Natural Gas Storage Capacity by State

The United States can hold about 4.83 trillion cubic feet (Tcf) of working natural gas underground. That is the August 2026 figure in the Energy Information Administration’s monthly storage capacity series, out of 9.38 Tcf of total capacity at 408 storage fields in 31 states. The other 4.55 Tcf is base gas, which stays in the ground to hold reservoir pressure.

Capacity and contents are different numbers. The most gas the weekly series has ever shown in storage, counting from 2010, is 4,047 billion cubic feet (Bcf) on November 11, 2016, and the highest week of 2025, November 7, 2025, was 3,950 Bcf. On October 23, 2026 the Lower 48 held 3,724 Bcf, 78 percent of the 4,760 Bcf those states reported as working capacity for August 2026.

EIA publishes three capacity figures for working gas: 4.83 Tcf across all fields on the books, 4.68 Tcf of design capacity for active fields and 4.28 Tcf of demonstrated peak capacity, and the last two cover the Lower 48 only. Each answers a different question: what all the fields on the books can hold, what the active fields were designed to hold, and what they have actually held. The state tables below use the 2024 annual series, because that is the only edition that splits capacity by field type. Michigan holds 14 percent of the working capacity, nineteen states and the District of Columbia have no underground storage field in EIA’s capacity tables, and working capacity has stayed flat from 2015 to 2024 while consumption rose 21 percent.

Total, working, design and peak capacity

EIA’s capacity tables define storage capacity as “The present developed maximum operating capacity” and working gas capacity as “The volume of total natural gas storage capacity that contains natural gas available for withdrawal.” The difference is base gas, which EIA’s storage basics page describes as “the volume of natural gas intended as permanent inventory in a storage reservoir to maintain adequate pressure and deliverability rates throughout the withdrawal season.” In the 2024 annual series that difference was 4.53 Tcf: 9.32 Tcf of total capacity less 4.79 Tcf of working gas. Base gas is 48.6 percent of the total, so a little under half of the system’s physical capacity is gas held as permanent inventory.

The monthly series is the newest. It reads 9.38 Tcf of total and 4.83 Tcf of working capacity for August 2026, which is 64 Bcf more total capacity and 37 Bcf more working capacity than the 2024 annual series, with 6 fewer fields on the books. The 2024 annual series reads the same as the December 2024 monthly figure for working gas capacity, and its total is 0.3 Bcf below the December 2024 monthly total of 9,319.6 Bcf. Tables 2, 3 and 5 and the chart use the annual series, and Table 10 compares it with the monthly series in separate columns.

The design and demonstrated peak figures come from the same EIA-191 operator survey and are published for the Lower 48 only. EIA’s May 2026 report says “Design capacity, sometimes referred to as nameplate capacity, is based on the physical characteristics of the reservoir, installed equipment, and operating procedures on the site, which often must be certified by federal or state regulators.” It says “Demonstrated peak capacity, or total maximum demonstrated working natural gas capacity, represents the sum of the largest volume of working natural gas reported for each individual storage field during the most recent five-year period, regardless of when the individual peaks occurred.” Because it is built from observed inventories, EIA calls it a conservative indicator: “Therefore, this measure provides a conservative indicator of capacity and may understate the amount that can be stored.”

The all-field and design figures differ by a stable amount. Lower 48 working gas capacity in EIA’s monthly series was 4,723.1 Bcf in December 2024 against a design capacity of 4,657 Bcf in November 2024, a gap of 66.1 Bcf. A year later it was 4,749.1 Bcf in December 2025 against 4,683 Bcf in November 2025, a gap of 66.1 Bcf again. The May 2026 report counts 375 active fields in the design figure and excludes 28 inactive ones. Those add up to 403, which equals the 403 Lower 48 fields in the August 2026 monthly count (408 less 5 in Alaska). The page’s reading is that the monthly series includes the inactive fields and that their working capacity is the gap; EIA’s tables do not state that, and the two sets of figures are a month apart.

The weekly figures are a different survey again. EIA estimates weekly stocks from a sample of operators on Form EIA-912, and compares them with the monthly census: from January 2010 through July 2026 the weekly estimates of total working gas stocks have shown an average absolute error of 11 Bcf, or 0.4 percent. EIA’s record for demonstrated peak capacity, 4,362 Bcf in 2016, is larger than the 4,047 Bcf record week of that year because it adds each field’s own peak, whenever it happened, while the record week counts what was in the ground on one Friday.

Salt caverns, aquifers and depleted fields

EIA’s basics page, dated November 16, 2015, says gas is “most commonly held in inventory underground under pressure in three types of facilities”: depleted reservoirs in oil and gas fields, aquifers and salt caverns. That page says depleted reservoirs are the most commonly used sites because of their wide availability, and that converting one from production to storage takes advantage of existing wells, gathering systems and pipeline connections. In the annual series they are 328 of the 414 fields, 77.5 percent of total capacity and 81.6 percent of working gas capacity.

The base gas share separates the three types sharply. Salt caverns carry 33.1 percent base gas, depleted fields 45.9 percent and aquifers 70.7 percent. EIA’s basics page says of aquifers that their use “usually requires more base (cushion) gas and allows less flexibility in injecting and withdrawing,” and that salt caverns “provide very high withdrawal and injection rates relative to their working gas capacity” with low base gas needs. Aquifers therefore hold 14.8 percent of the nation’s total capacity but only 8.4 percent of its working capacity, while salt caverns hold 7.7 percent of the total and 10.0 percent of the working gas.

Merging the two non-salt types gives 49.9 percent base gas, against 33.1 percent for salt. That matches the rule of thumb in the weekly storage report guide, about 30 percent base gas in salt caverns and about 50 percent in non-salt reservoirs, and shows that the 50 percent hides a wide spread: depleted fields are under half, aquifers over two-thirds. Field size does not explain the gap. The average salt cavern field holds 12.2 Bcf of working gas, the average depleted field 11.9 Bcf and the average aquifer 8.6 Bcf. What the capacity tables do not show is how fast each type cycles. The basics page says cavern construction costs more per thousand cubic feet of working gas capacity, but the ability to perform several withdrawal and injection cycles each year reduces the per-unit cost of each thousand cubic feet injected and withdrawn, so a Bcf of salt-cavern capacity can move more gas in a year than a Bcf of depleted field.

Each type clusters in a few places. 98.5 percent of salt-cavern working capacity, 470.5 of 477.7 Bcf, is in Texas, Louisiana, Mississippi and Alabama; the remaining 7.1 Bcf is in Virginia, Michigan and New York. EIA’s basics page says “Most salt cavern storage facilities have been developed in salt dome formations located in the Gulf Coast states,” with bedded-salt caverns made by leaching in the Northeast, Midwest and Southwest. Illinois, Iowa and Indiana hold 93.0 percent of aquifer capacity (1,282 of 1,379 Bcf). Depleted fields are in 27 of the 31 states, led by Michigan, Pennsylvania, Texas, California, Ohio and West Virginia; Iowa, Minnesota, Missouri and Washington have only aquifer capacity.

Salt-cavern working capacity fell by 13.5 Bcf between the 2023 and 2024 annual figures, from 491.2 to 477.7 Bcf, even though salt-cavern total capacity rose. EIA’s May 2026 report describes a 13.5 Bcf reclassification from working gas to base gas at Gulf South Pipeline’s Bistineau field in Louisiana, following a third-party engineering study. The two numbers are the same size, but the tables do not say Bistineau is counted as a salt cavern, so the match is an observation and not an EIA statement. A reclassification like this moves working capacity without any gas leaving the ground: base gas rises and working gas falls by the same amount, with total capacity unchanged.

Working capacity state by state

Michigan holds the most: 688 Bcf of working gas capacity in 44 fields, 14.4 percent of the U.S. total, nearly all in depleted fields. Texas (563 Bcf), Louisiana (430), Pennsylvania (426) and California (323) follow, and those five states hold 50.7 percent of the nation’s working capacity. The top three hold 35.1 percent and the top ten 76.1 percent.

Ranking by total capacity gives a different order. Illinois has 1,020 Bcf in total, second only to Michigan (1,076), and ahead of Texas (878), yet only 304 Bcf of it is working gas because 70 percent is base gas in aquifers. That puts Illinois 6th by working capacity. Michigan and Texas keep about 36 percent of their capacity as base gas, and Texas moves from third by total capacity to second by working capacity. Four Appalachian and Great Lakes states, Michigan, Pennsylvania, West Virginia and Ohio, hold 31.6 percent of all total capacity.

Montana is the outlier on size per field. Its 4 fields hold 197 Bcf of working capacity, 49.4 Bcf per field against 11.6 Bcf for the U.S. average, and that is 4.1 percent of the national total in a state with 0.09 Tcf of annual consumption. West Virginia has 31 fields and 265 Bcf. At the other end, four states (Virginia, Missouri, Minnesota, Tennessee) hold less than 5 Bcf each and 0.3 percent of the total between them. Alaska is separate from the rest: 5 depleted fields with 69.9 Bcf of working capacity and the lowest base gas share of any state, 18 percent. It is not in the Lower 48 weekly report or in EIA’s design and demonstrated-peak tables.

20 areas with no underground storage

Nineteen states and the District of Columbia have no storage fields in EIA’s capacity tables. In 2024 they used 7.03 Tcf, 21.3 percent of U.S. consumption. Florida is the largest at 1.69 Tcf, ahead of Georgia (0.76), North Carolina (0.69), New Jersey (0.66), Wisconsin (0.56) and Arizona (0.54). The tables count underground fields only. EIA’s basics page notes that natural gas is also stored in liquid or gaseous form in above-ground tanks, and none of that is in these numbers.

Fourteen of the twenty also report no gas production in EIA’s 2024 tables, which is the set the natural gas production by state guide counts: Connecticut, Delaware, District of Columbia, Georgia, Hawaii, Maine, Massachusetts, New Hampshire, New Jersey, North Carolina, Rhode Island, South Carolina, Vermont, Wisconsin. The other six (Arizona, Florida, Idaho, Nevada, North Dakota, South Dakota) produce some gas, from North Dakota’s large volumes to a few million cubic feet in Nevada, but none has a storage field. The tables do not show where these areas’ winter gas comes from. EIA’s weekly report puts all of them except Hawaii in a region that does have storage, which is the grouping used in the regional section below, and EIA’s basics page says most working gas in storage “is held under lease with shippers, LDCs, or end users who own the gas,” which is one way a facility in one state can serve customers in another. LDC here is EIA’s abbreviation for a local distribution company.

Storage against each state’s own use

Dividing each state’s working gas capacity by its average daily consumption in 2024 gives days of its own use. The U.S. figure is 53.1 days: 4.79 Tcf of working capacity against 33.06 Tcf of consumption, or 14.5 percent of one year’s use. Seventeen of the 31 storage states are above that average and fourteen below it. West Virginia comes out at 325 days and Michigan at 244, while Texas, with the biggest consumption of any state, is at 38.5 and New York at 34.6. Minnesota, Tennessee and Virginia hold under three days of their own use.

The ratio measures size, not security. Montana’s 810 days rest on 197 Bcf of capacity in a state that consumed 89 Bcf, 221 percent of a year’s use. EIA’s May 2026 report shows that Montana’s operators have demonstrated only 45 Bcf of the 197 Bcf design figure. On the demonstrated figure the same arithmetic gives 185 days. A state ratio also leaves out roles that cross state lines. Louisiana and Texas are in the South Central region, where EIA’s report lists the need to “Balance flexible receipts and deliveries to the growing South Central region pipeline and LNG export markets” among the reasons for more high-deliverability storage. The LNG export terminals guide has the plants on the demand side of that sentence.

Texas and California show what the ratio leaves out. Texas has 563 Bcf of working capacity, second only to Michigan, and that is 38.5 days of a 5.35 Tcf annual load; for the power side of that load, see the gas per megawatt-hour guide. California has 323 Bcf for 1.94 Tcf of use, 61.0 days, and almost all of that storage is in depleted fields. Neither number says how fast the gas can be withdrawn, which is the limit on a cold morning. EIA’s basics page defines deliverability as the daily withdrawal rate, in million cubic feet per day, and says it depends on how full the reservoir is. The capacity tables do not include it.

Capacity against use by storage region

EIA reports weekly storage for five regions, which it regrouped in 2015 to align storage locations with the markets they serve. Pennsylvania, Ohio, West Virginia, Maryland, Virginia and New York sit in the East region with Florida, Georgia, the Carolinas, New Jersey and New England. Tennessee is in the Midwest region, and the Mountain region includes Arizona and the Dakotas. A regional ratio is less sensitive to state borders than the state ratio in the last section.

The East looks thin: 1,043 Bcf of design capacity against 11.12 Tcf of use is 34 days, and 47 percent of that use is in 13 areas with no storage of their own, from Florida to Maine. The Midwest holds 1,221 Bcf against 5.59 Tcf, 80 days, and only Wisconsin lacks a field. The Mountain region is at 61 days, South Central at 55 and the Pacific at 52. The tables do not show how the areas without a field use storage, but any storage they use sits outside their borders. They show where the capacity is, not who uses it.

EIA’s basics page lists who runs the storage: interstate pipelines, intrastate pipelines, local distribution companies and independent storage service providers. A facility that serves interstate commerce is subject to the Federal Energy Regulatory Commission, and otherwise it is state-regulated. The page also says that after FERC Order 636 the major portion of working gas capacity at each interstate pipeline site, beyond what the operator reserves for system integrity and load balancing, “must be made available for lease to third parties on a nondiscriminatory basis.” Capacity at open-access sites can therefore be leased by parties located elsewhere, which is one reason a state’s own consumption is an imperfect yardstick for its storage. For how utilities pass gas costs through to bills, see the purchased gas adjustment guide.

Design capacity against demonstrated use

For the Lower 48, EIA’s May 2026 report gives design capacity of 4,683 Bcf and demonstrated peak capacity of 4,280 Bcf, so the fields’ five-year peaks add up to 91 percent of design capacity. The regions run from 67 percent in the Mountain region to 97 percent in the Pacific, with the East at 93, the Midwest at 96 and South Central at 93 percent. The 403 Bcf difference is concentrated: Montana alone is 152 Bcf of it, 37.7 percent, because its operators have demonstrated 45 Bcf against a 197 Bcf design capacity. Mississippi (49 Bcf), Ohio (35), Illinois (28) and Pennsylvania (26) are next. State gaps are differences of rounded figures and do not add exactly to the Lower 48 total.

Four states show a demonstrated peak above 100 percent of design capacity: Virginia (101%), Minnesota (113%), Indiana (105%), Colorado (106%). EIA’s note says peak capacity can exceed design “because design capacity limits may differ from actual capacity limits in storage fields, as determined by the facility operator and local regulations,” and that the effect is more common in states with a small number of facilities. Colorado’s ratio moved because its design capacity fell by 10 Bcf from November 2024 to November 2025 while its demonstrated peak was unchanged, which pushed the ratio over 100 percent. The change is in the design figure, not in the gas Colorado stored; the callout in the changes section covers how EIA’s text and table treat that 10 Bcf.

How full the system gets

The weekly series shows how much of the working capacity is ever used at once. In each year from 2013 to 2025 the highest weekly stock was between 68 percent (2018) and 85 percent (2016) of the December working gas capacity that EIA reports for the Lower 48. The highest week in the table is 4,047 Bcf on November 11, 2016, and the last two years reached 3,972 Bcf (November 8, 2024) and 3,950 Bcf (November 7, 2025). On October 23, 2026 stocks were 3,724 Bcf, 147 Bcf below a year earlier and 38 Bcf above the five-year average of 3,686 Bcf, still filling at 80 Bcf for the week.

From 2013 to 2025 no year’s highest week reached 90 percent of the capacity. A ratio below 100 is expected, because capacity is the sum of fields and EIA notes that the timing of peaks for different fields does not need to coincide, while the weekly stock is one national total on one Friday. The record week of 2016 is also the year with the highest ratio, 85.2 percent. The latest weekly report was released on Thursday, October 29, 2026, at 10:30 a.m. Eastern for the week ending October 23, 2026, and the next is due on November 5, 2026. The guide to the weekly storage report explains what the stock, change and implied-flow columns mean.

What winter takes out of storage

On a net basis, storage supplies a minority of winter gas. In the 14 winters from 2012-13 to 2025-26, the net fall in weekly stocks from the autumn high to the spring low was between 10.2 percent (2023-24) and 21.9 percent (2013-14) of total U.S. gas consumption from November through March. In 2025-26, stocks fell from 3,950 Bcf on November 7, 2025 to 1,818 Bcf on March 20, 2026, a net draw of 2,132 Bcf against 15,956 Bcf of consumption, 13.4 percent. The rest of that consumption was met by production and imports in the same months, net of exports.

The net draw understates what storage does, because injections and withdrawals both happen inside a winter and the net figure nets them. For scale, the 4.79 Tcf of working capacity in the 2024 annual series is 1.22 times the 3.92 Tcf the country used in January 2025, the heaviest month in EIA’s monthly series, which starts in 2001. The largest net draw in the table, 3,010 Bcf in 2013-14, was 22 percent of that winter’s November to March use, and the smallest, 1,577 Bcf in 2023-24, was 10 percent. The natural gas price drivers guide covers how the storage level feeds into price, and the Henry Hub guide explains the benchmark that reacts to it.

What changed since the 2024 annual figures

Between the 2024 annual series and August 2026, 13 of the 31 states show a change of at least 0.05 Bcf in working or total capacity, or a change in field count, in the monthly series. Texas leads: +33.4 Bcf of working capacity and +43.0 Bcf of total. Wyoming adds 16.0 Bcf. Mississippi adds 2.0 and California 1.2. Colorado loses 10.0 Bcf of working capacity, and Michigan loses 2.0. The changes sum to +36.6 Bcf nationally.

EIA’s May 2026 report names several of the projects behind these moves. Trinity Gas Storage began commercial operation of a new East Texas facility in 2025 with 18 Bcf of working capacity and expanded its Bethel Dome facility by 2.5 Bcf, and Spire Storage West raised the certificated working gas design capacity of its Clear Creek facility by 16.6 Bcf. Those fit the Texas and Wyoming moves in Table 10, but the monthly Texas increase of 33.4 Bcf is larger than the 20 Bcf of Texas design capacity the report covers through November 2025, so some of it arrived later or comes from other changes the tables do not itemize. The report also cites Columbia Gas Transmission’s base gas restoration, which raises base gas and cuts working capacity at its facilities, mostly in Ohio and West Virginia. Ohio and West Virginia both show small declines in Table 10.

The field count needs care. The U.S. count went from 414 to 408, a net fall of 6. Oregon’s count fell from 8 to 1 with no change in its 21.6 Bcf of working capacity, and Texas gained 1 field. EIA’s monthly table does not say why Oregon’s count dropped. The unchanged capacity suggests, in the page’s reading, a change in how fields are counted and not a loss of storage.

Demand grew while capacity stood still

Working gas capacity in the annual series was 4,801 Bcf in 2015 and 4,793 Bcf in 2024, a change of -0.16 percent. U.S. consumption over the same years rose 21.3 percent, from 27.24 to 33.06 Tcf. Capacity as a share of one year’s consumption therefore fell from 17.6 percent in 2015 to 14.5 percent in 2024, and the days of average use that working capacity covers fell from 64.3 to 53.1. The 2025 line uses the December monthly capacity and the monthly consumption sum, and shows 52.5 days.

Total capacity moved more than working capacity. From 2019 to 2024 total capacity rose 88 Bcf, 1.0 percent, while working capacity changed by -29 Bcf, -0.6 percent. The difference between the two, base gas, therefore rose by 117 Bcf. EIA’s May 2026 report lists market factors behind less need for new storage, among them lower prices from higher production, more pipeline capacity and interconnection, and small seasonal differences between winter and summer prices. It also lists factors that point to a greater need: electric power demand, wind and solar variability, and LNG export and pipeline markets in the South Central region. EIA says Lower 48 demonstrated peak capacity increased for the third year in a row in 2025, after falling from its 4,362 Bcf high in 2016. The natural gas price history by year gives the annual Henry Hub averages for context on those seasonal price differences.

Sources and check dates

Data and sources, all checked November 4, 2026: U.S. Energy Information Administration, Underground Natural Gas Storage Capacity, annual series: total capacity, salt caverns, aquifers, depleted fields, working gas capacity (and its salt, aquifer and depleted-field series), number of fields (and its three type series) and the monthly total and working gas series, release of October 30, 2026 (next release November 30, 2026), with the table definitions; EIA, Underground Natural Gas Working Storage Capacity, With Data for November 2025 (May 2026; EIA’s page lists it as the current issue, with the next due in May 2027); EIA, The Basics of Underground Natural Gas Storage (page dated November 16, 2015, so its descriptions of storage types and operators are not a current census); EIA, Weekly Natural Gas Storage Report for the week ending October 23, 2026 (released October 29, 2026; next release November 5, 2026), its notes and definitions and differences between monthly and weekly data (updated October 8, 2026), and the weekly Lower 48 series; EIA annual total consumption by state, the U.S. monthly consumption series, and the 2024 annual tables for gross withdrawals, marketed production and dry production. The annual capacity tables run through 2024 and a 2025 annual edition is not yet published; the monthly series runs through August 2026. Field-level data are not shown. Alaska is not in the May 2026 report or the weekly series, so Tables 6, 7 and 8 and the design, demonstrated and weekly rows of Table 1 are Lower 48 only, and Table 9 sets Lower 48 storage against U.S. consumption. Ratios, shares, days of use, net winter draws and rankings are calculated from those tables.