The California Global Warming Solutions Act of 2006 designates the State Air Resources Board as the state agency charged with monitoring and regulating sources of emissions of greenhouse gases. The act authorizes the state board to include the use of market-based compliance mechanisms in regulating those emissions. The implementing regulations adopted by the state board provide for the direct allocation of greenhouse gas allowances to electrical corporations and gas corporations pursuant to a market-based compliance mechanism.

Existing law vests the Public Utilities Commission with regulatory authority over public utilities, including gas corporations. Existing law requires the commission to consider options to promote the in-state production and distribution of biomethane, and that facilitate the development of a variety of sources of in-state biomethane. The commission has adopted 2 decisions implementing these requirements, the 2nd of which adopted a 5-year monetary incentive program effective June 11, 2015, for biomethane projects. Existing law requires the commission to modify the biomethane monetary incentive program in specified respects and to extend the program, as modified, until December 31, 2026, or until all available program funds are expended, whichever occurs first.

This bill would require the commission to extend the biomethane monetary incentive program until December 31, 2030. The bill would authorize the commission to authorize additional funding of $50,000,000 for the program program, of which no more than $10,000,000 would be authorized for dairy biomethane projects, using the revenues, including any accrued interest, received by a gas corporation as a result of the direct allocation of greenhouse gas allowances provided to gas corporations as part of the above-described market-based compliance mechanism. The bill would also require the commission to allow recovery in rates of the costs of gas corporation investments in interconnection costs for biomethane projects, subject to certain limitations.

Under existing law, a violation of the Public Utilities Act or an order, decision, rule, direction, demand, or requirement of the commission is a crime.

Because the provisions of this bill would be part of the act and because a violation of a commission action implementing its requirements would be a crime, the bill would impose a state-mandated local program.

The California Constitution requires the state to reimburse local agencies and school districts for certain costs mandated by the state. Statutory provisions establish procedures for making that reimbursement.

This bill would provide that no reimbursement is required by this act for a specified reason.

Existing law vests the Public Utilities Commission with regulatory authority over public utilities, including gas corporations. Existing law requires the commission to consider options to promote the in-state production and distribution of biomethane, including whether to allow recovery in rates of the costs of investments to (1) facilitate direct investment in the procurement and installation of utility infrastructure necessary to achieve interconnection between the natural gas transmission and distribution pipeline network and biomethane generation and collection equipment and of gathering lines for a dairy cluster biomethane project, (2) provide for the installation of utility infrastructure to achieve interconnection with facilities that generate biomethane, and (3) ensure that these investments for infrastructure are prudent and reasonable and provide a direct benefit to, and are in the interests of, all classes of ratepayers. and that facilitate the development of a variety of sources of in-state biomethane. The commission has adopted 2 decisions implementing these requirements, the 2nd of which adopted a 5-year monetary incentive program effective June 11, 2015, for biomethane projects. Existing law requires the commission to modify the biomethane monetary incentive program in specified respects and to extend the program, as modified, until December 31, 2026, or until all available program funds are expended, whichever occurs first.

This bill would require the commission, on or before June 1, 2026, to allow recovery in rates of the costs of those investments. commission to extend the biomethane monetary incentive program until December 31, 2030. The bill would authorize the commission to authorize additional funding for the program using the revenues, including any accrued interest, received by a gas corporation as a result of the direct allocation of greenhouse gas allowances provided to gas corporations as part of the above-described market-based compliance mechanism. The bill would also require the commission to allow recovery in rates of the costs of gas corporation investments in interconnection costs for biomethane projects, subject to certain limitations.

Under existing law, a violation of the Public Utilities Act or an order, decision, rule, direction, demand, or requirement of the commission is a crime.

Because the provisions of this bill would be part of the act and because a violation of a commission action implementing its requirements would be a crime, the bill would impose a state-mandated local program.

The California Constitution requires the state to reimburse local agencies and school districts for certain costs mandated by the state. Statutory provisions establish procedures for making that reimbursement.

This bill would provide that no reimbursement is required by this act for a specified reason.

Existing law vests the Public Utilities Commission with regulatory authority over public utilities, including gas corporations. Existing law requires the commission to consider options to promote the in-state production and distribution of biomethane, including whether to allow recovery in rates of the costs of investments to (1) facilitate direct investment in the procurement and installation of utility infrastructure necessary to achieve interconnection between the natural gas transmission and distribution pipeline network and biomethane generation and collection equipment and of gathering lines for a dairy cluster biomethane project, (2) provide for the installation of utility infrastructure to achieve interconnection with facilities that generate biomethane, and (3) ensure that these investments for infrastructure are prudent and reasonable and provide a direct benefit to, and are in the interests of, all classes of ratepayers.

This bill would require the commission, on or before June 1, 2026, to allow recovery in rates of the costs of those investments.

Under existing law, a violation of the Public Utilities Act or an order, decision, rule, direction, demand, or requirement of the commission is a crime.

Because the provisions of this bill would be part of the act and because a violation of a commission action implementing its requirements would be a crime, the bill would impose a state-mandated local program.

The California Constitution requires the state to reimburse local agencies and school districts for certain costs mandated by the state. Statutory provisions establish procedures for making that reimbursement.

This bill would provide that no reimbursement is required by this act for a specified reason.

SENATE COMMITTEE ON

Senator Sabrina Cervantes, Chair

2025 - 2026 Regular Session

SB 919 (Grayson) - Biomethane monetary incentive program

Bill Summary:

This bill would require the California Public Utilities Commission (CPUC) to extend the biomethane monetary incentive program and allow the CPUC to authorize additional funding of $50 million from greenhouse gas allowance revenues for the program, but would limit funding for dairy biomethane projects to no more than $10 million.

Fiscal Impact:

• Unknown, potentially significant costs, possibly in the hundreds of thousands of dollars annually, until December 31, 2030 (ratepayer funds) for the CPUC to extend the program and continue program oversight.

Background:

The Biomethane Monetary Incentive Program was established pursuant to CPUC decisions, D.19-12-009 which implemented an Incentive Reservation System for the Biomethane Monetary Incentive Program established as part of D.15-06-029. The program was modified by AB 2313 (Williams, Chapter 571, Statutes of 2016) which increased the amount of funding for interconnection costs for biomethane projects. The incentive program provides up to $3 million for non-dairy clusters and $5 million for dairy clusters that interconnect successfully with the natural gas utility pipeline system and operate by December 31, 2026. The Incentive Reservation System allows project developers to reserve incentive funds during the development phase of a project and receive the funds once the project is interconnected and operating. D.15-06-029 originally provided $40 million for incentives. The CPUC subsequently authorized an additional $40 million in funding from natural gas utility Cap-and-Trade allowance auction proceeds, bringing total funding to $80 million. The collective allocation of the additional $40 million in additional incentive spending is distributed across each of California four large gas utilities’ service territories consistent with each gas utility’s respective percentage of their combined CARB allocation of Cap-and-Trade allowances:

• SoCalGas: $19,704,000 (49.26% of $40 million)
• PG&E: $16,936,000 (42.34% of $40 million)
• SDG&E: $2,708,000 (6.77% of $40 million)
• Southwest Gas: $652,000 (1.63% of $40 million)

The interconnection incentive program is currently fully subscribed, but still accepting reservations from interested developers. The current wait list includes roughly $38 million in funding requested by project developers, mostly within PG&E and SoCalGas service territories.

Proposed Law:

This bill would require the CPUC to extend the biomethane monetary incentive program. It would also allow the CPUC to authorize additional funding of $50 million from greenhouse gas allowance revenues for the program, but would limit funding for dairy biomethane projects to no more than $10 million.

Related Legislation:

AB 1207 (Irwin, Chapter 117, Statutes of 2025), among its provisions, extended the authorization for the GHG emissions reduction market-based compliance program (now coined as the Cap-and-Invest Program) and design regulations, including distribution of emissions allowances in a manner that transitions support from gas corporations to electrical distribution utilities on or before January 1, 2031.

SB 377 (Grayson) of 2025, would have required policies to support deployment of biomethane production, including expanding eligibility to out-of-state projects for existing biomethane projects and required the CPUC to authorize natural gas corporations to recover the costs of biomethane projects from their customers. The bill died in the Senate.

AB 678 (Alvarez, Chapter 339, Statutes of 2023) extended the authority of the CPUC to establish biomethane procurement targets on gas corporations to also include core transport agents – third-party natural gas providers.

AB 3187 (Grayson, Chapter 598, Statutes of 2018) directed the CPUC to open a proceeding, by no later than July 1, 2019, to consider options to promote the in-state production and distribution of biomethane, including whether to allow recovery in rates of interconnection costs for biomethane projects.

SB 1440 (Hueso, Chapter 739, Statutes of 2018) required the CPUC, in consultation with the CARB, to consider adopting specific biomethane procurement targets or goals for each natural gas corporation. The bill required the CPUC, if the CPUC adopts those targets or goals, to take certain actions regarding the development of the targets or goals and the procurement of the biomethane to meet those targets or goals.

AB 2313 (Williams, Chapter 571, Statutes of 2016), codified, modified and extended the biomethane monetary incentive program without specifying a funding cap or a particular funding source. The bill also required consideration by the CPUC of whether to allow recovery in rates of interconnection costs for biomethane projects.

SB 1383 (Lara, Chapter 395, Statutes of 2016) required state agencies to consider and, as appropriate, adopt policies and incentives to significantly increase the sustainable production and use of renewable natural gas, including biomethane to meet the state’s climate change, renewable energy, low-carbon fuel, and short-lived climate pollutants goals, including black carbon, landfill diversion, and dairy methane targets.

SB 840 (Committee on Budget and Fiscal Review, Chapter 341, Statutes of 2016) required the CPUC to reevaluate its requirements and standards for biomethane to be injected into common carrier pipelines.

AB 1900 (Gatto, Chapter 602, Statutes of 2012) directed the CPUC to identify landfill gas constituents, develop testing protocols for landfill gas injected into common carrier pipelines, adopt standards for biomethane to ensure pipeline safety and integrity, and adopt rules to ensure open access to the gas pipeline system.

AB 2196 (Chesbro, Chapter 605, Statutes of 2012) ensured that biogas qualifies for RPS credit, provided its production, delivery and use meet certain conditions.

SB 1122 (Rubio, Chapter 612, Statutes of 2012) required IOUs to collectively procure at least 250 MW of generation eligible for the RPS from bioenergy generation project, including biogas projects.

-- END --

SENATE COMMITTEE ON ENERGY, UTILITIES AND COMMUNICATIONS

Senator Benjamin Allen, Chair

2025 - 2026 Regular

Bill No: Hearing Date: 4/21/2026

SUBJECT:

DIGEST: This bill requires the California Public Utilities Commission (CPUC) to allow recovery in natural gas utility rates of the costs to connect biomethane projects to the utility pipeline system (known as interconnection costs). This bill also requires the CPUC to extend the biomethane monetary incentive program until December 31, 2030.

ANALYSIS:

Existing law:

1. Establishes and vests the CPUC with regulatory authority over public utilities, including gas corporations. (Article XII of the California Constitution)
2. Establishes the California Global Warming Solutions Act of 2006 designates the California Air Resources Board (CARB) as the state agency charged with monitoring and regulating sources of emissions of greenhouse gases (GHG). Directs CARB to ensure that statewide GHG emissions are reduced to 40% percent below the 1990 level by 2030. (Health and Safety Code §38566)
3. Requires CARB to implement a strategy to reduce emissions of short-lived climate pollutants to achieve a reduction in methane by 40%, hydrofluorocarbon gases by 40%, and anthropogenic black carbon by 50% below 2013 levels by 2030. (Health and Safety Code §39730.5)
4. Directs CARB to adopt regulations to reduce methane emissions from livestock and dairy manure by up to 40% below 2013 levels by 2030 granted the regulations are economically feasible and a market exists for the products generated by these projects. (Health and Safety Code §39730.7)
5. Authorizes CARB to include the use of market-based compliance mechanisms in regulating GHG emissions. The implementing regulations adopted by CARB provide for the direct allocation of GHG allowances to electrical corporations and gas corporations pursuant to a market-based compliance mechanism, the Cap-and-Trade Program. (Health and Safety Code §38562)
6. Requires the CPUC to consider options to promote the in-state production and distribution of biomethane, including whether to allow recovery in rates of the costs of investments to (1) facilitate direct investment in the procurement and installation of utility infrastructure necessary to achieve interconnection between the natural gas transmission and distribution pipeline network and biomethane generation and collection equipment and of gathering lines for a dairy cluster biomethane project, (2) provide for the installation of utility infrastructure to achieve interconnection with facilities that generate biomethane, and (3) ensure that these investments for infrastructure are prudent and reasonable and provide a direct benefit to, and are in the interests of, all classes of ratepayers, and that facilitate the development of a variety of sources of in-state biomethane. (Public Utilities Code §399.24 and §784.2)
7. Requires the CPUC to modify the biomethane monetary incentive program in specified respects and to extend the program, as modified, until December 31, 2026, or until all available program funds are expended, whichever occurs first. (Public Utilities Code §399.19)
8. Requires the CPUC to adopt policies and programs that promote the in-state production and distribution of biomethane and requires that those policies and programs facilitate the development of a variety of sources of in-state biomethane. (Public Utilities Code §399.24)
9. Requires the CPUC, in consultation with CARB, to consider adopting specific biomethane procurement targets or goals for each gas corporation and core transport agent. (Public Utilities Code §§650 and 651)
10. Requires the CPUC for each gas corporation to adopt pipeline access rules that ensure that each gas corporation provides nondiscriminatory open access to its gas pipeline system to any party for the purposes of physically interconnecting with the gas pipeline system and effectuating delivery of gas. (Public Utilities Code §784)
11. Defines “interconnection” to mean the facilities necessary to physically connect the energy source of and the point of use by a private energy producer with the existing transmission facilities of a public utility, and includes any necessary transformation, compression or other facilities necessary to make such interconnection effective. (Public Utilities Code §2803)
12. Requires the CPUC to adopt pipeline access rules that ensure that each gas corporation provides nondiscriminatory access to the gas pipeline system to any party for the purposes of physically interconnecting with the gas pipeline system and effectuating the delivery of gas. (Public Utilities Code §784)
13. Requires the CPUC to adopt standards for biomethane that specify the concentrations of constituents of concerns that are reasonably necessary to protect public health and ensure pipeline integrity and safety and to adopt monitoring, testing, reporting and recordkeeping protocols. (Health and Safety Code §25421)
14. Requires the CPUC to hold public hearings to identify impediments that limit procurement of biomethane in California, including impediments to interconnection, and to offer solutions. (Health and Safety Code §25326)

This bill:

1. Makes several findings and declarations regarding climate change, the need to displace fossil gas in pipelines, and authorize natural gas corporations to include renewable natural gas interconnections projects in their rate base.
2. Requires the CPUC to extend the biomethane monetary incentive program until December 31, 2030, instead of 2026.
3. Authorizes the CPUC, on or after January 1, 2027, to authorize additional funding for the biomethane monetary incentive program using the revenues, including any accrued interest, received by a gas corporation as a result of the direct allocation of GHG allowances provided to gas corporations as part of the market-based compliance mechanism (known as the Cap-and-Invest Program).
4. Requires the CPUC, on or after January 1, 2027, to allow recovery in rates of the costs of gas corporation investments in interconnection costs for biomethane projects, subject to certain limitations, specifically:
   1. The sum of gas corporation interconnection investments and funding under the biomethane incentive program does not exceed the per-project incentive limitation of $3 million for non-dairy cluster project and $5 million for a dairy cluster project.
   2. Each gas corporation’s annual biomethane interconnection costs eligible for rate recovery does not exceed one percent of the gas corporation’s total annual revenue requirement.
5. Provides that the operating language of this bill remains in effect until January 1, 2031.

Background

Biomethane. Biomethane – also referred to as renewable natural gas or RNG – is combustible gas produced from the anaerobic decomposition of organic materials that are captured and then purified to a quality suitable for injection into a natural gas utility pipeline. Sources of biomethane include landfill waste (non-hazardous), waste from wastewater treatment facilities, organic waste, forest and other wood waste, agriculture and food processing waste, and animal manure. Methane emissions from these waste streams can be captured to create biomethane which is used as a direct replacement for fossil natural gas, thereby helping to reduce GHG emissions. Unlike fossil-based natural gas, biomethane can be produced sustainably and consistently as it is derived from sources that are constantly being replenished because of regular human and animal activity.

Biomethane considered renewable energy. Biomethane is biogas that has been cleaned and processed to remove impurities. Although the combustion of biogas releases carbon dioxide (CO₂), it also destroys methane, which is a more potent GHG than CO₂ because of its global warming potential and is considered a short-lived climate pollutant. Biomethane is considered carbon neutral because CO₂ that would be released into the atmosphere is utilized and thereby removed from the atmosphere. The use of biomethane can also displace energy consumption from fossil fuels, thereby decreasing carbon intensity.

Biomethane procurement targets. Pursuant to SB 1440 (Hueso, Chapter 739, Statutes of 2018), the CPUC is required to consider adopting biomethane procurement targets or goals for each natural gas corporation. In February 2022, the CPUC adopted Decision 22-02-025 which established biomethane procurement targets for the state’s large natural gas investor-owned utilities (IOUs) – namely Pacific Gas & Electric (PG&E), San Diego Gas & Electric (SDG&E), Southern California Gas Company (SoCalGas), and Southwest Gas. The CPUC decision established a biomethane procurement program intended to help achieve the state’s short-lived climate pollutant goals which call for a 40% reduction in methane and other short-lived climate pollutants by 2030. Renewable natural gas procurement is intended to help reduce otherwise uncontrolled methane and black carbon emissions in waste, landfill, agricultural, and forest management sectors. 

The decision established short-term and medium-term procurement goals:

• A short-term biomethane procurement target of 17.6 billion cubic feet of biomethane annually beginning in 2025, which corresponds to eight million tons of organic waste diverted annually from landfills. Each gas corporation is responsible for procuring a percentage of the total in accordance with its respective Cap-and-Trade allowance shares, as follows: PG&E 42.34%, SDG&E 6.77%, SoCalGas 49.26%, and Southwest Gas 1.63%.
• A medium-term target for biomethane procurement of 72.8 billion cubic feet per year beginning in 2030, is the Renewable Gas Standard for gas corporations. This higher amount will help the state achieve its goal to reduce methane emissions 40% by 2030. It reflects approximately 12.2% of bundled core customers’ natural gas usage in 2020.

CPUC limits biomethane produced from dairies. The CPUC restricted the use of biomethane produced from dairies to a limited amount within the medium-term target and to zero within the short-term target, given there are other state programs to incentivize biomethane procurement from dairies, including through the Low Carbon Fuel Standard. For the medium-term goal, there is a ceiling on dairy biomethane of four percent of total biomethane procurement. These are measures required to avoid adverse environmental impacts on air and water quality from any dairies that provide biomethane.

Interconnection. Interconnecting a biomethane project to the broader natural gas utility pipeline system requires specified costs and rules. Through various decisions, the CPUC has adopted the Standard Renewable Gas Interconnection Tariff Rule which establishes the terms of access and interconnection studies for interconnections to natural gas corporation’s system by interconnecting project developers. Costs for interconnecting include engineering design studies, land acquisitions, pipes and metering infrastructure, safety requirements, gas quality and other costs. Generally, these costs are borne by the project developer desiring to connect to the natural gas utility system. Costs associated with contributions to provide for the expansion, improvement, or replacement of the utility’s facilities, including interconnecting projects, are Contributions-in-aid-of-Construction which are subject to income tax.

Biomethane Monetary Incentive Program. The Biomethane Monetary Incentive Program was established pursuant to CPUC decisions, D.19-12-009 which implemented an Incentive Reservation System for the Biomethane Monetary Incentive Program established as part of D.15-06-029. The program was modified by AB 2313 (Williams, Chapter 571, Statutes of 2016) which increased the amount of funding for interconnection costs for biomethane projects. The incentive program provides up to $3 million for non-dairy clusters and $5 million for dairy clusters that interconnect successfully with the natural gas utility pipeline system and operate by December 31, 2026. The Incentive Reservation System allows project developers to reserve incentive funds during the development phase of a project and receive the funds once the project is interconnected and operating. D.15-06-029 originally provided $40 million for incentives. The CPUC subsequently authorized an additional $40 million in funding from natural gas utility Cap-and-Trade allowance auction proceeds, bringing total funding to $80 million. The collective allocation of the additional $40 million in additional incentive spending is distributed across each of California four large gas utilities’ service territories consistent with each gas utility’s respective percentage of their combined CARB allocation of Cap-and-Trade allowances:

• SoCalGas: $19,704,000 (49.26% of $40 million)
• PG&E: $16,936,000 (42.34% of $40 million)
• SDG&E: $2,708,000 (6.77% of $40 million)
• Southwest Gas: $652,000 (1.63% of $40 million)

The interconnection incentive program is currently fully subscribed, but still accepting reservations from interested developers. The current wait list includes roughly $38 million in funding requested by project developers, mostly within PG&E and SoCalGas service territories.

Comments

Need for this bill. According to the author:

While California is on track to meet its 40% methane reduction goal for dairies, progress in reducing methane emissions from landfills and wastewater treatment plants has been slow. One major barrier is the lack of utility procurement of RNG, which discourages investment in new RNG projects at these facilities. A key cost barrier is the high price of interconnecting RNG projects to the gas grid, which is substantially higher in California than in other states. Under current rules, developers must either provide a contribution in aid of construction or advance interconnection costs to utilities, which are subject to a 24% federal tax under the Income Tax Component of Contributions and Advances (ITCCA). SB 919 removes financial barriers to RNG development and supports California’s climate goals by reducing interconnection costs for RNG projects. This bill authorizes gas utilities to include just and reasonable interconnection costs in their rate base, eliminating the 24% federal ITCCA tax and leveraging lower utility financing costs to generate ratepayer savings. By addressing infrastructure financing constraints rather than creating a new procurement mandate, SB 919 provides a structural solution to unlock additional biomethane supply, reduce methane emissions from waste streams, and support long-term market stability.

Costs of interconnecting projects. As noted above, the costs to interconnect biomethane projects to the natural gas utility system are borne by the biomethane project developers and are subject to income tax obligations. The proponents of this bill suggest authorizing recovery of the interconnection costs by natural gas utility customers, rate base, rather than the developers would reduce the costs for these projects. However, as noted by The Utility Reform Network (TURN), rate basing these projects also subjects them to a rate of return for the utility, roughly 10% and subject to long-term financing costs all borne by utility customers. As a result, it’s possible these costs could be higher than the amount that would otherwise be paid by the developer, particularly if they benefit from an incentive.

CPUC issued a proposed decision. On March 6, the CPUC issued a proposed decision (Rulemaking 13-02-008) regarding several issues concerning biomethane. The proposed decision modifies the above biomethane procurement targets, reducing them to 36.4 Bcf annually, in part to protect ratepayers from these procurement costs. The decision also considered whether to authorize recovery of interconnection costs from ratepayers, instead of the project developers. The proposed decision declines to allow ratebasing of biomethane interconnection costs “until demonstrable progress has been made to reduce current interconnection costs and introduce meaningful costs control measures.” The CPUC noted that costs for interconnection projects are higher in California but needs more information to understand the reasons for the higher costs compared to other states. The CPUC proposed decision acknowledges that interconnection costs are an “obstacle for both producers, who bear the uncertainty and pay the up-front costs of project development, and ratepayers, who eventually see interconnection costs reflected in higher priced renewable gas procurement contracts.” The CPUC decision orders two next steps: (1) natural gas corporations to host a workshop within six months on the topic of interconnection costs, including cost analysis; and (2) orders natural gas corporations to jointly submit proposals (via Tier 2 Advice Letter) within three months of the workshop to reduce interconnection costs. The proposed decision further states: “after this process has concluded, the Utilities [natural gas corporations] may file Applications to ratebase certain interconnection costs.”

Based on the CPUC proposed decision and concerns about the impacts to ratepayers of authorizing the recovery of interconnection costs in utility ratebase, the Legislature may wish to hold off on authorizing these costs in the ratebase as proposed by this bill. The legislation would circumvent the deliberate, albeit slower process, at the CPUC to investigate the costs and determine which aspects might merit treatment in the ratebase. It should also be noted the CPUC proposed decision declined to extend the biomethane monetary incentive program, as several parties opposed its extension, including the Public Advocates Office and Sierra Club. TURN opposes the use of GHG allowance revenue for the biomethane incentive program as it would impact the amount residential customers would otherwise receive from the Climate Credit. TURN proposes a nonbypassable charge collected from all natural gas utility customers to fund the biomethane incentive program in order to spread the costs of the program to all customers and reduce impacts to residential customers.

Need for amendments. To address the concerns regarding ratepayer impacts, the author and committee may wish to delete the language in this bill authorizing ratebasing of the interconnection project costs. In lieu of this language, the author and committee may amend this bill to include intent language directing the CPUC to expeditiously proceed with ratebasing the specified costs identified by the CPUC to provide savings to ratepayers if ratebased. The author and committee may also amend this bill to provide $50 million for the biomethane incentive program with no more than $10 million for dairy projects.

Prior/Related Legislation

AB 1207 (Irwin, Chapter 117, Statutes of 2025), among its provisions, extended the authorization for the GHG emissions reduction market-based compliance program (now coined as the Cap-and-Invest Program) and design regulations, including distribution of emissions allowances in a manner that transitions support from gas corporations to electrical distribution utilities on or before January 1, 2031.

SB 377 (Grayson) of 2025, would have required policies to support deployment of biomethane production, including expanding eligibility to out-of-state projects for existing biomethane projects and required the CPUC to authorize natural gas corporations to recover the costs of biomethane projects from their customers. The bill died in the Senate.

AB 678 (Alvarez, Chapter 339, Statutes of 2023) extended the authority of the CPUC to establish biomethane procurement targets on gas corporations to also include core transport agents – third-party natural gas providers.

AB 3187 (Grayson, Chapter 598, Statutes of 2018) directed the CPUC to open a proceeding, by no later than July 1, 2019, to consider options to promote the in-state production and distribution of biomethane, including whether to allow recovery in rates of interconnection costs for biomethane projects.

SB 1440 (Hueso, Chapter 739, Statutes of 2018) required the CPUC, in consultation with the CARB, to consider adopting specific biomethane procurement targets or goals for each natural gas corporation. The bill required the CPUC, if the CPUC adopts those targets or goals, to take certain actions regarding the development of the targets or goals and the procurement of the biomethane to meet those targets or goals.

AB 2313 (Williams, Chapter 571, Statutes of 2016), codified, modified and extended the biomethane monetary incentive program without specifying a funding cap or a particular funding source. The bill also required consideration by the CPUC of whether to allow recovery in rates of interconnection costs for biomethane projects.

SB 1383 (Lara, Chapter 395, Statutes of 2016) required state agencies to consider and, as appropriate, adopt policies and incentives to significantly increase the sustainable production and use of renewable natural gas, including biomethane to meet the state’s climate change, renewable energy, low-carbon fuel, and short-lived climate pollutants goals, including black carbon, landfill diversion, and dairy methane targets.

SB 840 (Committee on Budget and Fiscal Review, Chapter 341, Statutes of 2016) required the CPUC to reevaluate its requirements and standards for biomethane to be injected into common carrier pipelines.

AB 1900 (Gatto, Chapter 602, Statutes of 2012) directed the CPUC to identify landfill gas constituents, develop testing protocols for landfill gas injected into common carrier pipelines, adopt standards for biomethane to ensure pipeline safety and integrity, and adopt rules to ensure open access to the gas pipeline system.

AB 2196 (Chesbro, Chapter 605, Statutes of 2012) ensured that biogas qualifies for RPS credit, provided its production, delivery and use meet certain conditions.

SB 1122 (Rubio, Chapter 612, Statutes of 2012) required IOUs to collectively procure at least 250 MW of generation eligible for the RPS from bioenergy generation project, including biogas projects.

FISCAL EFFECT: Appropriation: Fiscal Com.: Local:

SUPPORT:

Renewable Natural Gas Coalition (Sponsor)
Agricultural Council of California
Agricultural Energy Consumers Association
Ameresco
Bioenergy Association of California
California State Pipe Trades Council
Divert
Generate Upcycle
Hexagon Group
LF Bioenergy
Los Angeles County Sanitation Districts
Maas Energy
Milk Producers Council
Montauk Renewables
Republic Services
Sevana Bioenergy
Southern California Gas Company
The Transport Project
UGI Energy Services
Waga Energy

OPPOSITION:

California Environmental Voters
Californians Against Waste
Center for Biological Diversity
Earthjustice
Leadership Counsel for Justice & Accountability
Sierra Club California
The Utility Reform Network

ARGUMENTS IN SUPPORT: According to the Renewable Natural Gas Coalition (RNG), sponsor of this bill:

Currently, RNG developers seeking to connect to utility pipelines must provide the contribution in aid of construction or advance the funds for interconnection, which is subject to a Federal 24% tax factor under the Income Tax Component of Contributions and Advances (ITCCA). This additional cost burden has made it extremely difficult to deploy RNG projects in California in a cost-effective way, limiting ability to achieve its methane reduction goals. This bill directly addresses this challenge by authorizing gas utilities to include just and reasonable RNG interconnection investments in the overall rate base, with project limits that are consistent with the existing biomethane monetary incentive program and annual limits that further protect ratepayers. Allowing these costs to be rate-based eliminates the ITCCA tax penalty and enables interconnection investments to be financed at utility customers. Finally, SB 919 stresses the importance of needing to fund the Biomethane Monetary Incentive Program (BMIP), which has been a highly successful program in encouraging the development of biomethane projects and significantly reducing methane emissions in the state.

ARGUMENTS IN OPPOSITION: According to The Utility Reform Network (TURN):

TURN opposes requiring the CPUC to allow gas utilities to place biomethane project interconnection costs into ratebase. This issue is currently being evaluated by the CPUC in R.13-02-008. On March 6, 2026, CPUC President John Reynolds issued a Proposed Decision rejecting the exact treatment required under SB 919. The Proposed Decision explains that “the Commission declines to allow ratebasing of biomethane interconnection costs until demonstrable progress has been made to reduce current interconnection costs and introduce meaningful cost control measures.” (Proposed Decision, page 59) If the utilities can demonstrate progress on reducing interconnection costs through a process laid out in the Proposed Decision, the Commission would consider applications to ratebase “certain interconnection costs”. Given the CPUC’s ongoing review of this issue, and its pending rejection of the proposal to ratebase all biomethane interconnection costs, it is inappropriate for the Legislature to circumvent the ongoing process and require ratebasing under all circumstances.

-- END --

SENATE COMMITTEE ON ENERGY, UTILITIES AND COMMUNICATIONS

Senator Benjamin Allen, Chair

2025 - 2026 Regular

Bill No: Hearing Date: 4/21/2026

SUBJECT:

DIGEST: This bill requires the California Public Utilities Commission (CPUC) to allow recovery in natural gas utility rates of the costs to connect biomethane projects to the utility pipeline system (known as interconnection costs). This bill also requires the CPUC to extend the biomethane monetary incentive program until December 31, 2030.

ANALYSIS:

Existing law:

1. Establishes and vests the CPUC with regulatory authority over public utilities, including gas corporations. (Article XII of the California Constitution)
2. Establishes the California Global Warming Solutions Act of 2006 designates the California Air Resources Board (CARB) as the state agency charged with monitoring and regulating sources of emissions of greenhouse gases (GHG). Directs CARB to ensure that statewide GHG emissions are reduced to 40% percent below the 1990 level by 2030. (Health and Safety Code §38566)
3. Requires CARB to implement a strategy to reduce emissions of short-lived climate pollutants to achieve a reduction in methane by 40%, hydrofluorocarbon gases by 40%, and anthropogenic black carbon by 50% below 2013 levels by 2030. (Health and Safety Code §39730.5)
4. Directs CARB to adopt regulations to reduce methane emissions from livestock and dairy manure by up to 40% below 2013 levels by 2030 granted the regulations are economically feasible and a market exists for the products generated by these projects. (Health and Safety Code §39730.7)
5. Authorizes CARB to include the use of market-based compliance mechanisms in regulating GHG emissions. The implementing regulations adopted by CARB provide for the direct allocation of GHG allowances to electrical corporations and gas corporations pursuant to a market-based compliance mechanism, the Cap-and-Trade Program. (Health and Safety Code §38562)
6. Requires the CPUC to consider options to promote the in-state production and distribution of biomethane, including whether to allow recovery in rates of the costs of investments to (1) facilitate direct investment in the procurement and installation of utility infrastructure necessary to achieve interconnection between the natural gas transmission and distribution pipeline network and biomethane generation and collection equipment and of gathering lines for a dairy cluster biomethane project, (2) provide for the installation of utility infrastructure to achieve interconnection with facilities that generate biomethane, and (3) ensure that these investments for infrastructure are prudent and reasonable and provide a direct benefit to, and are in the interests of, all classes of ratepayers, and that facilitate the development of a variety of sources of in-state biomethane. (Public Utilities Code §399.24 and §784.2)
7. Requires the CPUC to modify the biomethane monetary incentive program in specified respects and to extend the program, as modified, until December 31, 2026, or until all available program funds are expended, whichever occurs first. (Public Utilities Code §399.19)
8. Requires the CPUC to adopt policies and programs that promote the in-state production and distribution of biomethane and requires that those policies and programs facilitate the development of a variety of sources of in-state biomethane. (Public Utilities Code §399.24)
9. Requires the CPUC, in consultation with CARB, to consider adopting specific biomethane procurement targets or goals for each gas corporation and core transport agent. (Public Utilities Code §§650 and 651)
10. Requires the CPUC for each gas corporation to adopt pipeline access rules that ensure that each gas corporation provides nondiscriminatory open access to its gas pipeline system to any party for the purposes of physically interconnecting with the gas pipeline system and effectuating delivery of gas. (Public Utilities Code §784)
11. Defines “interconnection” to mean the facilities necessary to physically connect the energy source of and the point of use by a private energy producer with the existing transmission facilities of a public utility, and includes any necessary transformation, compression or other facilities necessary to make such interconnection effective. (Public Utilities Code §2803)
12. Requires the CPUC to adopt pipeline access rules that ensure that each gas corporation provides nondiscriminatory access to the gas pipeline system to any party for the purposes of physically interconnecting with the gas pipeline system and effectuating the delivery of gas. (Public Utilities Code §784)
13. Requires the CPUC to adopt standards for biomethane that specify the concentrations of constituents of concerns that are reasonably necessary to protect public health and ensure pipeline integrity and safety and to adopt monitoring, testing, reporting and recordkeeping protocols. (Health and Safety Code §25421)
14. Requires the CPUC to hold public hearings to identify impediments that limit procurement of biomethane in California, including impediments to interconnection, and to offer solutions. (Health and Safety Code §25326)

This bill:

1. Makes several findings and declarations regarding climate change, the need to displace fossil gas in pipelines, and authorize natural gas corporations to include renewable natural gas interconnections projects in their rate base.
2. Requires the CPUC to extend the biomethane monetary incentive program until December 31, 2030, instead of 2026.
3. Authorizes the CPUC, on or after January 1, 2027, to authorize additional funding for the biomethane monetary incentive program using the revenues, including any accrued interest, received by a gas corporation as a result of the direct allocation of GHG allowances provided to gas corporations as part of the market-based compliance mechanism (known as the Cap-and-Invest Program).
4. Requires the CPUC, on or after January 1, 2027, to allow recovery in rates of the costs of gas corporation investments in interconnection costs for biomethane projects, subject to certain limitations, specifically:
   1. The sum of gas corporation interconnection investments and funding under the biomethane incentive program does not exceed the per-project incentive limitation of $3 million for non-dairy cluster project and $5 million for a dairy cluster project.
   2. Each gas corporation’s annual biomethane interconnection costs eligible for rate recovery does not exceed one percent of the gas corporation’s total annual revenue requirement.
5. Provides that the operating language of this bill remains in effect until January 1, 2031.

Background

Biomethane. Biomethane – also referred to as renewable natural gas or RNG – is combustible gas produced from the anaerobic decomposition of organic materials that are captured and then purified to a quality suitable for injection into a natural gas utility pipeline. Sources of biomethane include landfill waste (non-hazardous), waste from wastewater treatment facilities, organic waste, forest and other wood waste, agriculture and food processing waste, and animal manure. Methane emissions from these waste streams can be captured to create biomethane which is used as a direct replacement for fossil natural gas, thereby helping to reduce GHG emissions. Unlike fossil-based natural gas, biomethane can be produced sustainably and consistently as it is derived from sources that are constantly being replenished because of regular human and animal activity.

Biomethane considered renewable energy. Biomethane is biogas that has been cleaned and processed to remove impurities. Although the combustion of biogas releases carbon dioxide (CO₂), it also destroys methane, which is a more potent GHG than CO₂ because of its global warming potential and is considered a short-lived climate pollutant. Biomethane is considered carbon neutral because CO₂ that would be released into the atmosphere is utilized and thereby removed from the atmosphere. The use of biomethane can also displace energy consumption from fossil fuels, thereby decreasing carbon intensity.

Biomethane procurement targets. Pursuant to SB 1440 (Hueso, Chapter 739, Statutes of 2018), the CPUC is required to consider adopting biomethane procurement targets or goals for each natural gas corporation. In February 2022, the CPUC adopted Decision 22-02-025 which established biomethane procurement targets for the state’s large natural gas investor-owned utilities (IOUs) – namely Pacific Gas & Electric (PG&E), San Diego Gas & Electric (SDG&E), Southern California Gas Company (SoCalGas), and Southwest Gas. The CPUC decision established a biomethane procurement program intended to help achieve the state’s short-lived climate pollutant goals which call for a 40% reduction in methane and other short-lived climate pollutants by 2030. Renewable natural gas procurement is intended to help reduce otherwise uncontrolled methane and black carbon emissions in waste, landfill, agricultural, and forest management sectors. 

The decision established short-term and medium-term procurement goals:

• A short-term biomethane procurement target of 17.6 billion cubic feet of biomethane annually beginning in 2025, which corresponds to eight million tons of organic waste diverted annually from landfills. Each gas corporation is responsible for procuring a percentage of the total in accordance with its respective Cap-and-Trade allowance shares, as follows: PG&E 42.34%, SDG&E 6.77%, SoCalGas 49.26%, and Southwest Gas 1.63%.
• A medium-term target for biomethane procurement of 72.8 billion cubic feet per year beginning in 2030, is the Renewable Gas Standard for gas corporations. This higher amount will help the state achieve its goal to reduce methane emissions 40% by 2030. It reflects approximately 12.2% of bundled core customers’ natural gas usage in 2020.

CPUC limits biomethane produced from dairies. The CPUC restricted the use of biomethane produced from dairies to a limited amount within the medium-term target and to zero within the short-term target, given there are other state programs to incentivize biomethane procurement from dairies, including through the Low Carbon Fuel Standard. For the medium-term goal, there is a ceiling on dairy biomethane of four percent of total biomethane procurement. These are measures required to avoid adverse environmental impacts on air and water quality from any dairies that provide biomethane.

Interconnection. Interconnecting a biomethane project to the broader natural gas utility pipeline system requires specified costs and rules. Through various decisions, the CPUC has adopted the Standard Renewable Gas Interconnection Tariff Rule which establishes the terms of access and interconnection studies for interconnections to natural gas corporation’s system by interconnecting project developers. Costs for interconnecting include engineering design studies, land acquisitions, pipes and metering infrastructure, safety requirements, gas quality and other costs. Generally, these costs are borne by the project developer desiring to connect to the natural gas utility system. Costs associated with contributions to provide for the expansion, improvement, or replacement of the utility’s facilities, including interconnecting projects, are Contributions-in-aid-of-Construction which are subject to income tax.

Biomethane Monetary Incentive Program. The Biomethane Monetary Incentive Program was established pursuant to CPUC decisions, D.19-12-009 which implemented an Incentive Reservation System for the Biomethane Monetary Incentive Program established as part of D.15-06-029. The program was modified by AB 2313 (Williams, Chapter 571, Statutes of 2016) which increased the amount of funding for interconnection costs for biomethane projects. The incentive program provides up to $3 million for non-dairy clusters and $5 million for dairy clusters that interconnect successfully with the natural gas utility pipeline system and operate by December 31, 2026. The Incentive Reservation System allows project developers to reserve incentive funds during the development phase of a project and receive the funds once the project is interconnected and operating. D.15-06-029 originally provided $40 million for incentives. The CPUC subsequently authorized an additional $40 million in funding from natural gas utility Cap-and-Trade allowance auction proceeds, bringing total funding to $80 million. The collective allocation of the additional $40 million in additional incentive spending is distributed across each of California four large gas utilities’ service territories consistent with each gas utility’s respective percentage of their combined CARB allocation of Cap-and-Trade allowances:

• SoCalGas: $19,704,000 (49.26% of $40 million)
• PG&E: $16,936,000 (42.34% of $40 million)
• SDG&E: $2,708,000 (6.77% of $40 million)
• Southwest Gas: $652,000 (1.63% of $40 million)

The interconnection incentive program is currently fully subscribed, but still accepting reservations from interested developers. The current wait list includes roughly $38 million in funding requested by project developers, mostly within PG&E and SoCalGas service territories.

Comments

Need for this bill. According to the author:

While California is on track to meet its 40% methane reduction goal for dairies, progress in reducing methane emissions from landfills and wastewater treatment plants has been slow. One major barrier is the lack of utility procurement of RNG, which discourages investment in new RNG projects at these facilities. A key cost barrier is the high price of interconnecting RNG projects to the gas grid, which is substantially higher in California than in other states. Under current rules, developers must either provide a contribution in aid of construction or advance interconnection costs to utilities, which are subject to a 24% federal tax under the Income Tax Component of Contributions and Advances (ITCCA). SB 919 removes financial barriers to RNG development and supports California’s climate goals by reducing interconnection costs for RNG projects. This bill authorizes gas utilities to include just and reasonable interconnection costs in their rate base, eliminating the 24% federal ITCCA tax and leveraging lower utility financing costs to generate ratepayer savings. By addressing infrastructure financing constraints rather than creating a new procurement mandate, SB 919 provides a structural solution to unlock additional biomethane supply, reduce methane emissions from waste streams, and support long-term market stability.

Costs of interconnecting projects. As noted above, the costs to interconnect biomethane projects to the natural gas utility system are borne by the biomethane project developers and are subject to income tax obligations. The proponents of this bill suggest authorizing recovery of the interconnection costs by natural gas utility customers, rate base, rather than the developers would reduce the costs for these projects. However, as noted by The Utility Reform Network (TURN), rate basing these projects also subjects them to a rate of return for the utility, roughly 10% and subject to long-term financing costs all borne by utility customers. As a result, it’s possible these costs could be higher than the amount that would otherwise be paid by the developer, particularly if they benefit from an incentive.

CPUC issued a proposed decision. On March 6, the CPUC issued a proposed decision (Rulemaking 13-02-008) regarding several issues concerning biomethane. The proposed decision modifies the above biomethane procurement targets, reducing them to 36.4 Bcf annually, in part to protect ratepayers from these procurement costs. The decision also considered whether to authorize recovery of interconnection costs from ratepayers, instead of the project developers. The proposed decision declines to allow ratebasing of biomethane interconnection costs “until demonstrable progress has been made to reduce current interconnection costs and introduce meaningful costs control measures.” The CPUC noted that costs for interconnection projects are higher in California but needs more information to understand the reasons for the higher costs compared to other states. The CPUC proposed decision acknowledges that interconnection costs are an “obstacle for both producers, who bear the uncertainty and pay the up-front costs of project development, and ratepayers, who eventually see interconnection costs reflected in higher priced renewable gas procurement contracts.” The CPUC decision orders two next steps: (1) natural gas corporations to host a workshop within six months on the topic of interconnection costs, including cost analysis; and (2) orders natural gas corporations to jointly submit proposals (via Tier 2 Advice Letter) within three months of the workshop to reduce interconnection costs. The proposed decision further states: “after this process has concluded, the Utilities [natural gas corporations] may file Applications to ratebase certain interconnection costs.”

Based on the CPUC proposed decision and concerns about the impacts to ratepayers of authorizing the recovery of interconnection costs in utility ratebase, the Legislature may wish to hold off on authorizing these costs in the ratebase as proposed by this bill. The legislation would circumvent the deliberate, albeit slower process, at the CPUC to investigate the costs and determine which aspects might merit treatment in the ratebase. It should also be noted the CPUC proposed decision declined to extend the biomethane monetary incentive program, as several parties opposed its extension, including the Public Advocates Office and Sierra Club. TURN opposes the use of GHG allowance revenue for the biomethane incentive program as it would impact the amount residential customers would otherwise receive from the Climate Credit. TURN proposes a nonbypassable charge collected from all natural gas utility customers to fund the biomethane incentive program in order to spread the costs of the program to all customers and reduce impacts to residential customers.

Need for amendments. To address the concerns regarding ratepayer impacts, the author and committee may wish to delete the language in this bill authorizing ratebasing of the interconnection project costs. In lieu of this language, the author and committee may amend this bill to include intent language directing the CPUC to expeditiously proceed with ratebasing the specified costs identified by the CPUC to provide savings to ratepayers if ratebased. The author and committee may also amend this bill to provide $60 million for the biomethane incentive program with no more than $10 million for dairy projects.

Prior/Related Legislation

AB 1207 (Irwin, Chapter 117, Statutes of 2025), among its provisions, extended the authorization for the GHG emissions reduction market-based compliance program (now coined as the Cap-and-Invest Program) and design regulations, including distribution of emissions allowances in a manner that transitions support from gas corporations to electrical distribution utilities on or before January 1, 2031.

SB 377 (Grayson) of 2025, would have required policies to support deployment of biomethane production, including expanding eligibility to out-of-state projects for existing biomethane projects and required the CPUC to authorize natural gas corporations to recover the costs of biomethane projects from their customers. The bill died in the Senate.

AB 678 (Alvarez, Chapter 339, Statutes of 2023) extended the authority of the CPUC to establish biomethane procurement targets on gas corporations to also include core transport agents – third-party natural gas providers.

AB 3187 (Grayson, Chapter 598, Statutes of 2018) directed the CPUC to open a proceeding, by no later than July 1, 2019, to consider options to promote the in-state production and distribution of biomethane, including whether to allow recovery in rates of interconnection costs for biomethane projects.

SB 1440 (Hueso, Chapter 739, Statutes of 2018) required the CPUC, in consultation with the CARB, to consider adopting specific biomethane procurement targets or goals for each natural gas corporation. The bill required the CPUC, if the CPUC adopts those targets or goals, to take certain actions regarding the development of the targets or goals and the procurement of the biomethane to meet those targets or goals.

AB 2313 (Williams, Chapter 571, Statutes of 2016), codified, modified and extended the biomethane monetary incentive program without specifying a funding cap or a particular funding source. The bill also required consideration by the CPUC of whether to allow recovery in rates of interconnection costs for biomethane projects.

SB 1383 (Lara, Chapter 395, Statutes of 2016) required state agencies to consider and, as appropriate, adopt policies and incentives to significantly increase the sustainable production and use of renewable natural gas, including biomethane to meet the state’s climate change, renewable energy, low-carbon fuel, and short-lived climate pollutants goals, including black carbon, landfill diversion, and dairy methane targets.

SB 840 (Committee on Budget and Fiscal Review, Chapter 341, Statutes of 2016) required the CPUC to reevaluate its requirements and standards for biomethane to be injected into common carrier pipelines.

AB 1900 (Gatto, Chapter 602, Statutes of 2012) directed the CPUC to identify landfill gas constituents, develop testing protocols for landfill gas injected into common carrier pipelines, adopt standards for biomethane to ensure pipeline safety and integrity, and adopt rules to ensure open access to the gas pipeline system.

AB 2196 (Chesbro, Chapter 605, Statutes of 2012) ensured that biogas qualifies for RPS credit, provided its production, delivery and use meet certain conditions.

SB 1122 (Rubio, Chapter 612, Statutes of 2012) required IOUs to collectively procure at least 250 MW of generation eligible for the RPS from bioenergy generation project, including biogas projects.

FISCAL EFFECT: Appropriation: Fiscal Com.: Local:

SUPPORT:

Renewable Natural Gas Coalition (Sponsor)
Agricultural Council of California
Agricultural Energy Consumers Association
Ameresco
Bioenergy Association of California
California State Pipe Trades Council
Divert
Generate Upcycle
Hexagon Group
LF Bioenergy
Los Angeles County Sanitation Districts
Maas Energy
Milk Producers Council
Montauk Renewables
Republic Services
Sevana Bioenergy
Southern California Gas Company
The Transport Project
UGI Energy Services
Waga Energy

OPPOSITION:

California Environmental Voters
Californians Against Waste
Center for Biological Diversity
Earthjustice
Leadership Counsel for Justice & Accountability
Sierra Club California
The Utility Reform Network

ARGUMENTS IN SUPPORT: According to the Renewable Natural Gas Coalition (RNG), sponsor of this bill:

Currently, RNG developers seeking to connect to utility pipelines must provide the contribution in aid of construction or advance the funds for interconnection, which is subject to a Federal 24% tax factor under the Income Tax Component of Contributions and Advances (ITCCA). This additional cost burden has made it extremely difficult to deploy RNG projects in California in a cost-effective way, limiting ability to achieve its methane reduction goals. This bill directly addresses this challenge by authorizing gas utilities to include just and reasonable RNG interconnection investments in the overall rate base, with project limits that are consistent with the existing biomethane monetary incentive program and annual limits that further protect ratepayers. Allowing these costs to be rate-based eliminates the ITCCA tax penalty and enables interconnection investments to be financed at utility customers. Finally, SB 919 stresses the importance of needing to fund the Biomethane Monetary Incentive Program (BMIP), which has been a highly successful program in encouraging the development of biomethane projects and significantly reducing methane emissions in the state.

ARGUMENTS IN OPPOSITION: According to The Utility Reform Network (TURN):

TURN opposes requiring the CPUC to allow gas utilities to place biomethane project interconnection costs into ratebase. This issue is currently being evaluated by the CPUC in R.13-02-008. On March 6, 2026, CPUC President John Reynolds issued a Proposed Decision rejecting the exact treatment required under SB 919. The Proposed Decision explains that “the Commission declines to allow ratebasing of biomethane interconnection costs until demonstrable progress has been made to reduce current interconnection costs and introduce meaningful cost control measures.” (Proposed Decision, page 59) If the utilities can demonstrate progress on reducing interconnection costs through a process laid out in the Proposed Decision, the Commission would consider applications to ratebase “certain interconnection costs”. Given the CPUC’s ongoing review of this issue, and its pending rejection of the proposal to ratebase all biomethane interconnection costs, it is inappropriate for the Legislature to circumvent the ongoing process and require ratebasing under all circumstances.

-- END --

SENATE COMMITTEE ON ENERGY, UTILITIES AND COMMUNICATIONS

Senator Benjamin Allen, Chair

2025 - 2026 Regular

Bill No: Hearing Date: 3/17/2026

SUBJECT:

DIGEST: This bill requires the California Public Utilities Commission (CPUC) to allow recovery in natural gas utility rates of the costs to connect biomethane projects to the utility pipeline system (known as interconnection costs). The bill also requires the CPUC to extend the biomethane monetary incentive program until December 31, 2030.

ANALYSIS:

Existing law:

1. Establishes and vests the California Public Utilities Commission (CPUC) with regulatory authority over public utilities, including gas corporations. (Article XII of the California Constitution)
2. Establishes the California Global Warming Solutions Act of 2006 designates the California Air Resources Board (CARB) as the state agency charged with monitoring and regulating sources of emissions of greenhouse gases (GHG). Directs CARB to ensure that statewide greenhouse gas (GHG) emissions are reduced to 40 percent below the 1990 level by 2030. (Health and Safety Code §38566)
3. Requires CARB to implement a strategy to reduce emissions of short-lived climate pollutants to achieve a reduction in methane by 40 percent, hydrofluorocarbon gases by 40 percent, and anthropogenic black carbon by 50 percent below 2013 levels by 2030. (Health and Safety Code §39730.5)
4. Directs CARB to adopt regulations to reduce methane emissions from livestock and dairy manure by up to 40 percent below 2013 levels by 2030 granted the regulations are economically feasible and a market exists for the products generated by these projects. (Health and Safety Code §39730.7)
5. Authorizes CARB to include the use of market-based compliance mechanisms in regulating GHG emissions. The implementing regulations adopted by CARB provide for the direct allocation of greenhouse gas allowances to electrical corporations and gas corporations pursuant to a market-based compliance mechanism, the Cap-and-Trade Program. (Health and Safety Code §38562)
6. Requires the CPUC to consider options to promote the in-state production and distribution of biomethane, including whether to allow recovery in rates of the costs of investments to (1) facilitate direct investment in the procurement and installation of utility infrastructure necessary to achieve interconnection between the natural gas transmission and distribution pipeline network and biomethane generation and collection equipment and of gathering lines for a dairy cluster biomethane project, (2) provide for the installation of utility infrastructure to achieve interconnection with facilities that generate biomethane, and (3) ensure that these investments for infrastructure are prudent and reasonable and provide a direct benefit to, and are in the interests of, all classes of ratepayers. and that facilitate the development of a variety of sources of in-state biomethane. (Public Utilities Code §399.24 and §784.2)
7. Requires the CPUC to modify the biomethane monetary incentive program in specified respects and to extend the program, as modified, until December 31, 2026, or until all available program funds are expended, whichever occurs first. (Public Utilities Code §399.19)
8. Requires the CPUC to adopt policies and programs that promote the in-state production and distribution of biomethane and requires that those policies and programs facilitate the development of a variety of sources of in-state biomethane. (Public Utilities Code §399.24)
9. Requires the CPUC, in consultation with CARB, to consider adopting specific biomethane procurement targets or goals for each gas corporation and core transport agent. (Public Utilities Code §§650 and 651)
10. Requires the CPUC for each gas corporation to adopt pipeline access rules that ensure that each gas corporation provides nondiscriminatory open access to its gas pipeline system to any party for the purposes of physically interconnecting with the gas pipeline system and effectuating delivery of gas. (Public Utilities Code §784)
11. Defines “interconnection” to mean the facilities necessary to physically connect the energy source of and the point of use by a private energy producer with the existing transmission facilities of a public utility, and includes any necessary transformation, compression or other facilities necessary to make such interconnection effective. (Public Utilities Code §2803)
12. Requires the CPUC to adopt pipeline access rules that ensure that each gas corporation provides nondiscriminatory access to the gas pipeline system to any party for the purposes of physically interconnecting with the gas pipeline system and effectuating the delivery of gas. (Public Utilities Code §784)
13. Requires the CPUC to adopt standards for biomethane that specify the concentrations of constituents of concerns that are reasonably necessary to protect public health and ensure pipeline integrity and safety and to adopt monitoring, testing, reporting and recordkeeping protocols. (Health and Safety Code §25421)
14. Requires the CPUC to hold public hearings to identify impediments that limit procurement of biomethane in California, including impediments to interconnection, and to offer solutions. (Health and Safety Code §25326)

This bill:

1. Makes several findings and declarations regarding climate change, the need to displace fossil gas in pipelines, and authorize natural gas corporations to include renewable natural gas interconnections projects in their rate base.
2. Requires the CPUC to extend the biomethane monetary incentive program until December 31, 2030, instead of 2026.
3. Authorizes the CPUC, on or after January 1, 2027, to authorize additional funding for the biomethane monetary incentive program using the revenues, including any accrued interest, received by a gas corporation as a result of the direct allocation of greenhouse gas allowances provided to gas corporations as part of the market-based compliance mechanism (known as the Cap-and-Invest Program).
4. Requires the CPUC, on or after January 1, 2027, to allow recovery in rates of the costs of gas corporation investments in interconnection costs for biomethane projects, subject to certain limitations, specifically:
   1. The sum of gas corporation interconnection investments and funding under the biomethane incentive program does not exceed the per-project incentive limitation of $3 million for non-dairy cluster project and $5 million for a dairy cluster project.
   2. Each gas corporation’s annual biomethane interconnection costs eligible for rate recovery does not exceed one percent of the gas corporation’s total annual revenue requirement.
5. Provides that the operating language of the bill remains in effect until January 1, 2031.

Background

Biomethane. Biomethane – also referred to as renewable natural gas or RNG – is combustible gas produced from the anaerobic decomposition of organic materials that are captured and then purified to a quality suitable for injection into a natural gas utility pipeline. Sources of biomethane include landfill waste (non-hazardous), waste from wastewater treatment facilities, organic waste, forest and other wood waste, agriculture and food processing waste, and animal manure. Methane emissions from these waste streams can be captured to create biomethane which is used as a direct replacement for fossil natural gas, thereby helping to reduce GHG emissions. Unlike fossil-based natural gas, biomethane can be produced sustainably and consistently as it is derived from sources that are constantly being replenished because of regular human and animal activity.

Biomethane considered renewable energy. Biomethane is biogas that has been cleaned and processed to remove impurities. Although the combustion of biogas releases carbon dioxide (CO₂), it also destroys methane, which is a more potent GHG than CO₂ because of its global warming potential and is considered a short-lived climate pollutant. Biomethane is considered carbon neutral because CO₂ that would be released into the atmosphere is utilized and thereby removed from the atmosphere. The use of biomethane can also displace energy consumption from fossil fuels, thereby decreasing carbon intensity.

Biomethane procurement targets. Pursuant to SB 1440 (Hueso, Chapter 739, Statutes of 2018), the CPUC is required to consider adopting biomethane procurement targets or goals for each natural gas corporation. In February 2022, the CPUC adopted Decision 22-02-025 which established biomethane procurement targets for the state’s large natural gas IOUs – namely Pacific Gas & Electric (PG&E), San Diego Gas & Electric (SDG&E), SoCalGas, and Southwest Gas. The CPUC decision established a biomethane procurement program intended to help achieve the state’s short-lived climate pollutant goals which call for a 40 percent reduction in methane and other short-lived climate pollutants by 2030. Renewable natural gas procurement is intended to help reduce otherwise uncontrolled methane and black carbon emissions in waste, landfill, agricultural, and forest management sectors. 

The decision established short-term and medium-term procurement goals:

• A short-term biomethane procurement target of 17.6 billion cubic feet of biomethane annually beginning in 2025, which corresponds to eight million tons of organic waste diverted annually from landfills. Each gas corporation is responsible for procuring a percentage of the total in accordance with its respective Cap-and-Trade allowance shares, as follows: PG&E 42.34%, SDG&E 6.77%, SoCalGas 49.26%, and Southwest Gas 1.63%.
• A medium-term target for biomethane procurement of 72.8 billion cubic feet per year beginning in 2030, is the Renewable Gas Standard for gas corporations. This higher amount will help the state achieve its goal to reduce methane emissions 40 percent by 2030. It reflects approximately 12.2 percent of bundled core customers’ natural gas usage in 2020.

CPUC limits biomethane produced from dairies. The CPUC restricted the use of biomethane produced from dairies to a limited amount within the medium-term target and to zero within the short-term target, given there are other state programs to incentivize biomethane procurement from dairies, including through the Low Carbon Fuel Standard. For the medium-term goal, there is a ceiling on dairy biomethane of four percent of total biomethane procurement. These are measures required to avoid adverse environmental impacts on air and water quality from any dairies that provide biomethane.

Interconnection. Interconnecting a biomethane project to the broader natural gas utility pipeline system requires specified costs and rules. Through various decisions, the CPUC has adopted the Standard Renewable Gas Interconnection Tariff Rule which establishes the terms of access and interconnection studies for interconnections to natural gas corporation’s system by interconnecting project developers. Costs for interconnecting include engineering design studies, land acquisitions, pipes and metering infrastructure, safety requirements, gas quality and other costs. Generally, these costs are borne by the project developer desiring to connect to the natural gas utility system. Costs associated with contributions to provide for the expansion, improvement, or replacement of the utility’s facilities, including interconnecting projects, are Contributions-in-aid-of-Construction which are subject to income tax.

Biomethane Monetary Incentive Program. The Biomethane Monetary Incentive Program was established pursuant to CPUC decisions, D.19-12-009 which implemented an Incentive Reservation System for the Biomethane Monetary Incentive Program established as part of D.15-06-029. The program was modified by AB 2313 (Williams, Chapter 571, Statutes of 2016) which increased the amount of funding for interconnection costs for biomethane projects. The incentive program provides up to $3 million for non-dairy clusters and $5 million for dairy clusters that interconnect successfully with the natural gas utility pipeline system and operate by December 31, 2026. The Incentive Reservation System allows project developers to reserve incentive funds during the development phase of a project and receive the funds once the project is interconnected and operating. D.15-06-029 originally provided $40 million for incentives. The CPUC subsequently authorized an additional $40 million in funding from natural gas utility Cap-and-Trade allowance auction proceeds, bringing total funding to $80 million. The collective allocation of the additional $40 million in additional incentive spending is distributed across each of California four large gas utilities’ service territories consistent with each gas utility’s respective percentage of their combined CARB allocation of Cap-and-Trade allowances:

• SoCalGas: $19,704,000 (49.26 percent of $40 million)
• PG&E: $16,936,000 (42.34 percent of $40 million)
• SDG&E: $2,708,000 (6.77 percent of $40 million)
• Southwest Gas: $652,000 (1.63 percent of $40 million)

The interconnection incentive program is currently fully subscribed, but still accepting reservations from interested developers. The current wait list includes roughly $38 million in funding requested by project developers, mostly within PG&E and SoCalGas service territories.

Comments

Need for the bill. According to the author:

While California is on track to meet its 40% methane reduction goal for dairies, progress in reducing methane emissions from landfills and wastewater treatment plants has been slow. One major barrier is the lack of utility procurement of RNG, which discourages investment in new RNG projects at these facilities. A key cost barrier is the high price of interconnecting RNG projects to the gas grid, which is substantially higher in California than in other states. Under current rules, developers must either provide a contribution in aid of construction or advance interconnection costs to utilities, which are subject to a 24% federal tax under the Income Tax Component of Contributions and Advances (ITCCA). SB 919 removes financial barriers to RNG development and supports California’s climate goals by reducing interconnection costs for RNG projects. The bill authorizes gas utilities to include just and reasonable interconnection costs in their rate base, eliminating the 24% federal ITCCA tax and leveraging lower utility financing costs to generate ratepayer savings. By addressing infrastructure financing constraints rather than creating a new procurement mandate, SB 919 provides a structural solution to unlock additional biomethane supply, reduce methane emissions from waste streams, and support long-term market stability.

Costs of interconnecting projects. As noted above, the costs to interconnect biomethane projects to the natural gas utility system are borne by the project developers and are subject to income tax obligations. The proponents of this bill suggest authorizing recovery of the interconnection costs by natural gas utility customers, rate base, rather than the developers would reduce the costs for these projects. However, as noted by The Utility Reform Network (TURN), rate basing these projects also subjects them to a rate of return for the utility, roughly 10% and subject to long-term financing costs. As a result, it’s possible these costs could be higher than the amount that would otherwise be paid by the developer, particularly if they benefit from an incentive.

CPUC issued a proposed decision. On March 6, the CPUC issued a proposed decision (Rulemaking 13-02-008) regarding several issues concerning biomethane. The proposed decision modifies the above biomethane procurement targets, reducing them to 36.4 Bcf annually, in part to protect ratepayers from these procurement costs. The decision also considered whether to authorize recovery of interconnection costs from ratepayers, instead of the project developers. The proposed decision declines to allow ratebasing of biomethane interconnection costs “until demonstrable progress has been made to reduce current interconnection costs and introduce meaningful costs control measures.” The CPUC noted that costs for interconnection projects are higher in California but needs more information to understand the reasons for higher costs compared to other states. The CPUC proposed decision acknowledges that interconnection costs are an “obstacle for both producers, who bear the uncertainty and pay the up-front costs of project development, and ratepayers, who eventually see interconnection costs reflected in higher priced renewable gas procurement contracts.” The CPUC decision orders two next steps: (1) natural gas corporations to host a workshop within 6 months on the topic of interconnection costs, including cost analysis; and (2) orders natural gas corporations to jointly submit proposals (via Tier 2 Advice Letter) within three months of the workshop to reduce interconnection costs. The proposed decision further states: “after this process has concluded, the Utilities [natural gas corporations] may file Applications to ratebase certain interconnection costs.”

Based on the CPUC proposed decision and concerns about the impacts to ratepayers of authorizing the recovery of interconnection costs in utility ratebase, the legislature may wish to hold off on authorizing these costs in the ratebase as proposed by this bill. The legislation would circumvent the deliberate, albeit slower process, at the CPUC to investigate the costs and determine which aspects might merit treatment in the ratebase. It should also be noted the CPUC proposed decision declined to extend the biomethane monetary incentive program, as several parties opposed its extension, including the Public Advocates Office and Sierra Club.

Need for amendments. XXX

Prior/Related Legislation

AB 1207 (Irwin, Chapter 117, Statutes of 2025), among its provisions, extended the authorization for the GHG emissions reduction market-based compliance program (now coined as the Cap-and-Invest Program) and design regulations, including distribution of emissions allowances in a manner that transitions support from gas corporations to electrical distribution utilities on or before January 1, 2031.

SB 377 (Grayson, 2025) would have required policies to support deployment of biomethane production, including expanding eligibility to out-of-state projects for existing biomethane projects and required the CPUC to authorize natural gas corporations to recover the costs of biomethane projects from their customers.

AB 678 (Alvarez, Chapter 339, Statutes of 2023) extended the authority of the CPUC to establish biomethane procurement targets on gas corporations to also include core transport agents – third-party natural gas providers.

AB 3187 (Grayson, Chapter 598, Statutes of 2018) directed the CPUC to open a proceeding, by no later than July 1, 2019, to consider options to promote the in-state production and distribution of biomethane, including whether to allow recovery in rates of interconnection costs for biomethane projects.

SB 1440 (Hueso, Chapter 739, Statutes of 2018) required the CPUC, in consultation with the CARB, to consider adopting specific biomethane procurement targets or goals for each natural gas corporation. The bill required the CPUC, if the CPUC adopts those targets or goals, to take certain actions regarding the development of the targets or goals and the procurement of the biomethane to meet those targets or goals.

AB 2313 (Williams, Chapter 571, Statutes of 2016), codified, modified and extended the biomethane monetary incentive program without specifying a funding cap or a particular funding source. The bill also required consideration by the CPUC of whether to allow recovery in rates of interconnection costs for biomethane projects.

SB 1383 (Lara, Chapter 395, Statutes of 2016) required state agencies to consider and, as appropriate, adopt policies and incentives to significantly increase the sustainable production and use of renewable natural gas, including biomethane to meet the state’s climate change, renewable energy, low-carbon fuel, and short-lived climate pollutants goals, including black carbon, landfill diversion, and dairy methane targets.

SB 840 (Committee on Budget and Fiscal Review, Chapter 341, Statutes of 2016) required the CPUC to reevaluate its requirements and standards for biomethane to be injected into common carrier pipelines.

AB 1900 (Gatto, Chapter 602, Statutes of 2012) directed the CPUC to identify landfill gas constituents, develop testing protocols for landfill gas injected into common carrier pipelines, adopt standards for biomethane to ensure pipeline safety and integrity, and adopt rules to ensure open access to the gas pipeline system.

AB 2196 (Chesbro, Chapter 605, Statutes of 2012) ensured that biogas qualifies for RPS credit, provided its production, delivery and use meet certain conditions.

SB 1122 (Rubio, Chapter 612, Statutes of 2012) required IOUs to collectively procure at least 250 MW of generation eligible for the RPS from bioenergy generation project, including biogas projects.

FISCAL EFFECT: Appropriation: Fiscal Com.: Local:

SUPPORT:

Renewable Natural Gas Coalition, (Sponsor)

Agricultural Council of California
Agricultural Energy Consumers Association
Ameresco

Bioenergy Association of California

California State Pipe Trades Council
Divert, Inc.

Generate Upcycle

Hexagon Group

LF Bioenergy

Maas Energy

Milk Producers Council
Montauk Renewables

Republic Services

Sevana Bioenergy

Southern California Gas Company

The Transport Project

UGI Energy Services

Waga Energy

OPPOSITION:

California Environmental Voters
Californians Against Waste
Center for Biological Diversity
Earthjustice
Leadership Counsel for Justice & Accountability
Sierra Club California
The Utility Reform Network

ARGUMENTS IN SUPPORT: According to the Renewable Natural Gas Coalition (RNG), sponsor of this bill:

Currently, RNG developers seeking to connect to utility pipelines must provide the contribution in aid of construction or advance the funds for interconnection, which is subject to a Federal 24% tax factor under the Income Tax Component of Contributions and Advances (ITCCA). This additional cost burden has made it extremely difficult to deploy RNG projects in California in a cost-effective way, limiting ability to achieve its methane reduction goals. This bill directly addresses this challenge by authorizing gas utilities to include just and reasonable RNG interconnection investments in the overall rate base, with project limits that are consistent with the existing biomethane monetary incentive program and annual limits that further protect ratepayers. Allowing these costs to be rate-based eliminates the ITCCA tax penalty and enables interconnection investments to be financed at utility customers. Finally, SB 919 stresses the importance of needing to fund the Biomethane Monetary Incentive Program (BMIP), which has been a highly successful program in encouraging the development of biomethane projects and significantly reducing methane emissions in the state.

ARGUMENTS IN OPPOSITION: According to The Utility Reform Network (TURN):

TURN opposes requiring the CPUC to allow gas utilities to place biomethane project interconnection costs into ratebase. This issue is currently being evaluated by the CPUC in R.13-02-008. On March 6, 2026, CPUC President John Reynolds issued a Proposed Decision rejecting the exact treatment required under SB 919. The Proposed Decision explains that “the Commission declines to allow ratebasing of biomethane interconnection costs until demonstrable progress has been made to reduce current interconnection costs and introduce meaningful cost control measures.” (Proposed Decision, page 59) If the utilities can demonstrate progress on reducing interconnection costs through a process laid out in the Proposed Decision, the Commission would consider applications to ratebase “certain interconnection costs”. Given the CPUC’s ongoing review of this issue, and its pending rejection of the proposal to ratebase all biomethane interconnection costs, it is inappropriate for the Legislature to circumvent the ongoing process and require ratebasing under all circumstances.

-- END --