The U.S. State Oil and Gas Methane Regulations You Need to Know in 2026

Amid federal repeals and reconsiderations, state methane regulations are expanding in scope and complexity across the United States. In 2026, oil and gas operators face methane intensity verification rules, enhanced LDAR requirements, venting and flaring restrictions and climate disclosure mandates that may exceed or diverge from federal requirements.

This article outlines key state-level methane and GHG disclosure regulations impacting oil and gas operations. For related developments, see our other pieces covering U.S. federal EPA methane requirements, Canada (federal and provincial) and international import requirements.

Given the dynamic nature of methane regulations, we will continue to update this content periodically to reflect rule changes and our insights. Please refer to the date above for the latest revision.

Key takeaways: 

• In periods of federal regulatory uncertainty or deregulation, states often increase their regulatory programs

• Regulatory obligations will differ by geography, both in terms of physical location and where operators conduct business

Colorado GHG intensity verification: first report due in 2026

Colorado enacted a GHG emissions verification requirement in 2023 and the initial reports are due in 2026. The rule is designed to show compliance with the verification and reporting of methane emissions and calculated GHG intensities required in Regulation 7, part B, Sections VIII.F.-G., which apply to upstream owners and operators. 

Entities subject to this requirement are required to create a measurement-informed methane emissions inventory and use both that and other GHG emissions in intensity calculations. Operators have the option of developing their own measurement program or use state default intensity verification factors.

The first report, covering 2025 emissions, is due on June 30, 2026. Reports are due annually thereafter. 

Implications for operators: 

California Senate Bill 1137 effective but facing legal challenge

California Senate Bill 1137 (SB 1137) which applies to oil and gas production facilities within a health protection zone, is in force, though it is facing legal challenges from the Trump Administration.

California passed Senate Bill 1137 (SB 1137) and subsequently Assembly Bill No. 218 (AB 218), which prohibits the construction of new oil and gas production facilities within a health protection zone (HPZ) or located within 3,200 feet of a sensitive receptor. It also establishes stringent engineering, operational and monitoring requirements for existing oil and gas production operations within an HPZ or within 3,200 feet from a sensitive receptor.  

This rule is in effect, with phased requirements. The next requirement is a sensitive receptor inventory and map due by July 1, 2025. Health, safety and environmental requirements, including but not limited to enhanced LDAR, become effective July 1, 2026. Operators are required to submit a leak detection and response plan by 2028, to be fully implemented by 2030. 

Implications for operators: 

• Operators in affected areas should submit their sensitive receptor inventories and maps as soon as possible, if not already submitted 

• Sites must fully comply with other operational and engineering requirements by July 1, 2026 

• Continuous emissions monitoring programs take time to implement and Montrose recommends starting to lay the groundwork for those programs 

New Mexico methane waste rule 98% capture requirement deadline in 2026

The New Mexico Methane Waste Rule has been effective for several years, but the 98% gas capture deadline is December 31, 2026. The rule prohibits routine venting and flaring, except in cases of emergency or during malfunctions. It mandates monthly reporting and annual certification of compliance with gas capture requirements. Requirements apply to oil and gas operators and infrastructure involved in producing or handling natural gas in New Mexico. 

Implications for operators: 

• Operators subject to this rule must be able to certify compliance with the 98% gas capture requirement by December 31, 2026

• Venting and flaring reports and certification reports will be used to determine compliance with the capture requirement

• The annual certification report is due on February 28

New York GHG inventory for calendar year 2026 due in 2027

The state of New York established its own GHG emissions inventory reporting program to collect emissions data for specific industries, including several oil and gas industry segments. Entities that emit more than 10,000 metric tons (MT) of carbon dioxide equivalent (CO2e) annually are required to report. “Large Emission Sources,” defined as those that emit greater than 25,000 MT CO2e annually, are also required to submit monitoring plans to the state and have their emissions inventory reports independently verified. Note that the NY GHG Inventory requires the use of 20-year global warming potentials (GWPs), which are higher than the GWPs used in the federal GHGRP. 

The first reporting year is 2026. New York developed a GHG estimator tool and requires report uploads through its own state reporting portal.  

Implications for operators: 

• Operators should determine whether they are subject to reporting requirements and if so, whether they will be subject to the additional requirements for Large Emission Sources 

• Ensure calculations of CO2e use the 20-year GWPs when determining program applicability 

• All entities should ensure they are collecting data needed for the 2026 report 

• The Emissions Monitoring and Measurement Plan, applicable to Large Emission Sources only, is due on December 31, 2026 

• The first inventory report is due on June 1, 2027 

• The first verification report, for Large Emission Sources only, is due on December 1, 2027 

Several states have proposed or passed climate disclosure bills that impact oil and gas

Various states have enacted or proposed climate disclosure bills that mandate the disclosure of GHG emissions and climate-related financial risks by certain operators. The bills typically require calculations according to established standards and are triggered by defined financial thresholds. California was the first state to enact this type of legislation, but several states have proposed similar measures. A listing of states with climate disclosure bills mandating the disclosure of GHG emissions is below. Although enforcement of these laws is uncertain, the growing number of states pursuing this type of legislation indicates that states are increasingly working to influence GHG reporting requirements. 

Implications for operators: 

• Operators should closely monitor regulations impacting GHG disclosure by geography, often determined by whether an operator does business in the state and not only geographic location 
• Develop a Scope 2 and Scope 3 emissions inventory (in addition to the Scope 1 inventory that may be required by other regulations) 
• Prepare and submit required reports according to applicable deadlines

State programs are increasingly shaping methane compliance expectations, regardless of federal direction. Differences in calculation methodologies, allowed technologies and verification requirements require careful alignment and proactive strategy. 

To understand how state rules intersect with EPA requirements, consult our U.S. Federal methane article. For cross-border and export-related obligations, see our Canada and International articles. 

Want to build a more holistic and proactive methane mitigation program for your company? Get in touch today.