A gas utility can meet every survey schedule and still struggle to show which indications mattered and what happened to them.

Compliance requirements for gas distribution have been in motion since 2020. The federal leak detection and repair (LDAR) rulemaking has been proposed, finalized, and withdrawn, and has not been re-proposed. Some utilities have responded by holding program decisions until the picture settles.

That is a reasonable instinct, and it reflects real uncertainty about timing. But it treats compliance as the finish line. For a gas utility, the real question is whether the program can explain its decisions when a regulator, an auditor, or someone inside the utility asks why a particular call was made.

The LDAR trajectory is clear, even if the final rule is not.

Both versions of the PHMSA rulemaking have asked for the same things:

• A written advanced leak detection program
• A minimum equipment sensitivity rather than a mandated technology
• Survey frequencies that increase with class location and population density
• Leak grading tied to repair timelines

States are moving forward. California has operated under leak abatement requirements for years. Colorado’s Public Utilities Commission adopted advanced leak detection and repair timeline standards that took effect this year. Other states have written grading and repair rules into statute or commission regulation, or have approved advanced leak detection programs through rate proceedings, which draws less attention than a federal rulemaking but is no less binding.

A utility operating across several states is already managing several versions of the same expectation. If a federal rule returns, it’s fair to assume it will ask for what every version has asked for: a program that can show what it found, what it decided, and why.

A defensible program can explain its decisions with leak survey data.

A review can reach back to any single indication and ask why it was investigated or cleared, how it was graded, and whether a technician in another district would have made the same call.

In a defensible program, the answer is already there. The decision and the data behind it live in the same place, connected when the decision was made rather than matched up later. Pull a second indication from a different crew in a different district, and the record looks the same.

In a program that is compliant but not yet defensible, the same question quickly turns into a project. Answering a question about one decision means pulling from multiple sources and piecing the story together after the fact.

The cost of that gap shows up in the field every survey cycle. Most utilities carry a backlog of Grade 3 leaks that are monitored rather than repaired, and advanced detection finds them again every time a vehicle drives past. Unless the record connects each new indication back to the leak already on file, someone has to investigate it again, reach the same conclusion, and log the same result. The program is compliant. It is also spending time and money to learn what it already knew.

That is the main difference between the two. Compliant means the required work happened, and the survey schedule will attest to that. Defensible means the utility can also show why each decision was made, and which indications mattered, without anyone having to reconstruct it.

Defensibility looks different at every level of the utility.

At the field level, it means the decision is recorded alongside the indication it responds to, whether the decision is to investigate, to clear, to assign a grade, or to match it to a leak already on file. The record shows what the team was looking at and what it decided, with little to reconcile afterward.

At the management level, it means seeing survey and investigation activity across crews, districts, and years in one place. Follow-up gets scheduled by risk rather than by order of arrival, and the record of what was done is the same everywhere on the system.

At the leadership level, it means walking into a rate case with the evidence to answer the question a commission actually asks: why is this investment justified? Advanced leak detection is approved because it makes the system safer and more reliable, and a defensible record is what lets a utility show that it is delivering those outcomes, and doing so efficiently. The evidence behind a field decision is also the evidence behind a capital decision: measured conditions, over time, across a defined part of the network. Commissions increasingly expect that kind of justification for infrastructure spending. A utility that has it can make the case to repair the leaks that matter and to prioritize replacement where the data supports it, rather than defending either one on general grounds.

A simple test

Pick one indication from a year ago and trace it end to end. How many systems does it take? How much depends on anecdote or memory? And if the same indication came in today, could you see it, the response, and the record together, or would you be assembling that picture all over again?

If the answer comes easily, the program is defensible today. If it does not, the problem is how the work is recorded, and that is fixable.

That is where methane intelligence comes in. When detection, field verification, and documentation are connected in one operational view, the record of what was found and what was decided takes shape as the work is done. It feeds the systems the utility already relies on, stays current from one compliance cycle to the next, and is ready when the question arrives.

Utilities have already modernized much of the grid. Methane risk management is the next step, and the standard it will be held to is defensibility.

Project Canary works with gas utilities to connect detection, field verification, and documentation in one operational view of methane risk.

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