger screens for gas expansion, more robust NPA analysis, and closer scrutiny of alternative fuels.
• State agency testimony from MDE and MEA gave the Commission a climate-policy and implementation frame for the gas transition. MDE’s testimony connected the proceeding to Maryland’s emissions-reduction obligations, while MEA’s testimony focused on the interaction between gas planning, building electrification, energy efficiency, affordability, reliability, and practical implementation of clean-heat policies.

LEA Reform (RM 92)

• The parallel rulemaking on removing line extension allowances for gas has been stalled. 
• See the update earlier in the report here. 

What’s Next:

• June-Summer 2026: Commission and Special Master review of the Phase II testimony record and the pending utility appeals, stay requests, and motions related to the May 1 order.
• Summer 2026: rebuttal testimony and continued record development on demand forecasting, capital planning, NPAs, alternative fuels, cost allocation, reliability, and affordability.
• September-October 2026: final statements and replies expected under the Special Master schedule.
• December 2026: Special Master’s report expected, followed by party comments before year-end. 

Massachusetts

The Future of Gas (Docket #: 20-80)

(2020-present) 

Utility Climate Compliance Plans: (25-40, 25-41, 25-42, 25-43, 25-44, 25-45)

In its landmark December 2023 order in the “Future of Gas” docket, the Massachusetts Department of Public Utilities (DPU) established a new standard for gas system investment consistent with the state’s net-zero by 2050 mandate. The DPU shifted the burden of proof to gas utilities, requiring them to demonstrate that non-pipeline alternatives (NPAs) are either not cost-effective or infeasible before proceeding with major gas infrastructure investments, including full pipeline replacements. This marked a departure from business-as-usual gas expansion and laid the groundwork for reassessing long-term stranded asset risk and ratepayer exposure.

In 2024, the DPU turned to reforming gas line extension allowances (LEAs). Utilities were directed to report on their LEA practices, and in a February 5, 2025 memorandum, the Department proposed eliminating LEAs by requiring new customers to pay the full cost of connecting to the gas distribution system. The proposal further stated that “no costs associated with a new service or line extension shall be deemed prudently incurred and, thus, eligible for inclusion in an LDC’s rate base” (Feb. 5, 2025 Memorandum). 

Implementation is occurring through the 2025 Climate Compliance Plan (CCP) dockets: D.P.U. 25-40 for Berkshire Gas, D.P.U. 25-41 for National Grid, D.P.U. 25-42 for Unitil, D.P.U. 25-43 for Liberty, and D.P.U. 25-44/25-45 for Eversource’s EGMA and NSTAR Gas companies. These dockets are the mechanism for implementing D.P.U. 20-80-B‘s requirements on emissions-reduction planning, NPAs, line-extension policy, decommissioning, and stranded-cost risk. The initial CCP were filed in April 2025 and were supposed to expand on the utilities’ net-zero enablement plans, detail total investment necessary and at least one alternative pathway, include customer/stakeholder/community input, and report on hybrid-heating switchover practices. The CCP dockets are also the forum for investigating NPA analysis before pipeline projects, decommissioning and depreciation practices, stranded costs from GSEP investments, whether GSEP should be combined into CCP review, and line-extension allowance policies.

In a subsequent Interlocutory Order, the DPU proposed a simplified policy to eliminate LEAs and clarified that final determinations would be made within these CCP dockets. Utilities sought a stay, citing procedural concerns, but the Department directed them to file revised tariffs  reflecting removal of LEAs. At the same time, the Department began evaluating how the state’s 2024 climate law (S. 2967) reshapes the gas “obligation to serve,” including whether utilities may retire gas service in favor of electrification or thermal energy networks, and whether neighborhood-scale decarbonization projects can proceed without unanimous customer consent. The central question is whether the obligation to serve guarantees indefinite gas service upon request, or whether the DPU may permit targeted retirement of gas infrastructure where adequate non-gas alternatives exist. This issue is critical to whether neighborhood-scale electrification or thermal energy network projects can proceed without unanimous customer consent.

From April to June 2026, utilities and intervenors filed initial and reply briefs regarding the utilities’ CCPs. The most significant development was broad criticism of the CCPs from DOER, the Attorney General, and environmental/consumer advocates, who argues that the utilities’ plans do not comply with the Department’s Future of Gas directives and are simply enabling the continuance of a business-as-usual gas expansion framework.

Q2 2026:

April 2026 Initial Briefs Challenging the Plans

• DOER critiqued the CCPs, arguing that because they are not actionable or enforceable, do not meaningfully contribute to statewide emissions reductions, and do not build adequately on the prior net-zero enablement plans, they should be rejected and refiled. DOER also argued that the utilities’ NPA framework would not avoid GSEP replacements on a reasonable timeline and should be revised with clearer customer-engagement, viability-testing, cost-effectiveness, rate-impact, and annual-update requirements.
• Advocate groups CLF, EDF, and Sierra Club asked the Department to reject the utilities’ plans and require resubmission. Their central argument was that the plans largely continue the existing gas-system trajectory rather than providing a concrete, enforceable roadmap for winding down gas use, reducing climate pollution, avoiding unnecessary infrastructure spending, and protecting customers from rising gas-system costs.
• The Attorney General also criticized the plans during this briefing round, arguing that the utilities had not followed the Department’s instructions to produce meaningful climate compliance roadmaps and should face stronger consequences if substantially revised plans are not filed.

Utility Response

• In the June reply brief filed collectively for the gas utilities, the utilities defended their initial CCPs and urged the DPU to reject calls from DOER, the Attorney General, and environmental intervenors to reject or require wholesale refiling of the plans. The utilities argued that the CCPs should be treated as the first step in an iterative five-year planning process, not as immediately enforceable emissions-compliance plans or a vehicle for resolving every Future of Gas implementation issue at once. 
• Utilities pushed back on claims that the plans fail because they do not quantify all Scope 3 reductions or commit to specific decommissioning outcomes, emphasizing safety, reliability, affordability, customer choice, and the continuing obligation to serve. The brief also resists prescriptive requirements on NPAs, line-extension allowance reforms, depreciation, stranded-cost treatment, and cost recovery, arguing those issues should be handled through tariff filings, rate cases, GSEP proceedings, or future CCP updates with utility-specific records rather than through broad rejection of the initial CCPs.

What’s Next:

• Summer-Fall 2026: Possible Department order on whether the six CCPs satisfy D.P.U. 20-80-B and what revisions are required for NPA screening, line-extension allowances, GSEP integration, decommissioning, depreciation, and stranded-cost controls.
• Late 2026 (anticipated CCP Orders): The Department is expected to resolve LEA reform and define how the obligation to serve applies in a managed gas transition.

Minnesota

In the Matter of a Commission Evaluation of Changes to the Natural Gas Utility Regulatory and Policy Structures to Meet State Greenhouse Gas Reduction Goals (Docket #: G-999/CI-21-565)

(2021-present)

In 2021, the Minnesota Legislature directed the Public Utilities Commission (PUC) to evaluate changes to natural gas regulatory structures needed to meet or exceed the state’s greenhouse gas reduction goals. The Commission opened the Future of Gas docket (G999/21-565) to implement this directive. Much of the early work proceeded through gas utilities’ Integrated Resource Plan (IRP) proceedings, culminating in March and October 2024 orders addressing modeling assumptions, emissions pathways, and planning transparency.

In January 2025, the Commission reset the scope and timeline, returning focus to the Future of Gas docket. Current informational hearing topics include winter reliability, renewable natural gas (RNG), hydrogen and other alternative fuels, hybrid heating rate design, and updates from the Thermal Energy Network (TEN) Work Group. In parallel, the Commission initiated review of gas line extension allowance (LEA) policies before a comment period evaluating changes to rates to promote heat pump affordability and evaluate and address stranded asset risks as a result of electrification.

In June 2026, the Commission met to discuss the LEA policy, among other issues, and determined that they would only make minor modifications to the policy (see the LEA summary above). 

Q2 2026:

June 4th Hearing

• The major activity in the docket was addressing the issue of whether the Commission should modify gas line extension allowances.
• As discussed in the LEA summary above, the Commission took minor action, lowering the footage allowance by twenty feet for Centerpoint and with no change for Xcel. 
• The Commission did require gas utilities to file a report in the future whenever they see a “sustained” reduction in gas throughput, however, and whether that decline in demand warrants a revision to the LEA policy. 
• All utilities must also draft survey questions to ask residential customers, builders and developers which heating option they would choose in the absence of natural gas service, including electric, delivered fuel or heating oil. The responses will be filed with the commission beginning in 2027.

What’s Next

• First Gas IRP Filing: Xcel Energy is scheduled to file Minnesota’s first gas IRP in July 2026; CenterPoint is expected to file in July 2027; MERC is expected to file in July 2028. While related to the Future of Gas, these filings will take place in docket no. 23-117. In the Commission’s recent order, it was determined that that utilities would evaluate compliance costs in their IRPs under 3 scenarios: 1) no GHG compliance costs 2) methane regulation at $13/metric ton CO2e for production emissions starting in 2030 and distribution-system emissions starting in 2035 and 3) broader methane plus end-use CO2 regulation starting in 2030, with CO2 costs ranging from $5 to $75/ton. Utilities also are required to conduct 2-3 Expansion Alternatives Analyses to evaluate alternatives, such as non-pipeline alternatives, to planned gas system expansion projects greater than $1 million in investment. Utilities are not required to implement these alternatives. 

New York

Proceeding on Motion of the Commission in Regard to Gas Planning Procedures 

(Docket # 20-G-0131)

(2020-present) 

Associated dockets: 24-G-0248, 23-G-0676, 23-G-0437, 23-G-0147, 22-G-0610 

The New York gas planning docket (20-G-0131) originated in response to gas moratoria concerns but has since identified the need for a statewide framework for managed gas transition planning. The PSC now requires each gas utility to file a Long-Term Gas Plan (LTGP) every three years in separate utility-specific dockets.

Each LTGP must include at least one scenario with no new traditional gas infrastructure, quantify greenhouse gas impacts, evaluate non-pipeline alternatives (NPAs), and provide updates on demand forecasts, electrification progress, and system risks.

Q2 2026:

• The PSC issued proposed language for revising Title 16 of the New York Code of Rules and Regulations Part 230 in light of the removal of the state’s “100-foot-rule,” or gas line extension allowance. Comments on the language were due on June 26, 2026.

Utility-Specific Gas Planning:

Central Hudson Gas & Electric (23-G-0676):

• Central Hudson issued their annual long-term gas plan update (LTGP) in May 2026.

New York State Electric & Gas Corporation and Rochester Gas and Electric (23-G-0437): 

• Annual LTGP update filed in June 2026.

ConEd and Orange and Rockland Utilities (23-G-0147): 

• Annual LTGP update filed in May 2026. 

National Grid (24-G-0248):

• Annual LTGP update filed in May 2026.

National Fuel Gas Distribution Corp. (22-G-0610):

• Annual LTGP update filed in May 2026. 

What’s Next (Long-Term Gas Plans)

• Finalize Title 16 Part 230 language following comment period.

Rhode Island

Investigation into the Future of the Regulated Gas Distribution Business in Rhode Island

Docket #: 22-01-NG

The Rhode Island Public Utilities Commission opened the Future of Gas investigation in June 2022 to examine the future of the regulated gas distribution business in light of the Act on Climate. The docket produced extensive stakeholder process work and an E3 technical analysis, but has not had significant activity in the past year. The most meaningful development in 2026 is how the Future of Gas issue of gas line extension allowances surfaced in RI Energy’s pending 25-45-GE electric/gas rate case and in companion House (H7891) and Senate (S2354) resolutions that are asking the PUC to terminate gas line-extension allowances in that rate case.

Q2 2026:

• While there has not been activity in the Future of Gas docket itself, a parallel rate case and the legislative session have become venues for raising one aspect of that docket: whether gas line extension allowances should be removed or reformed. 
• H7891 and S2354 ask the PUC to terminate gas line-extension allowances as part of RI Energy’s 25-45-GE rate case. The resolutions frame the existing allowance as a ratepayer-funded subsidy for new gas connections and argue that continued gas expansion conflicts with the State’s 2030, 2040, and 2050 emissions requirements.
  • Testimony on LEAs tie the issue to the Future of Gas docket and argue that the state should reduce incentives for gas-system growth, including eliminating broad-based subsidization of new gas connections.
• In RI Energy’s rate case (25-45-GE), Conservation Law Foundation requested information on LEAs from RI Energy during discovery, which shows that the company is aware of gas line-extension reforms in other states but has not produced internal work product examining them and believes its current policy remains appropriate. RI Energy’s May 11 rebuttal testimony by Michele Leone and David Moreira defends current LEA practices.

State / Rule or Regulation

Recent Activity

Category

California, Rulemaking Regarding Building Decarbonization (R. 19-01-011)

The Building Decarbonization Rulemaking was opened in 2019 following the passage of SB 1477, which provided cap-and-invest funding for two building electrification pilot programs: the Building Initiative for Low-Emissions Development (BUILD) Program and the Technology and Equipment for Clean Heating (TECH) Initiative. 

The proceeding has since evolved beyond oversight of the original pilot programs into a broader forum for implementation lessons, zonal decarbonization concepts, and coordination across related CPUC proceedings. Activity at the end of 2025 and beginning of 2026 focused on procedural extensions, PG&E’s CSU Monterey Bay zonal electrification “lessons learned” report, and a Commission-convened workshop on best practices and future pathways for scaling building decarbonization. 

Q2 2026:

Building Decarbonization Action Plan and Pilot Reports

• On March 20, 2026, CPUC issued an Administrative Law Judge (ALJ) ruling seeking information on building decarbonization and entering the draft reports for the Building Initiative for Low-Emissions Development (BUILD) and Technology and Equipment for Clean Heating (TECH) pilot programs into the record. The ruling asked parties to comment on lessons learned from the BUILD and TECH pilots, the January 2026 Building Decarbonization Best Practices and Future Pathways Workshop, and what should be included in a future Building Decarbonization Action Plan.
• Action Plan Scope and Governance: Parties generally supported the Building Decarbonization Action Plan, but were split on how directive it should be. Sierra Club urged a cross-agency roadmap that identifies barriers, solutions, responsible venues, and timelines, while Pacific Gas and Electric (PG&E) argued that the plan should provide strategic coordination without deciding issues pending in Energy Efficiency (EE), Distributed Energy Resources (DER), rate design, or general rate case proceedings.
• Rates, Affordability, and Cost Recovery: Sierra Club, Natural Resources Defense Council (NRDC), and the City and County of San Francisco raised rate design, bill neutrality, and affordability issues as central to scaling electrification, while PG&E argued that those issues should be handled in dedicated rate proceedings. The California Environmental Justice Alliance (CEJA) also raised concerns about how electric distribution upgrade costs could affect environmental justice communities; PG&E disagreed with CEJA’s proposal to treat certain upgrades as operating expenses, arguing that long-lived assets should remain capitalized.
• Coordination and Neighborhood-Scale Decarbonization: Several parties emphasized that building decarbonization will require coordination among utilities, local governments, CCAs, Regional Energy Networks, and community-based organizations. The California Municipal Utilities Association emphasized early engagement and information-sharing to avoid grid-readiness problems, while the Local Government Sustainable Energy Coalition supported more formal coordination requirements; PG&E supported coordination but cautioned against rigid statewide requirements that could slow implementation.
• Panel Upgrades and Grid Constraints: SPAN.IO’s opening comments argued that smart panels, managed load, and power control systems can reduce the cost of electrification by avoiding unnecessary panel upsizing and upstream distribution upgrades. Southern California Edison (SCE) also raised cost-effectiveness concerns, including whether current EE cost-effectiveness frameworks limit building electrification incentives.
• New Construction vs. Existing Building Retrofits: San Francisco argued that the Action Plan should focus limited public-purpose program funding on existing-building retrofits rather than all-electric new construction, where building codes and elimination of gas line-extension subsidies are already shifting the market. PG&E disagreed, arguing that EE-funded new construction incentives still help move builders beyond current code toward efficient all-electric buildings.

What’s Next

• Summer-Fall 2026: CPUC staff and the ALJ are expected to use the March-April comment record to shape the Building Decarbonization Action Plan, including how it will incorporate BUILD and TECH pilot lessons, workshop findings, affordability concerns, service-upgrade barriers, and coordination with other CPUC proceedings.

line extension allowances, rebates and incentives; grid management; workforce

California

OIR for Oversight of Energy Efficiency Portfolios, Policies, Programs, and Evaluation (R.25-04-010).

Natural Gas Energy Efficiency Incentives Policy

In April 2025, the CPUC opened R.25-04-010 as the successor to the long-running energy efficiency rulemaking, establishing a new forum for oversight of energy efficiency portfolios, cost-effectiveness policy, and program administration.

Of central concern is the reconsideration of ratepayer-funded incentives for gas-burning appliances. In late 2025, staff proposed further phasing out gas EE incentives where viable electric alternatives (VEAs) exist.

Q2 2026: 

• In April 2026, the gas utilities filed their 2025 Energy Efficiency (EE) annual reports.

2025 Energy Efficiency Annual Reports

• Pacific Gas and Electric (PG&E): PG&E’s 2025 Energy Efficiency (EE) Annual Report presents a relatively strong portfolio that is on track to meet its 2024-2027 goals, with the company emphasizing building electrification, load flexibility, financing, and local climate-action support. PG&E is using EE programs not only for traditional efficiency savings, but also to test electrification strategies, including the “Empower My Home” program for underserved customers and neighborhood-scale electrification pilots designed around targeted gas-system retirement or avoided gas infrastructure.
• San Diego Gas & Electric (SDG&E): SDG&E’s 2025 EE Annual Report argues that its service territory has limited remaining opportunities for cost-effective EE because of higher baseline codes, customer participation barriers, rising costs, and overlap with other program administrators. The report supports SDG&E’s broader push to shrink and refocus its EE portfolio, rely more heavily on statewide programs, and coordinate with the San Diego Regional Energy Network (SDREN) rather than continuing broad regional program administration.
• Southern California Edison (SCE): SCE’s 2025 EE Annual Report portrays EE as evolving from a traditional savings program into a grid and affordability resource. SCE emphasizes portfolio discipline, lower spending, customer bill savings, Strategic Energy Management (SEM), normalized metered energy consumption (NMEC), whole-building approaches, electrification, and demand flexibility. Although SCE is not a gas utility, its report is relevant because it shows how electric EE portfolios are being positioned to support building electrification and manage new electric load.
• Southern California Gas (SoCalGas): SoCalGas’s 2025 EE Annual Report emphasizes that they believe there is EE value in gas and dual-fuel programs. Overall, the utility continues to defend a “fuel-neutral” approach to statewide EE, arguing that customers should retain access to high-efficiency gas measures as well as electric alternatives. 

What’s Next:

• The Commission is expected to issue a Proposed Decision on natural gas incentive policy in 2026.

gas subsidies, energy efficiency

Colorado

Xcel Gas Energy Plan

25A-0220G

This proceeding is Colorado’s first fully adjudicated Gas Infrastructure Plan (GIP) case under the state’s gas planning rules. Xcel sought approval of its 2025-2030 GIP, including prospective review of planned gas infrastructure investments and a cost-recovery structure for non-pipeline alternatives (NPAs). The plan included about $572.4 million in planned projects over the 2025-2030 action and informational periods, within a broader gas capital plan of roughly $2.85 billion through 2029. The proceeding tests how Colorado’s GIP rules will be used to evaluate gas-system growth, customer affordability, clean heat compliance, forecasting, NPAs, and whether gas infrastructure investments remain prudent as electrification and climate mandates change long-term gas demand.

Q2 2026:

• On June 4, 2026, the Colorado PUC issued Decision No. C26-0371, granting Xcel’s application in part and denying it in part.
• The Commission found that Xcel had not made a good-faith effort to comply with prior directives on NPA cost-benefit analysis and ordered the company to file an updated CBA Handbook within 60 days.
• They also directed Xcel to develop service-line NPA and other pilot proposals and recognized that thermal energy networks can qualify as NPAs under Colorado’s gas planning rules.
• The decision raised broader concerns that Xcel’s capital-spending incentives may be misaligned with customer interests and climate policy, especially in a declining-gas-sales environment where remaining customers could bear higher fixed costs.
• Finally, the Commission flagged future rate cases as the venue to consider reforms such as line-extension cost allocation, differentiated returns, securitization, deferrals, or other mechanisms to reduce the link between gas capital spending and utility earnings.

What’s Next:

• Summer 2026: Xcel must file an updated Cost-Benefit Analysis (CBA) Handbook within 60 days of the June 4, 2026 decision, incorporating the Commission’s required changes to how it evaluates Non-Pipeline Alternatives (NPAs).
• Summer-Fall 2026: Xcel is expected to advance service-line NPA and other pilot proposals through the Clean Heat Plan process, including potential pilots for local electrification, thermal energy networks, and other alternatives that could avoid or defer gas infrastructure.

Gas planning, NPAs, pipeline replacement

D.C.

In The Matter Of The Investigation Into Washington Gas Light Company’s Strategically Targeted Pipe Replacement Plan

(Case # 1179)

Washington Gas Light’s accelerated pipeline replacement program (formerly ProjectPIPES) remains under active scrutiny as the District weighs safety, climate alignment, and ratepayer risk.

In December 2022, WGL filed its PIPES 3 proposal, a five-year, $671.8 million plan. In June 2024, the Public Service Commission of the District of Columbia (DC PSC) dismissed it, directing the utility to refocus on high-risk pipe replacement and better align with the District’s climate goals. WGL refiled in September 2024 as the Strategic Accelerated Facility Enhancement (SAFE) Plan, proposing $215 million over three years to replace 12.4 miles of main and 3,608 service lines, with continued recovery through the existing surcharge mechanism. Consumer advocates argued the revised plan still failed to adequately evaluate non-pipeline alternatives (NPAs), including electrification, and did not sufficiently address stranded asset risk. Rather than approving SAFE immediately, the Commission extended the existing surcharge through the end of 2025 with a $34 million spending cap and moved the case into an evidentiary phase focused largely on WGL’s JANA risk model.

In March 2026, the Commission approved a modified SAFE plan, cutting WGL’s proposed budget by roughly 30 percent and imposing tighter annual caps, threshold-based cost recovery, and enhanced reporting requirements. 

Q2 2026: 

District SAFE Plan Oversight

• On April 3, 2026, WGL filed its initial Year 1 Annual Project List for the Modified District SAFE Plan, which was rejected as insufficient by the DCPSC and then refiled on April 21, 2026.
• On May 20, 2026, the DCPSC issued Order No. 22867, holding implementation of the Modified District SAFE Plan “in abeyance” until further Commission order. This followed reconsideration requests by the Office of the People’s Counsel (OPC), District Government, and Sierra Club, who argued that additional disputed material facts required evidentiary review. The order also paused review and approval of the annual project lists.

What’s Next

• The pre-hearing conference took place in June and post-hearing briefs are due by August 11. 
• The Modified District SAFE Plan and Year 1 project-list review remain paused until the Commission issues a further order.

accelerated pipeline replacement, NPAs

D.C.

Integrated Distribution System Planning (“IDSP”) FC 1182 and Integrated Natural Gas Distribution System Planning proceeding (“INGDSP”), FC # 1187)

The D.C. PSC opened Formal Case No. 1182 in late 2024 to create a more coordinated, transparent, and climate-aligned framework for electric distribution planning. The docket responds to long-running concerns that Pepco’s planning, load forecasting, and DER integration processes are too fragmented and insufficiently aligned with the District’s clean energy goals. In July 2025, the Commission directed that an IDSP Working Group be convened to develop recommendations on load forecasting, data transparency, DER valuation and hosting capacity, and resilience, electrification, and equity.

In March 2026, the Commission opened a new Integrated Natural Gas Distribution System Planning proceeding (“INGDSP”, Case # 1187), signaling that future gas replacement spending will be evaluated within a broader long-term gas planning and decarbonization framework.

Q2 2026:

• The IDSP Working Group continued in May 2026, with filings and discussion focused on turning the docket’s broad planning goals into a concrete framework. Pepco’s presentation described its current distribution planning process, including load forecasting, constraint identification, and consideration of non-wires solutions such as storage and demand response. DOEE and OPC’s presentation proposed a more formal IDSP framework with a three-year cycle, annual updates, scenario-based load and distributed energy resource (DER) forecasting, grid-needs assessments, non-wires alternative (NWA) screening, hosting capacity transparency, affordability review, and clearer links to rate cases. The May 5 Working Group session centered on defining NWAs, improving DER valuation and hosting capacity data, and using benefit-cost analysis (BCA) to compare traditional grid investments with targeted alternatives.
• The June Working Meetings focused on DER valuation/hosting capacity, climate resilience and equity, asset replacement, reliability and resilience planning, and IDSP performance metrics as well as the continued development of the IDSP framework.

What’s Next: 

• The working group will continue technical sessions through summer 2026, with a final report expected in August. 
• The Commission will then determine the requirements for Pepco’s first formal IDSP filing and how the new framework will interact with future rate cases and climate-related proceedings.

Integrated system planning, electric system

Massachusetts

Eversource Geothermal Rate Case (DPU 25-86)

On September 17, 2025, NSTAR Gas (Eversource Energy) filed a petition seeking approval of a regulatory framework and new geothermal rate to develop networked geothermal systems in new construction projects in its service territory.

The filing follows the Department’s 2023 policy decision in D.P.U. 20-80-B and recent statutory changes that explicitly authorize gas companies to make, sell, or distribute networked geothermal energy.

The proposal seeks to establish a structured process for evaluating geothermal alongside natural gas in new developments and to create a dedicated geothermal rate for participating customers.

Under the proposed framework:

• Participating customers would take service under a new geothermal rate in lieu of traditional gas distribution charges. The rate will be sized by tonnage, and be comparable to existing gas rates.
• Revenues collected from geothermal customers would flow through the Geothermal Energy Provision (GEP) of the Company’s Local Distribution Adjustment Clause (LDAC), while the differential between geothermal system costs and geothermal rate revenues would be supported—up to a $15 million cap over five years—by Eversource Gas customers.
• Developers could compare geothermal and gas on a side-by-side basis using a contribution-in-aid-of-construction (CIAC) framework, with an expedited regulatory review process for qualifying projects.
• If approved, the framework would move networked geothermal from pilot status to a structured, rate-regulated offering embedded within gas utility planning.

The filing is structured as a Tier 2 proceeding and includes testimony from both a Geothermal Panel and a Rates Panel.

Q2 2026:

Massachusetts D.P.U. 25-86 Q2 Update: Eversource Networked Geothermal Rate

• During the May comment period, commenters generally supported networked geothermal but urged caution on rate design. Conservation Law Foundation (CLF) and Environmental League of Massachusetts (ELM) argued that any approved rate should be interim, not permanent, because geothermal costs, performance, and ratepayer impacts are still developing. They also urged stronger protections to ensure customers benefit from avoided gas infrastructure costs and future cost reductions.
• CLF and ELM also pushed for more data transparency, including lifecycle comparisons between gas and geothermal systems, clearer avoided-cost analysis, and project performance data. ELM specifically raised concerns that Eversource’s proposed unmetered rate may not provide enough usage data to evaluate scalability or encourage efficient customer behavior.
• Dandelion Energy supported the proceeding but argued the framework is too narrow because it focuses on networked geothermal systems. Dandelion urged the DPU to include individual, non-networked geothermal systems in new construction, or require Eversource to file a companion framework for those systems.
• On June 23, 2026, a technical conference was held, featuring Massachusetts Clean Energy Center (MassCEC), Home Energy Efficiency Team (HEET), and Eversource presentations on geothermal network research, data standardization, cost reduction, equity, electric-grid impacts, and lessons from the Framingham pilot.

What’s Next

• Intervenor testimony is due July 10, 2026, followed by Eversource rebuttal testimony on August 18. 

thermal energy networks, rates

Massachusetts

Inquiry by the Department of Public Utilities on its own Motion into Energy Burden with a Focus on Energy Affordability for Residential Ratepayers

D.P.U. 24-15

In January 2024, the Massachusetts Department of Public Utilities (DPU) opened an inquiry to examine residential energy burden and improve affordability for electric and gas customers. “Energy burden” is defined as the share of a household’s annual income spent on utility bills; for example, a 4% energy burden target means combined annual electric and gas bills are calibrated not to exceed roughly 4% of household income under modeled usage assumptions.

Following extensive stakeholder comments, workshops, technical sessions, and model development, the DPU issued a Phase I Order on February 17, 2026 establishing a new statewide framework for tiered low-income discount rates. The Order represents a structural shift from flat percentage discounts to an income-tiered model explicitly tied to target energy burdens.

Q2 2026:

Phase II Implementation Comments

• In May 2026, DPU received Phase II comments on how to implement the new six-tiered Low-Income Discount Rate (LIDR) by November 1, 2026. The comments focused less on whether tiered discounts should exist and more on the mechanics of making them work: enrollment pathways, income and household-size verification, default tier placement, customer movement between tiers, one-stop-shop design, outreach, and Community Action Agency (CAA) funding.

Massachusetts D.P.U. 24-15 Q2 Update: Tiered Low-Income Discount Rate Implementation

• In May 2026, the DPU received Phase II comments on implementation of the six-tiered Low-Income Discount Rate (LIDR), with the record focused on enrollment, income verification, default tier placement, outreach, Community Action Agency (CAA) funding, and readiness for the November 1, 2026 launch.
• Commenters generally supported using the lowest discount tier as the default when a customer is income-eligible but lacks verified tier information, while emphasizing the need for a clear path to move customers into the correct tier once income and household-size data are verified.
• The main dispute was over customer protections and enrollment flexibility.
• Commenters also focused on how to make enrollment easier with a digital “one-stop shop” integrated with utility systems.

What’s Next

• Utilities are preparing for the November 1, 2026 launch of the six-tiered LIDR. Additional comments on self-attestation fraud costs and verification costs are due July 17, 2026, and the DPU plans to assess the tiered discount programs after implementation.

rates, affordability, energy burden

New York, 

Energy Efficiency and Building Electrification proceedings 

14-M-0094: Proceeding on Motion of the Commission to Consider a Clean Energy Fund

18-M-0084:  In the Matter of a Comprehensive Energy Efficiency Initiative

25-M-0248: In the Matter of the 2026-2030 non-Low- to Moderate-Income Energy Efficiency and Building Electrification Portfolio

25-M-0249: In the Matter of the 2026-2030 Low- to Moderate-Income Energy Efficiency and Building Electrification Portfolio

The Energy Efficiency and Building Electrification proceeding, formerly referred to as “New Efficiency: New York (NE:NY),” is the state’s $5 billion portfolio of ratepayer-funded energy efficiency and electrification incentive programs. These offerings were under regulatory review by the NYS Public Service Commission to improve program design, spending, and accountability.

On May 15, 2025, the Commission established two new proceedings—one for Low- and Moderate-Income (LMI) programs (25-M-0249) and one for market-rate programs (25-M-0248)—authorizing approximately $1 billion per year for 2026–2030 in energy efficiency and clean energy solutions, including building electrification. Administered by the state’s investor-owned electric and gas utilities and NYSERDA, nearly one-third of the funding ($1.57 billion) is dedicated exclusively to LMI programs.

Following the May 2025 orders, the Commission advanced implementation of the broader Clean Energy Fund (CEF), including approval of the 2026–2030 Innovation & Research (I&R) portfolio and modifications to the New York Green Bank (NYGB). Together, these actions shape the innovation, financing, and market infrastructure supporting building electrification through 2030.

Q2 2026:

Clean Energy Fund (14-00549) 

• CEF Reporting: On June 1, 2026, NYSERDA filed the Clean Energy Fund (CEF) Q1 2026 Quarterly Report and Dashboard Scorecard, aligning quarterly performance reporting with its April 2026 Compiled Investment Plan.
• New York Green Bank: NY Green Bank filed its Metrics, Reporting & Evaluation Plan 4.0 and 2026-2027 Annual Business Plan. The plan begins implementation of the Commission’s 2026 NYGB modifications, including investment targets for building decarbonization, affordable housing, energy efficiency, and benefits to Disadvantaged Communities and Low- to Moderate-Income (LMI) New Yorkers.

Market-Rate / Non-LMI Programs (25-M-0248)

• Hybrid Heating Study: DPS Staff filed a revised hybrid heating report on May 21, 2026. The report responds to the Commission’s directive to evaluate hybrid heating within the 2026-2030 Energy Efficiency and Building Electrification (EE/BE) portfolio.
• Weatherization and DACs: There was a June 16 technical conference on weatherization for Disadvantaged Communities (DACs). 

LMI Programs (25-M-0249)

• Implementation Plan Approval: On March 18, 2026, DPS Staff issued an LMI EE/BE Implementation Plan compliance letter, following up on deficiencies identified in the December 2025 compliance review.
• Weatherization and DAC Coordination: There was also a technical conference on weatherization for LMI programs, with a focus on EmPower+ and affordable multifamily offerings as tools to reduce energy burden, improve housing quality, and prepare homes for electrification.

What’s Next

• DPS Staff expects to finalize the revised EE/BE reporting template by June 30, 2026, after which Q1 reports will be filed. Q2 reports remain due by August 29, 2026. The June DAC weatherization conference, hybrid heating report, and NYGB filings will shape how New York tracks and implements the 2026-2030 portfolios across weatherization, electrification readiness, LMI access, and building decarbonization finance.

energy efficiency, electrification, LMI programs

New York, Utility Thermal Energy Network and Jobs Act (UTENJA) 22-M-0429

Since being directed by the 2022 UTENJA law, New York utilities have been exploring how they can use thermal energy networks to decarbonize entire neighborhoods across the state. There are currently 10 proposed pilot projects under PSC review. The proceeding has moved from feasibility analysis to detailed engineering design, lifecycle cost validation, and customer protection planning, positioning several pilots for potential Stage 3 construction decisions.

Q2 2026:

• Con Edison, Orange and Rockland, National Grid, and NYSEG/RGE all have pilots that have completed comment period on Stage 2 supplemental filings. These projects are awaiting approval from the Public Service Commission to move to Stage 3, which includes customer enrollment and construction
• Central Hudson has a pilot project with Stage 2 filings that are open for comments until June 29th. 
• National Fuel Gas has filed their Stage 2 filings, but a comment period has not yet been opened. 
• Details on the projects can be found here or in the docket. 

What’s Next:

• Determinations on whether individual pilots may advance to Stage 3 (customer enrollment and construction).
• Continued monthly progress and expenditure reporting.
• Potential additional stakeholder process if further revisions are required prior to Stage 3 authorization.

thermal energy networks, workforce, neighborhood scale