The reporting requirements in 40 CFR Part 98, Subpart W apply to petroleum and natural gas facilities that emit 25,000 metric tons or more of carbon dioxide equivalent in a calendar year, and they require you to quantify methane and CO2 from specified sources across the production-to-distribution chain, keep a written monitoring plan, and submit an annual report to EPA through the e-GGRT portal certified by a designated representative.1eCFR. 40 CFR 98.2 – Who Must Report? What follows is what triggers the obligation, what you have to measure, how to file, and what happens if you get it wrong.
Who Has to Report
The 25,000 metric ton CO2e threshold is set in the program’s general provisions at 40 CFR 98.2, not in Subpart W itself, but it is what pulls a petroleum or gas operation into the reporting mandate.1eCFR. 40 CFR 98.2 – Who Must Report? You calculate the number by adding emissions from all stationary combustion units and every applicable Subpart W source at the facility. Once you cross the line, the obligation continues until emissions fall below specified levels for several consecutive years.
What counts as a single “facility” is where operators most often go wrong. For most industry segments a facility is one physical location under common ownership or control. Onshore production is the exception. There, a facility is every well pad and its associated equipment that the same owner or operator controls within a single hydrocarbon basin, as defined by the American Association of Petroleum Geologists.2eCFR. 40 CFR 98.238 – Definitions Onshore gathering and boosting uses the same basin-level grouping.3US EPA. Subpart W Information Sheet
Two hundred wells scattered across a basin roll up into one facility. A company that assumes each pad reports independently may conclude none crosses 25,000 tons, when the aggregated basin total clears the threshold easily. That mistake doesn’t just distort the numbers. It can mean no report gets filed when one is legally required.
Industry Segments and Why Your Classification Matters
Subpart W divides the sector into distinct segments in 40 CFR 98.230, each with its own operational boundaries, source types, and calculation methods.4eCFR. 40 CFR 98.230 – Definition of the Source Category
- Offshore production: platforms and floating production equipment that extract hydrocarbons from the ocean or lake floor, including connected secondary structures and storage tanks.
- Onshore production: all equipment on or associated with a well pad used to extract, separate, or treat petroleum and natural gas, including compressors, dehydrators, storage vessels, and CO2 enhanced oil recovery.
- Onshore natural gas processing: plants that separate natural gas liquids or remove impurities to meet pipeline specifications, plus residue gas compression.
- Onshore natural gas transmission compression: compressor stations that push gas through transmission pipelines toward distribution or storage.
- Underground natural gas storage: depleted reservoirs, aquifers, or salt caverns used to hold gas for later use.
- LNG storage: facilities that store natural gas in liquefied form.
- LNG import and export equipment: terminals where fuel transitions between liquid and gaseous forms for international trade.
- Natural gas distribution: local pipeline systems that deliver gas to end users.
- Onshore gathering and boosting: pipeline networks and compressors moving gas from wellheads toward processing plants.
- Onshore natural gas transmission pipelines: the pipelines themselves, distinct from the compressor stations that pressurize them.
Using the wrong segment’s methodology produces numbers that won’t clear EPA’s verification checks and can trigger enforcement.
What You Have to Measure
Within each segment, Subpart W identifies specific emission source types that must be quantified: equipment leaks at valves, connectors, and flanges; intentional venting from pneumatic devices; flaring of waste gas; combustion slip from compressor engines; and emissions from storage tanks, dehydrators, and acid gas removal units.
The measurement approach has shifted. Historically most operators counted equipment, multiplied by a default emission factor published in the regulation, and reported the result. EPA’s May 2024 final rule added calculation methods that allow, and in many cases require, direct measurement of actual emissions instead.5Federal Register. Greenhouse Gas Reporting Rule: Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems
Pneumatic devices show the change most clearly. Facilities with 25 or fewer gas-driven pneumatic devices must measure all of them every year. Facilities with 26 to 50 devices must measure all of them within a two-year cycle, and the interval extends by another year for each additional 25 devices, capping at a five-year cycle above 100 devices. Each measurement must last at least 15 minutes, with a five-minute minimum for isolation valve actuators.5Federal Register. Greenhouse Gas Reporting Rule: Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems
The 2024 rule also introduced facility-specific emission factors for equipment leaks, developed from direct measurement data collected at your own facilities. For large glycol dehydrators and acid gas removal units, certain input parameters must now come from actual unit-level measurements rather than engineering estimates. And starting with reporting year 2025, operators must calculate and report emissions from “other large release events,” a new category that captures unplanned or abnormal releases outside routine source types.5Federal Register. Greenhouse Gas Reporting Rule: Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems
Your Monitoring Plan and Records
Every reporting facility must maintain a written GHG Monitoring Plan. It has to identify the job titles responsible for collecting emissions data, describe the processes and methods used for data collection, spell out quality assurance and quality control procedures for each measurement technique, and explain how missing data are handled.6eCFR. 40 CFR 98.3 – What Are the General Monitoring, Reporting, Recordkeeping, and Verification Requirements? The plan is not submitted to EPA, but it must be available for inspection on request and updated whenever methods or personnel change.
Records must be kept for at least three years from the submission date of the annual report they support. If your facility is required to use EPA’s verification software under 40 CFR 98.5(b), retention jumps to five years.6eCFR. 40 CFR 98.3 – What Are the General Monitoring, Reporting, Recordkeeping, and Verification Requirements? The records include a list of all units and processes for which you calculated emissions, the underlying data by fuel or material type, analytical results, the annual reports, and documentation of any missing data events with their cause and how the gap was filled.
Filing the Annual Report
Reports go through the Electronic Greenhouse Gas Reporting Tool, the web portal EPA uses for the entire reporting program. The standard deadline is March 31 for the previous calendar year’s emissions.1eCFR. 40 CFR 98.2 – Who Must Report? For reporting year 2025, EPA extended the deadline to October 30, 2026, a one-time extension tied to pending revisions to the program.7Federal Register. Extending the Reporting Deadline Under the Greenhouse Gas Reporting Rule for 2025
Before anything is filed, the company must appoint a designated representative who takes legal responsibility for the submission. That person signs a Certificate of Representation and a certification statement affirming the report is true, accurate, and complete. False statements can trigger civil and criminal enforcement under Section 113 of the Clean Air Act.
What Happens After You File
Every submission runs through EPA’s automated validation and verification checks, which flag inconsistencies, outliers, and missing fields. If the system identifies potential errors, EPA notifies you, and you either explain why the flagged item is not an error or correct it and resubmit.8US EPA. GHGRP Methodology and Verification The report is not finalized until all flags are resolved.
These checks compare current-year data against the facility’s historical submissions, check mathematical consistency across reported source categories, and flag year-over-year changes in throughput or emissions that lack explanation. Treating the filing deadline as the finish line is a common mistake; plan for staff time during the post-submission review window as well.
Penalties for Getting It Wrong
Civil penalties under Section 113(b) of the Clean Air Act can reach $124,426 per day per violation, based on the inflation adjustment effective January 2025.9GovInfo. Civil Monetary Penalty Inflation Adjustment Rule Penalties accumulate daily, so missed deadlines and inaccurate data compound quickly.
Criminal penalties apply when someone knowingly makes a false statement, omits material information, or tampers with monitoring equipment. A first conviction can bring up to two years in prison, a fine under Title 18, or both. A second conviction doubles both maximums.10Office of the Law Revision Counsel. 42 USC 7413 – Federal Enforcement The “knowingly” standard does not require intent to harm the environment. Signing off on a report you know has gaps is enough.
Two Related Programs That Are Not Subpart W
Two adjacent programs often get bundled with Subpart W in conversation, but neither changes your reporting obligations. The Methane Super Emitter Program under 40 CFR Part 60, Subpart OOOOb, addresses unplanned methane releases quantified at 100 kilograms per hour or greater by EPA-approved remote sensing. When EPA forwards a super-emitter notification, you must begin investigating within five calendar days and report findings within 15 days.11US EPA. Methane Super Emitter Program That is a separate regulatory obligation running alongside Subpart W, not part of it.
The Waste Emissions Charge created by the Inflation Reduction Act would have imposed per-ton fees on methane emissions above certain intensity thresholds at Subpart W reporters. Public Law 119-21, signed on July 4, 2025, pushed the start date from calendar year 2024 to calendar year 2034 and rescinded unobligated funding for the related Methane Emissions Reduction Program.12GovInfo. Public Law 119-21 No facility will owe the charge for reporting years through 2033 under current law. Subpart W reporting itself is unaffected. The data you file still feeds enforcement decisions, public disclosure, and other EPA programs.