Environmental Regulations for the Oil and Gas Industry

Environmental regulations for the oil and gas industry reach every stage of a well’s life, from the first permit application through drilling, production, waste handling, and final plugging. Federal statutes set a national floor, states run most of the day-to-day permitting under programs that must be at least as strict, and a single well pad can trigger duties under half a dozen laws at once. The financial stakes are high: Clean Air Act penalties alone now reach $124,426 per day per violation, and a new federal charge puts a direct price on excess methane emissions.

Air Emissions From Wells, Tanks, and Compressors

The Clean Air Act is the primary statute controlling pollutants released during extraction and processing.¹ EPA’s New Source Performance Standards (NSPS) set equipment-level limits on methane and volatile organic compounds from wellheads, storage tanks, compressors, and pneumatic controllers. Separate National Emission Standards for Hazardous Air Pollutants (NESHAP) address toxics like benzene and toluene, which turn up in glycol dehydrators used to dry natural gas.²

Subpart OOOOa, OOOOb, and OOOOc

For facilities built or modified between September 2015 and December 2022, Subpart OOOOa requires operators to capture methane and VOCs that would otherwise vent.³ In March 2024, EPA finalized Subpart OOOOb for new and modified sources and Emission Guidelines OOOOc for existing ones, extending methane controls to previously unregulated sources including existing well sites and compressor stations.⁴

Several OOOOb compliance deadlines have been extended to January 22, 2027, covering zero-emission process controllers, equipment leak repairs, enhanced flare monitoring, and the Super Emitter Response Program. State plans implementing EG OOOOc for existing sources share the same January 22, 2027 submittal deadline. The underlying OOOOa standards remain fully enforceable in the meantime, and many parts of the 2024 rule are already effective.

Leak Detection and Flaring

Leak Detection and Repair (LDAR) programs require operators to survey equipment using optical gas imaging cameras or portable analyzers. When leaks turn up at valves, flanges, or connectors, a first repair attempt must happen within 30 days, and the repair itself must be completed inside that same window.³ Under OOOOb, survey frequency increases and the equipment covered expands.

Flaring is permitted during emergencies or specific operational phases, but the equipment must reach a high destruction efficiency so that unburned methane does not escape. Venting raw gas without combustion is increasingly restricted at both federal and state levels. Operators converting pneumatic controllers to zero-emission electric or compressed air systems have until the extended January 2027 date, but new installations must already comply.

Methane Fees and Greenhouse Gas Reporting

The Inflation Reduction Act created a Waste Emissions Charge that taxes excess methane from oil and gas facilities. For 2026, the charge is $1,500 per metric ton of reported methane above facility-specific thresholds.⁵ The thresholds vary by facility type: production facilities pay on methane exceeding 0.2% of natural gas sent to sale, gathering and boosting facilities exceeding 0.05%, and transmission facilities exceeding 0.11%. This is the first direct federal price on methane emissions in this sector.

The charge applies only to facilities already reporting under EPA’s Greenhouse Gas Reporting Program (GHGRP). Under Subpart W, any facility emitting 25,000 metric tons or more of carbon dioxide equivalent per year must submit annual emissions reports.⁶ Covered operations include onshore and offshore production, natural gas processing, transmission compression, underground storage, and LNG facilities.⁷

Super Emitter Response Program

Under Subpart OOOOb, EPA has established a program in which certified third parties detect and report large methane leaks using satellites, aerial surveys, or mobile monitoring. A “super emitter event” is any release at or near an oil and gas facility of 100 kilograms per hour of methane or more. Third parties must notify EPA within 15 calendar days of detection.⁸

Once EPA passes the notification to the facility owner, the operator must begin investigating within five calendar days, complete the investigation and report findings within 15 days, and update the report within five business days after any ongoing event ends. If an operator fails to respond, EPA posts the attribution publicly.⁸ Full implementation is extended to January 22, 2027, but the framework is in place now.⁴

Water Discharges and Spill Prevention

The Clean Water Act and the Safe Drinking Water Act together protect surface water and underground drinking water from oil and gas contamination.⁹ Under the National Pollutant Discharge Elimination System (NPDES), most operations cannot discharge produced water, the salty and often chemical-laden fluid that surfaces alongside oil, directly into rivers or streams. It must be treated to specific purity standards or sent to disposal. Uncontaminated stormwater runoff from oil and gas sites is largely exempt from NPDES permitting, but any runoff that contacts raw materials, waste products, or byproducts on site triggers permit requirements.¹⁰

SPCC Plans and Facility Response Plans

Any facility storing more than 1,320 gallons of oil in aboveground containers (counting every tank of 55 gallons or more, even if empty) must prepare a Spill Prevention, Control, and Countermeasure (SPCC) plan under 40 CFR Part 112. A well pad with a few storage tanks and fuel containers hits that threshold easily. The plan describes containment measures, inspection schedules, and response procedures to keep oil out of navigable waters.

Facilities that could cause “substantial harm” in a worst-case spill face a heavier obligation: a Facility Response Plan (FRP) under Section 311(j)(5) of the Clean Water Act. An FRP demonstrates readiness for a worst-case discharge, including response equipment, trained personnel, and coordination with local emergency services.¹¹

Underground Injection Control

Subsurface disposal of oilfield fluids falls under the Underground Injection Control (UIC) program, administered by EPA or by delegated state agencies. Class II wells handle oilfield brines, enhanced oil recovery injection, and hydrocarbon storage.¹² These wells must meet rigorous construction standards, with multiple layers of steel casing and cement isolating the injection zone from underground sources of drinking water.

Operators must demonstrate mechanical integrity at least once every five years for the life of the well.¹³ These tests verify that neither the tubing nor the outer casing is leaking in a way that could allow fluids to migrate into protected aquifers. A failed test means stopping injection immediately and notifying the regulating agency. Corrective work often involves pulling the internal tubing and replacing seals or recementing the wellbore.

Regulators also watch injection pressure to keep the surrounding rock from fracturing. High-pressure injection that exceeds formation limits can trigger seismic activity or contaminate freshwater wells. Induced seismicity has become a serious concern in several states, leading to injection rate limits and shutdowns in areas with elevated earthquake activity.

Exploration and Production Waste

The Resource Conservation and Recovery Act (RCRA) governs solid and hazardous waste nationwide, but 42 U.S.C. § 6921(b)(2)(A) exempts certain exploration and production (E&P) wastes from the heaviest hazardous waste requirements.¹⁴ Drilling muds, cuttings, and produced water are classified as non-hazardous even when they show characteristics like toxicity or ignitability. The exemption does not extend to downstream wastes from refineries or chemical plants, which remain subject to the full hazardous waste rules under Subtitle C of RCRA.¹⁵

Because the federal exemption pushes E&P waste management to the states, rules for pit lining, land application of drilling fluids, and off-site disposal vary considerably. Operators must keep records of the volume and destination of all waste hauled from a site regardless of jurisdiction.

Naturally Occurring Radioactive Material

One waste stream that catches operators off guard is Technologically Enhanced Naturally Occurring Radioactive Material (TENORM). The extraction process can concentrate radionuclides that exist naturally in deep formations, bringing them to the surface in produced water, scale buildup inside pipes, and filter socks.¹⁶ There is no uniform federal disposal standard for TENORM. States set their own limits for landfill disposal, and some require specialized licensed facilities. Operators working in formations known to produce elevated radioactivity should test equipment and waste streams early.

Environmental Review on Federal and Tribal Lands

Drilling on federal or tribal lands triggers the National Environmental Policy Act (NEPA), which requires the Bureau of Land Management or other lead agency to evaluate environmental consequences before issuing a permit.¹⁷ Review follows a tiered approach depending on expected impact.

Minor activities may qualify for a categorical exclusion. Congress has directed BLM to apply categorical exclusions for drilling on a site that hosted similar operations within the previous five years.¹⁸ A categorical exclusion does not erase environmental obligations, but it allows the operator to skip the longer assessment process.

Most new drilling proposals require an Environmental Assessment (EA) covering wildlife, vegetation, water resources, and cultural sites. If the EA concludes the project will not cause a major negative impact, the agency issues a Finding of No Significant Impact (FONSI) and the operator moves to the standard permit application. Projects expected to have a significant impact require a full Environmental Impact Statement (EIS), with extensive public consultation, analysis of alternatives, and assessment of cumulative effects. An EIS can take several years and hundreds of thousands of dollars in technical studies, and that timeline alone can decide whether a project pencils out.

Offshore Operations

Operations on the Outer Continental Shelf fall under the Outer Continental Shelf Lands Act. The Bureau of Ocean Energy Management (BOEM) handles lease sales, exploration plans, and environmental reviews for offshore areas.¹⁹ The Bureau of Safety and Environmental Enforcement (BSEE) handles operational safety, inspections, and enforcement once drilling begins.

Offshore rules add safety requirements onshore wells do not carry. Blowout preventer (BOP) systems must be able to close and seal the wellbore against the well’s maximum anticipated surface pressure. Operators must report equipment failures to both BSEE and designated third parties, and formal failure investigations must begin within 90 days of an incident.²⁰ Remotely operated vehicles must be able to independently open and close each shear ram on the BOP stack.

Operating Permits and Reporting

Larger facilities need a Title V operating permit under the Clean Air Act on top of construction and drilling permits. A facility qualifies as a “major source” if it emits 10 tons per year of any single hazardous air pollutant or 25 tons per year of any combination of hazardous air pollutants.²¹ Title V permits pull all applicable air requirements into one document, require regular compliance reporting, and go through public notice with at least 30 days for comment.²²

Reporting is electronic. EPA’s Central Data Exchange (CDX) is the primary portal for air and water reports.²³ For underground injection wells, operators use the EPA Form 7520 series covering permit applications, quarterly monitoring reports, annual disposal well reports, and plugging records.²⁴ Each wellbore has a unique API number of at least 12 digits that identifies the state, county, well, and individual wellbore.

Permit applications must include the chemical composition of any hydraulic fracturing fluids with CAS numbers for each ingredient, geological data on the target formation, site maps showing proximity to water bodies and buildings, and baseline water testing from nearby wells. Agency review can range from 90 days for straightforward projects to well over a year for complex installations on federal land.

Plugging and Abandonment

Every well eventually reaches the end of its productive life, and federal and state law require proper plugging and abandonment. BLM sets minimum standards for wells on federal and Indian lands, BSEE governs offshore abandonment, and states regulate wells on private land.²⁵ Plugging typically involves pumping cement into the wellbore at designated depth intervals to permanently seal off productive zones and protect freshwater aquifers.

The financial risk is substantial. States require operators to post surety bonds before drilling, but historically bond amounts have been far below actual plugging costs, leaving hundreds of thousands of “orphan” wells with no responsible party. The Infrastructure Investment and Jobs Act directed the Department of the Interior to establish federal, state, and tribal programs to plug, remediate, and restore wells that would otherwise leak methane and contaminate groundwater.²⁶ Operators acquiring existing wells should pay close attention to the abandonment liabilities they inherit.

Penalties

Enforcement scales quickly. The base Clean Air Act penalty of $25,000 per day has been pushed by annual inflation adjustments to $124,426 per day per violation as of the most recent update. Clean Water Act penalties reach up to $68,445 per day, and oil spill violations can go higher depending on the circumstances.²⁷

Beyond per-day fines, enforcement actions routinely include mandatory equipment upgrades, long-term environmental monitoring, and injunctive relief restricting future operations until compliance is demonstrated. For operators subject to the Waste Emissions Charge, $1,500 per metric ton of excess methane sits on top of any enforcement penalty.⁵ Traditional penalties, the methane fee, and a public Super Emitter attribution can hit the same facility at once.

1
US EPA. Summary of the Clean Air Act
2
Legal Information Institute. 40 CFR Appendix to Subpart HH of Part 63 – Tables
3
eCFR. 40 CFR Part 60 Subpart OOOOa – Standards of Performance for Crude Oil and Natural Gas Facilities
4
Federal Register. Oil and Natural Gas Sector Climate Review Final Rule
5
Congressional Research Service. Inflation Reduction Act Methane Emissions Charge: In Brief
6
US EPA. Subpart W Information Sheet
7
US EPA. What is the GHGRP?
8
US EPA. Methane Super Emitter Program
9
Office of the Law Revision Counsel. 33 US Code 1251 – Congressional Declaration of Goals and Policy
10
US EPA. Oil and Gas Stormwater Permitting
11
US EPA. Facility Response Plan (FRP) Overview
12
US EPA. Class II Oil and Gas Related Injection Wells
13
eCFR. 40 CFR Part 144 – Underground Injection Control Program
14
Office of the Law Revision Counsel. 42 USC 6921 – Identification and Listing of Hazardous Waste
15
US EPA. Summary of the Resource Conservation and Recovery Act
16
US EPA. TENORM: Oil and Gas Production Wastes
17
Office of the Law Revision Counsel. 42 USC 4321 – Congressional Declaration of Purpose
18
Bureau of Land Management. National Environmental Policy Act
19
Bureau of Ocean Energy Management. OCS Lands Act History
20
Bureau of Safety and Environmental Enforcement. Interior Department Finalizes Well Control Rule to Strengthen Offshore Safety Standards
21
US EPA. Who Has to Obtain a Title V Permit?
22
U.S. Environmental Protection Agency. Guidance on Streamlining Title V Operating Permit Reviews
23
Environmental Protection Agency. Central Data Exchange
24
Environmental Protection Agency. Underground Injection Control Reporting Forms for Owners or Operators
25
US EPA. Well Plugging
26
U.S. Department of the Interior. Orphaned Wells
27
eCFR. 40 CFR Part 19 – Adjustment of Civil Monetary Penalties for Inflation