Gas utilities report about 1 per cent of their gas as lost, a smaller number than ordinary meter error can produce on its own, so it cannot tell a leak from a meter's mistake
Each year every U.S. gas utility reports the share of its gas it cannot account for. In this page's model of a system that loses nothing at all, ordinary meter error alone puts that figure anywhere from about −0.8 to 2.2 per cent at its assumptions. About a third of reports are zero or negative, and a negative means the meters counted more gas going out than coming in, which no leak can do. Customers pay for it through their rates, under rules regulators set: in Texas and Oklahoma, the two states this page follows, about a dollar or two a year on a home's bill for all of it, and some of that gas was burned by customers whose meters missed it.
Reports through · PHMSA's gas distribution annual reports, data as of · PHMSA adds each year's reports to the file
- Customers carry the cost of lost gas: Texas's rule, for the utilities its Railroad Commission regulates, disallows lost-gas costs above 5 per cent of the gas a utility takes in unless the Commission allows more, and in Oklahoma at least one large utility's approved tariff collects it through the gas charge.
- The figure says most where it is far from the rest: 96 reports for 2025 are above 10 per cent, beyond anything ordinary meter error produces, though a report cannot say why.
- Where gas runs colder than 60 °F, some gas reported as lost was in fact delivered: cold gas is denser, a meter that does not correct for temperature counts too little of it, and that gas is then charged to every customer through the gas charge instead.
What utilities report
The figure is lost and unaccounted-for gas: the gas a distribution system bought or produced, minus the gas its customers and the company used (with some adjustments), as a percentage of the gas used1, over the twelve months to June 30. Each operator files it with the Pipeline and Hazardous Materials Safety Administration (PHMSA), the federal pipeline safety regulator, once for each state it serves. PHMSA's own report to Congress says what it is2: "LAUF gas is a combination of measurement inaccuracy and unknown leaks, but it is impossible to know the portion attributable to each."
1,369 reports for 2025. Each bar counts the reports that put a share of their gas, in quarter-point steps, as lost and unaccounted for. The median report is 1 per cent. The two end bars gather the 52 reports at −5 or below and the 96 above 10.
Zero or less: 32 per cent. 207 reports say exactly zero and 234 are negative: the meters say more gas went out than came in. A negative cannot be a physical loss.
A system that loses nothing. The shaded range is what this page's model of ordinary meter error reports for systems with no loss at all: the middle 90 per cent of them land between −0.8 and 2.2 per cent. Where the range sits depends on two assumptions, the gas's temperature and how many customer meters correct for it; its width, about 3 points, hardly does.
Inside it: 55 per cent of reports at this page's assumptions, 47 per cent of those that are not exactly zero, and 82 per cent of customers, counted by their service lines. That share moves with the two assumptions (the table in the appendix); the width does not. The typical report, 1 per cent, is smaller than the spread meter error alone produces, and at these assumptions a real two-point loss read by perfect meters would land inside the range too.
Far outside it. 96 reports for 2025 are above 10 per cent, and 52 are at −5 or below. Meter errors of the ordinary kind modelled here do not produce figures like those. That is where the number can say something: not what is happening, but that something other than ordinary meter error is.
The chart counts reports, one for each operator in each state, not gas: a town of a few hundred customers counts as much as a utility of a million, which is why the share of customers is given beside the share of reports. Natural gas systems only; the figure is each operator's own, as filed.
Who pays for it
In Texas the Railroad Commission's rule presumes that all lost and unaccounted-for gas3 is gas actually lost unless a utility proves in a rate case that part of it is something else, and it names among those things "meter errors due to inaccurate calibration or temperature and pressure fluctuations,". For ratemaking it disallows the expense of lost gas above 5.0 per cent of the gas metered into a distribution system, unless the Commission allows more on the facts of a case, and the Commission can still judge whether the cost is reasonable. The rule binds the utilities the Commission regulates; 80 of the 117 Texas reports for 2025 come from systems owned by cities, whose rates the cities set.
Oklahoma's rule requires gas to be measured4 "in order that the "lost and unaccounted for" gas in distribution may be accurately determined", and sets no percentage, and its rules for passing gas costs through to customers do not mention lost gas; 52 of the 66 Oklahoma reports for 2025 come from city-owned systems. One large utility's tariff5, approved by the Oklahoma Corporation Commission, says "LUFG shall be collected through the PGA", the purchased gas adjustment being the part of a bill that passes the cost of gas through to customers, and gives a two per cent safe harbor above which the Commission may disallow the excess. Its figure counts gas the company used as well as gas lost, so it is not on PHMSA's basis.
Your state:
Texas, 2024: a home used 37 thousand cubic feet of gas, and gas cost the state's utilities $3.25 per thousand at the city gate6. Each point of lost and unaccounted-for gas is about $1.21 a year on that home's bill. The system serving the median Texas customer, counting customers by service line, reported 1.29 per cent, about $1.56 a year, against a gas bill of about $668.
Oklahoma, 2024: a home used 54 thousand cubic feet of gas, and gas cost the state's utilities $6.19 per thousand at the city gate. Each point of lost and unaccounted-for gas is about $3.35 a year on that home's bill. The system serving the median Oklahoma customer, counting customers by service line, reported 0.38 per cent, about $1.27 a year, against a gas bill of about $756.
The gas is priced at what utilities pay for it, not at the retail price, which also pays for delivery. These are approximations: utilities recover the cost across all their customers and true it up once a year.
How a meter can report gas as lost that was delivered
Gas enters a distribution system through a city-gate station. The clip shows one kind of station meter, an orifice meter: a plate with a hole in it, across the pipe. The flow is inferred from how far the pressure falls across the plate, through a coefficient that comes from an equation fitted to laboratory data, not from a test of that meter. It leaves through the customer meters, thousands of them on a large system. Every one of them is a little wrong, and the reported figure is the difference between what the meters say came in and what they say went out.
Each meter's own error averages away across many of them. An error they share does not. The plainest shared error is temperature. A customer meter that does not correct for it counts the volume of the gas as it is, and the bill treats that volume as if the gas were at 60 °F. Cold gas is denser, so the meter under-counts it: at 55 °F, by about 1.0 per cent. If 70 per cent of a system's meters do not correct for temperature, which is this page's assumption and not a measured figure, about 0.7 per cent of the gas delivered is never billed by a meter. It still shows up as unaccounted for, and its cost goes back into the gas charge every customer pays. So that part of "lost" gas is not an extra charge for gas nobody got: it is gas customers burned, billed through the gas charge instead of through their meters. Warm gas does the opposite and pushes the figure down, which is one way a system can report a negative.
What the figure cannot tell you
A negative figure cannot be gas physically lost: the meters say more gas went out than came in. Many exact zeros follow the form's old rule rather than a measurement: until the 2017 reports PHMSA told companies: "PHMSA instructs companies that calculate a negative value for percent of LAUF gas to report zero." From the 2018 reports, negatives are allowed7, and of the 91 negative reports that year, 34 came from systems that had reported exactly zero the year before. In 2025, 207 reports were exactly zero and 234 were negative.
Nor is the figure a measure of leaks. The same report to Congress: "LAUF gas is not a valid proxy for either unknown leak volume or methane emissions." A report carries one percentage and nothing that would separate a real loss from a meter error. It can show a system whose figure sits far outside what meters alone produce, year after year; it cannot show how much of a typical figure is loss.
Method
The reports. PHMSA's gas distribution annual reports, Form PHMSA F 7100.1-1, Part G, field PERCENT_UNACC_GAS, from its bulk file of 2010 to 2025 reports. The form defines the figure as "Unaccounted for gas as a percent of total consumption", over the twelve months ending June 30. Each report covers one operator in one state, by the state of operation. From 2015 the reports say which gas a system carries, and only natural gas systems are kept (763 propane, landfill, synthetic and other reports left out). The chart bins the 1,369 reports for 2025 in quarter points, right-inclusive, so the bin ending at zero holds the exact zeros.
A system that loses nothing. A model of one system with no loss at all: receipts measured at a city-gate station, deliveries through 2,000 customer meters, figure (in − out) / out. Each error is a relative error on a volume, normal, split into a part that stays with the system and a part redrawn each year. Every input is an assumption: city-gate standard uncertainty 0.5 per cent, the customer meters' shared error 0.5 per cent between systems and its drift 0.2 per cent a year, each meter's own error 1 per cent, 70 per cent of meters without temperature correction at a mean gas temperature of 55 °F that varies by 1.5 °F from year to year, and a billing-period mismatch of 0.5 per cent. The shaded range is the middle 90 per cent of 200,000 such systems. The reported year-to-year changes are as wide as this model's at about 1.5 times these uncertainties, so the uncertainties are not set high. On PHMSA's basis, gas consumed, Texas's 5.0 per cent of gas metered in is 5.26 per cent, if what is consumed is what came in less what was lost.
Where the range sits depends on two of those assumptions; its width does not much. The share of 2025 reports inside it, as they move:
| Gas temperature | Meters not correcting | Range, % | Reports inside | Inside, zeros left out |
|---|---|---|---|---|
| 50 °F | 0% | −1.4 to 1.4 | 50% | 41% |
| 50 °F | 35% | −0.8 to 2.1 | 55% | 47% |
| 50 °F | 70% | −0.1 to 2.9 | 57% | 49% |
| 50 °F | 100% | 0.4 to 3.5 | 37% | 44% |
| 55 °F | 0% | −1.4 to 1.4 | 50% | 41% |
| 55 °F | 35% | −1.1 to 1.8 | 52% | 44% |
| 55 °F | 70% | −0.8 to 2.2 | 55% | 47% |
| 55 °F | 100% | −0.5 to 2.5 | 57% | 49% |
| 60 °F | 0% | −1.4 to 1.4 | 50% | 41% |
| 60 °F | 35% | −1.4 to 1.4 | 50% | 42% |
| 60 °F | 70% | −1.4 to 1.5 | 51% | 42% |
| 60 °F | 100% | −1.5 to 1.5 | 52% | 43% |
| 65 °F | 0% | −1.4 to 1.4 | 50% | 41% |
| 65 °F | 35% | −1.8 to 1.1 | 48% | 38% |
| 65 °F | 70% | −2.1 to 0.8 | 39% | 28% |
| 65 °F | 100% | −2.4 to 0.5 | 36% | 25% |
| 70 °F | 0% | −1.4 to 1.4 | 50% | 41% |
| 70 °F | 35% | −2.1 to 0.8 | 38% | 27% |
| 70 °F | 70% | −2.8 to 0.1 | 30% | 17% |
| 70 °F | 100% | −3.3 to −0.4 | 8% | 10% |
Dollars. Each state's residential consumption divided by its residential customers, EIA, 2024, times the citygate price, EIA, the same year, times the figure. The figure is the median of the state's reports for 2024 weighted by service lines: the system serving the median customer. PHMSA's year ends June 30 and EIA's is the calendar year.
The meter model
The pipeline meter model behind the clip, and what its errors are worth
The city-gate side of the model draws on an earlier piece of this work: a Monte Carlo model of a pipeline system of orifice meters, built on ISO 5167-2's Reader-Harris/Gallagher discharge coefficient8 and NIST's reference implementation of AGA Report No. 89. On a 0.50 meter its flow carries a standard uncertainty of 0.27 per cent over one calibration interval, 0.25 per cent of it from the discharge coefficient alone. For a system of 12 receipt and 3 delivery meters, 101 million cubic feet a day, the imbalance's standard uncertainty depends on whether the meters share that coefficient's error:
| The discharge coefficient's error is | Imbalance, standard uncertainty | One standard uncertainty, a year |
|---|---|---|
| independent at every meter | 0.18% | $210,000 |
| shared, receipts and deliveries alike | 0.055% | $65,000 |
| shared within each end, the ends apart | 0.36% | $420,000 |
Valued at $3.10 per million British thermal units, the median Henry Hub price10 from 2025-10 to 2026-09. The middle row is a limit, not a typical value: it holds only if every meter's error in the coefficient is exactly the same, and it rises toward the first row as that sharing weakens. An error shared by both sides of a balance cancels; one shared by one side only survives whole, which is why the customer meters' shared temperature error matters and their individual errors do not. The model, its tests and the full write-up are in the meter archive below. The price here is Henry Hub, a wholesale price, because these are pipeline meters, not a household's.
Limits
The reports are the operators' own figures; nothing here checks one. The no-loss model's inputs are assumptions, not measurements of any system, and its errors are drawn as normal: a station meter that fails for part of a year, a regulator off its set point or a wrong correction factor can move a figure much further, and the model has nothing for theft, unmetered use, estimated reads, accounting adjustments or leaks. The dollars are approximations. No operator is named in this page's text; the Sources cite one Oklahoma utility's tariff by name, and the downloadable table carries PHMSA's operator names as PHMSA publishes them.
The code
Python: the fetch scripts, each recording where and when its file came from; the readers; the payload builder; the no-loss model; the page generator; and the tests. The archive carries the payload and the operator table, not the raw files. 411 KB. The meter model is a separate archive, 645 KB.
Download source The meter model All code
Sources
- Pipeline and Hazardous Materials Safety Administration, Gas Distribution Annual Data, 2010 to present, Form PHMSA F 7100.1-1, Part G; and the form itself, rev. 10/11/2018 ("CY 2018 and forward").Each operator's percent unaccounted for, by state of operation, its owner type, and the Part G definition.
- Pipeline and Hazardous Materials Safety Administration, Report on lost and unaccounted for natural gas metrics, report to Congress under section 29 of the PIPES Act of 2016, May 2017.That LAUF combines measurement inaccuracy and unknown leaks in unknowable shares, is not a proxy for leaks or emissions, and the instruction to report a negative as zero.
- Railroad Commission of Texas, 16 Texas Administrative Code s.7.5525, Lost and Unaccounted for Gas, and s.7.5519, Gas Cost Recovery (Chapter 7 compilation effective 8 April 2024).The presumption, meter errors named in (a); lost-gas expense above 5.0% of gas metered in disallowed for ratemaking unless the Commission allows more (b), (c); the Commission's review of the reasonableness of gas expense (d); purchased gas adjustment clauses (7.5519).
- Oklahoma Corporation Commission, Oklahoma Administrative Code 165:45-7-11, Gas measurement requirements (Chapter 45 effective 1 October 2024); and 165:50, Fuel, Purchased Gas, and Purchased Power Adjustment Clauses (effective 25 July 2019).Measurement so that LAUF may be determined, no percentage; the purchased gas adjustment rules, which do not mention lost gas.
- Oklahoma Natural Gas Company, tariff schedules 1001 (Purchased Gas Adjustment Clause), 1071 (Unrecovered Purchased Gas Cost) and 1191 (Lost, Used, and Unaccounted for Gas Rider), as approved by the Oklahoma Corporation Commission."LUFG shall be collected through the PGA", the two per cent safe harbor and the Commission's power to disallow the excess; LUFG includes gas used.
- U.S. Energy Information Administration, natural gas series for Texas and Oklahoma: residential consumption, number of residential consumers, residential price and citygate price, annual.Gas per household and the price utilities pay for gas, by state.
- Federal Register 83 FR 3462, 25 January 2018, "Pipeline Safety: Information Collection Activities".PHMSA's change to a consumption denominator and its allowing negative values, from calendar year 2018 reports.
- Reader-Harris, ISO 5167: Past and Present, Global Flow Measurement Workshop, 2022; and Emerson, Conditioning Orifice Technology and Orifice Standards, technical note, Table 6, quoting ISO 5167-2:2003, section 5.3.3.1.The orifice equation the meter model uses and its coefficient's stated uncertainty.
- National Institute of Standards and Technology, AGA8 reference code (GERG-2008, DETAIL and GROSS), github.com/usnistgov/AGA8; not subject to copyright protection in the United States (17 U.S.C. 105), foreign copyright may apply.Compressibility and heating value in the meter model.
- U.S. Energy Information Administration, Henry Hub Natural Gas Spot Price, monthly, series RNGWHHD.The price the meter model's imbalance is valued at.