For US Utilities serving 3,000-100,000 meters and for operations team, billing team and utility managers. For Heads of Billing who own collections accuracy and revenue leakage.
Methane emissions reporting is the process of measuring, recording, and submitting data on the methane a gas system releases, mainly from pipe leaks. For a gas distribution utility, the reporting that applies most directly is its annual pipeline safety report to PHMSA, which counts leaks repaired by cause, plus any state requirements and the EPA greenhouse gas program where it still applies. The reports are only as good as the leak, repair, and asset records behind them.
Methane is the main component of natural gas. When it escapes from a pipe, valve, meter set, or regulator station, it is both a safety hazard and a greenhouse gas. Methane emissions reporting is how a gas operator shows regulators, and increasingly customers and lenders, how much gas is escaping, where it escapes, and what the operator did about it.
For a gas distribution utility, most of that picture comes from leaks on mains and service lines. The operator finds a leak through a survey or a customer call, grades it, repairs it, and records the result. Reporting is the step that turns those individual records into the totals a regulator asks for.
This page covers distribution operators: municipal gas systems, investor-owned local distribution companies, and multi-service utilities that sell gas alongside water or electricity. If your utility also runs a gas utility management platform, the same customer, asset, and work order records feed these reports.
Upstream operators such as producers, gathering systems, and processing plants report under different segments and different rules. Searches for "methane emissions reporting oil and gas" mostly describe those segments. A distribution utility has no wellheads or compressor stations, so its reporting centers on the pipe in the ground and the meters on customer premises.
A gas distribution utility answers to several audiences, and each asks for a different cut of the same underlying leak data. The rules in this area changed repeatedly across 2025 and 2026, so each item below is described as the source document states it, and the table ends with where to check current status. Our overview of city gas distribution trends covers the wider industry shifts behind these requirements.
The EPA fact sheet states that, under the proposal, facilities in the natural gas distribution segment of subpart W would no longer report to EPA after reporting year 2024 (EPA). A proposal is not a final rule. Before relying on it, check EPA's rulemaking notices page for the final action.
The PHMSA rule faces the same caution. A policy brief from GTI Energy's Center for Methane Research notes that the January 2025 final rule had not been published in the Code of Federal Regulations as of May 13, 2025, and that its requirements could change before codification (GTI Energy). The same brief still describes the rule as a good best practice for leak detection and repair, which is why many operators use it to plan their programs.
Whatever the final shape of federal rules, the data a regulator, auditor, or lender will ask for is consistent. These are the records that need to exist for every leak:
Each of those records usually starts as a work order. A structured gas pipeline work order system captures the date, crew, and completion details at the time the repair happens, rather than asking someone to reconstruct them at year end.
Every operator builds this process a little differently, but the sequence is consistent.
Step three is where most reporting problems begin. If a leak is found but never tied to a work order and an asset, it cannot be counted correctly at step five.
Methane reporting is often described as a measurement challenge, but for a distribution utility it is mostly a records challenge. The measurement happens in the field. The reporting depends on whether the records from the field can be found, matched, and totaled months later.
Utilities that struggle with leak reporting usually fail one of these checks:
Can you list every leak found this year, with its grade, cause, and repair date, without searching through paper forms or spreadsheets?
Can you tell which pipe material, install year, and protection type each repaired leak occurred on?
Can you show that the leak survey equipment you used was validated, and when?
Can a second person produce the same annual totals from the same records?
If the answer to any of these is no, the first project is the record system, not the report. Pipe and equipment details come from the asset register; our guide to gas utility asset management software explains what those records should contain and how they connect to pipe replacement planning.
The GTI brief summarizes the January 2025 PHMSA rule in terms that matter for recordkeeping. Operators of gas distribution, transmission, and some gathering pipelines would need an advanced leak detection program with written procedures for each piece of equipment, and a list of the equipment used for screening and leakage surveys (GTI Energy).
According to the same brief:
Even if the rule changes before it is codified, these elements show what regulators and auditors are likely to value: survey records by area and date, equipment validation records, and a measured count of leaks found and fixed.
Three separate jobs are often grouped under "methane management." They use different tools and different teams, and only one of them is reporting.
A utility can do the first two well and still struggle with the third if the results are stored in different places. Larger operators in the natural gas distribution companies of North America often have dedicated compliance staff for this. A municipal gas system with a small team usually does not, which makes a single system of record more important.
Inspectors from a state commission or a PHMSA state partner usually look at the same set of items. Preparing them in advance shortens an audit.
Utilities that keep these records in a work order and asset system can generate them as filtered reports. Utilities that keep them in separate spreadsheets typically assemble them by hand each year.
SMART360 is a utility management platform. It does not detect leaks, calculate emissions, or file regulatory reports on a utility's behalf. What it provides is the record system that those activities depend on, on one database:
Leak survey instruments, GIS, and filing portals stay in place. SMART360 connects to them so the same records are not entered twice.
Methane emissions reporting is the process of measuring, recording, and submitting data on the methane released by a gas system. For a gas distribution utility, this mostly means leak records on mains and service lines, summarized in reports such as the annual PHMSA filing, state commission reports, and, where it applies, the EPA greenhouse gas program.
It depends on the current status of the rule. EPA's September 2025 proposal would remove the natural gas distribution segment of subpart W from the Greenhouse Gas Reporting Program after reporting year 2024. A proposal is not final, so check EPA's rulemaking notices page for the latest action before deciding what to file.
Gas distribution operators file an annual report under 49 CFR Part 191. It includes miles of main and numbers of services, and leaks repaired during the year by cause, separately for mains and services, with totals and hazardous counts.
Upstream oil and gas operators report emissions from wells, gathering, processing, and compression facilities. A distribution utility reports on pipe, regulators, and meters in its service territory, so its data comes mainly from leak surveys, repairs, and pipe records rather than from process equipment.
No. SMART360 does not detect leaks, calculate emissions, or submit regulatory filings. It keeps the work orders, asset records, and service point records that those reports are built from, and connects to other systems through pre-built integrations and APIs.
Methane reports are built from leak, repair, and asset records. SMART360 keeps work orders, asset records, customer accounts, and service points on one database, so the totals a regulator asks for come from one place instead of several spreadsheets.
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