Why Waha Natural Gas Prices Go Negative

Waha natural gas prices go negative when Permian Basin gas output fills the pipelines that carry it out of West Texas. Because most of that gas comes up with oil, producers keep it flowing and pay buyers to take it. EIA reported Waha below zero on 45% of trading days in 2024 by late August, a low of -$6.41 per MMBtu on August 29, 2024, and a September 2025 average of -$0.64, the lowest for any September on record.

The arithmetic behind those prints is visible in EIA’s own production numbers. Permian marketed gas output rose from 20.07 billion cubic feet per day (Bcf/d) in 2022 to 27.55 Bcf/d in 2025, a gain of 7.48 Bcf/d. Over the same three years, the takeaway projects in Table 3 added 3.55 Bcf/d, and 2025 added none. The rest had to find room in existing lines, local demand, or a lower price. The Permian Basin production outlook covers the oil side of the same basin.

What a price below zero at Waha actually means

Waha is a trading point on the border of Reeves and Pecos counties in West Texas, where gathering systems and processing plants from the Delaware and Midland basins hand gas to long-haul pipelines. The Waha spot price is what a buyer pays for gas delivered there for the next day. A price of -$2.00 per million British thermal units (MMBtu) means the seller pays the buyer two dollars for each MMBtu taken off its hands. The buyer still has to move or use that gas, so a negative price is really the cost of finding a spot in a full pipe or a full local market.

Henry Hub in Louisiana is the national benchmark and the delivery point for NYMEX futures. Every regional hub trades at a premium or discount to it, and that difference is called the basis. When the Waha basis is a few cents, Permian gas is moving freely to the Gulf Coast, Mexico and the West. When it is several dollars, the pipelines are full and the marginal molecule at Waha is worth much less than the same molecule in Houston or Louisiana. Our guide to Henry Hub explains how the benchmark is set and why local hubs drift away from it.

Negative prices are not unique to Texas gas; power markets see them when wind and solar output exceed demand. What is unusual about Waha is how often it happens. In 2024 a negative close was the more likely outcome on any given trading day for months at a stretch, and every day from July 26 into September was below zero. That frequency is the clearest sign that the price problem is structural (too little pipe for too much gas) rather than a one-off accident.

Waha minus Henry Hub, quote by quote

Daily Waha prices are compiled by commercial reporters (Natural Gas Intelligence, LSEG and others) and are not a free EIA data series. EIA did quote the Wednesday Waha price, and its gap to Henry Hub, in most issues of its Natural Gas Weekly Update. Table 1 lists eleven of those quotes from March 2024 to December 2025, each from the issue that printed it.

The spread in these quotes ranged from -$0.38 on Dec 4, 2024 to -$7.96 on Dec 10, 2025. Two things move it. Henry Hub itself is one: on December 10, 2025, Henry Hub was at $4.61 while Waha sat at -$3.35, so a strong national price and a weak local one combined into the widest gap in the table. The Waha side is the other, and it can jump several dollars in a week when a pipeline comes back from maintenance. Between December 10 and December 17, 2025, Waha rose $3.72 as El Paso Natural Gas finished work on parts of its North and South Mainlines, while Henry Hub fell 94 cents.

The calm stretch in the table, from late November 2024 to late January 2025, was the first winter after Matterhorn Express started. Waha traded above zero on every day from January 1 to January 29, 2025, according to EIA, compared with below zero on 36% of trading days in the fourth quarter of 2024. By mid-March 2025 the negative prints were back.

EIA’s longer averages tell the same story at lower resolution. In its September 10, 2024 Today in Energy article, EIA said Waha had traded an average of $2.07 below Henry Hub so far in 2024, against an average of 42 cents below in the second half of 2021. In September 2022, it put the 2019 average at $1.66 below Henry Hub, the previous period when Permian gas growth outran new pipe. For the national price that sets the other end of the spread, see why natural gas prices go up and down.

How often Waha closed below zero

Counts of negative days come from the same commercial daily data, so the only counts given here are the ones EIA itself printed, with the date it printed them:

Two readings follow. First, 2025 as a whole was much less negative than 2024 (16% of trading days through October 1, against 45% to 46% at a similar point in 2024), which is what a 2.5 Bcf/d pipeline starting in late 2024 would predict. Second, the September 2025 average of -$0.64 was the lowest for any September on record, below September 2024’s $0.03, which shows that a basin with little spare pipe can still post a record-weak month after relief arrives if maintenance and growth line up. EIA tied that September to force majeure and maintenance events that limited pipeline capacity.

Permian takeaway pipelines and when each started

The Permian’s large takeaway lines are mostly intrastate Texas pipelines, regulated by the Railroad Commission of Texas rather than the Federal Energy Regulatory Commission. That is why no single federal docket lists them. EIA’s Natural Gas Pipeline Projects Tracker does, compiling FERC filings, Texas permits, company sites and SEC filings. Table 3 is built from its August 4, 2026 release, updated where EIA or an operator published something newer.

Matterhorn Express is the hinge of the recent history. EIA’s tracker records it as completed on September 15, 2024, with 2.5 Bcf/d from Waha to Katy; project partners and market reporting dated its first commercial flows to October 1, 2024. Waha had closed below zero every day from July 26 into September; by October 2, 2024 it was at $1.47, its highest since July 10, EIA reported. The relief was uneven: the spread widened back to $3.58 the following week, Waha settled at -$3.14 on October 28 and went negative again in early November, and only from late November did the basis settle. Then nothing of similar size followed for almost two years. Two large proposals, Williams’ Bluebonnet Market Express and Kinder Morgan’s Permian Pass, were marked cancelled in the tracker in October 2025, and Targa’s Apex, which Targa expected in service in 2026 when EIA wrote about Permian pipelines in September 2024, is now listed as on hold.

What changed in 2026

Three projects moved in 2026. The Gulf Coast Express expansion, a compression-only project adding 0.57 Bcf/d to the 2019 line, is listed as completed. Energy Transfer’s Hugh Brinson pipeline, about 400 miles of 42-inch pipe from Waha to Maypearl with 1.5 Bcf/d in its first phase, began flowing ahead of schedule in summer 2026, EIA wrote on October 2, 2026; a second phase of compression is expected to take it to about 2.2 Bcf/d in the first quarter of 2027. Energy Transfer’s project page says Phase I is expected to be in service by the end of 2026; first flows in summer and formal in-service status by year end can both be true. EIA’s tracker, updated July 10, 2026, listed Phase I as in commissioning, with tariffs filed in Texas and at FERC.

Blackcomb, WhiteWater’s 2.5 Bcf/d line from the Permian to Agua Dulce, is the largest piece still pending. EIA said in May 2026 that it was slated for the third quarter of 2026, and the project’s own website still shows a third-quarter date. The tracker row updated July 6, 2026 is newer and says the in-service date was pushed back from July to November 2026. As of October 31, 2026, neither EIA nor the operator had announced that Blackcomb was in service.

Beyond 2027 the queue thins out and then fills again. WhiteWater upsized Eiger Express to 3.7 Bcf/d in November 2025 and kept a mid-2028 target. The 2.8 Bcf/d Saguaro Connector, from Oneok’s WesTex system at Waha to Mexico, is approved but delayed; on April 10, 2026 its developer asked FERC for more time, citing delays in Mexican LNG. Transwestern’s Desert Southwest expansion was enlarged in December 2025 to as much as 2.3 Bcf/d for late 2029. And on October 21, 2026, Kinder Morgan said NGPL had taken a final investment decision on Permian Link, roughly 2.8 Bcf/d on about 434 miles of new pipe, backed by take-or-pay contracts to serve power generation for a data center customer, with service expected in the third quarter of 2030.

Not every line in the tracker relieves Waha directly. Traverse, a WhiteWater-led pipeline between Agua Dulce and Katy due in 2027, moves gas along the coast after it has already left the basin, so it is left out of Table 3. Its tracker row also shows two capacities (2.4 Bcf/d in the capacity column, up to 1.75 Bcf/d in the notes). Smaller connectors that gather gas to Waha, such as Targa’s Bull Run extension and the Forza pipeline, add supply at the hub rather than taking it away.

Production growth against new pipe, year by year

Adding up the capacity in Table 3 and setting it against total production would be misleading, because the table leaves out older pipelines and because part of Permian output is used or processed inside the basin. The fairer test is the increment: how much new gas each year had to find a home, and how much new pipe opened that year.

From 2023 through 2025 Permian marketed gas grew by 2.72, 2.16 and 2.60 Bcf/d. New pipe matched that only in 2024, the Matterhorn year. 2025 had the second-largest increase in production and no new long-haul line, and it produced the lowest September average on record and a $7.96 spread in December. 2026 looks better on paper: about 1.98 Bcf/d of new gas against 2.07 Bcf/d of new pipe, plus another 2.5 Bcf/d if Blackcomb starts in November. That is consistent with EIA’s October 2026 description of new pipelines easing long-standing bottlenecks. But EIA’s forecast for 2027 adds 2.50 Bcf/d of gas against only Hugh Brinson’s second phase, so the margin shrinks again until Eiger Express in 2028.

Three caveats keep Table 4 honest. First, marketed gas is measured before processing, and pipelines carry the residue gas left after natural gas liquids are removed. Nationally, EIA’s 2025 dry production was about 91% of marketed production (107.64 against 118.42 Bcf/d in the October 2026 Outlook), and liquids-rich Permian gas loses more volume in processing than average, so the gas that needs pipe is smaller than the marketed figure. Second, part of the gas is burned in the basin itself, in compressors, power plants and, from 2026, data center supply laterals such as the ones Energy Transfer is building off Hugh Brinson for Oracle’s Abilene site. Third, a pipeline’s nameplate capacity is not delivered on every day, as the next section shows.

The gas-oil ratio column explains why gas growth outruns oil growth. EIA wrote in June 2026 that the Permian ratio averaged nearly 4,200 cubic feet per barrel in 2025, up 16% from 2021, as reservoir pressure falls in maturing wells. Holding the 2021 ratio, EIA estimated, the basin would have produced 3.8 Bcf/d less gas in 2025. The implied ratio in Table 4 keeps rising through the forecast, so even flat oil output would add gas every year. Our page on the shale breakeven price covers why operators keep drilling for the oil anyway.

Why maintenance turns a tight system negative

Almost every sharp drop in Table 1 has a named pipeline event behind it. When capacity is short by only a few percent, losing one compressor station or one segment of pipe can strand hundreds of millions of cubic feet a day. EIA’s weekly notes from 2024 and 2025 give a dated list:

• February 19, 2024: El Paso Natural Gas declared force majeure on Line 2000, cutting westbound flows through the Gila constraint toward Arizona and California. Waha fell to $0.41 the next day. El Paso lifted it on July 5, and Waha rose above zero on July 8.
• March 2024: Waha was negative every day from March 11, which EIA put down to warm weather and maintenance on the El Paso system, which delivers Permian gas westbound.
• April 26, 2024: Kinder Morgan declared force majeure on NGPL’s Lockridge Lateral in its Permian zone, and Waha hit an intraweek low of -$2.13. On May 6 it reached -$4.60.
• November 2024: the 2.6 Bcf/d Permian Highway Pipeline finished end-of-year inspections and returned to full service, and Waha rose $2.45 in a week, from -$0.83 to $1.62.
• September 2025: force majeure and maintenance events limited pipeline capacity, EIA wrote, and 14 of the year’s 30 negative days fell in that month.
• Late October and early November 2025: El Paso capacity cuts on westbound flows, unplanned Transco work affecting southbound flows, and integrity assessments affecting northbound flows all hit in the same week. Waha fell from $0.74 to -$1.02.

The pattern explains why Waha can be fine one week and deeply negative the next. A basin with 2 Bcf/d of spare pipe shrugs off a 0.5 Bcf/d outage. A basin with no spare pipe has to shed that volume by price, and the price falls until some buyer with flexible capacity, a storage operator or a power plant takes it, or until a producer cuts output. Many of the negative stretches in Table 2 fall in March, April, September and October, the shoulder months between heating and cooling seasons, when pipeline work is often scheduled.

Why associated gas keeps flowing below zero

A dry gas well in Louisiana that gets a negative price can be choked back. A Permian oil well is different: its gas comes out with the oil, in a ratio set by the reservoir. To produce less gas the operator has to produce less oil, and oil is the product that pays. That one fact explains most of the Waha market.

The barrel pays for the gas

The arithmetic runs in three steps. Start with EIA’s 2025 Permian gas-oil ratio of about 4,200 cubic feet per barrel. Multiply by EIA’s 2025 average heat content for consumed natural gas, 1,036 Btu per cubic foot: 4,200 cf/b × 1,036 Btu/cf = 4,351,200 Btu, or about 4.35 MMBtu of gas per barrel of oil. Then price that gas at Waha and compare it with the oil.

Even the worst case, the -$6.41 low of August 29, 2024, cost about $27.89 a barrel when WTI averaged $76.68 that month. A producer would rather not pay that, but cutting the oil to avoid it would forfeit the far larger oil revenue. At the September 2025 monthly average, the gas cost about $2.78 a barrel, roughly 4.4% of WTI. That is why EIA keeps describing Permian gas as a by-product: the decision to drill is made on the oil price, and the gas price is something operators absorb.

The oil price backdrop in 2026 makes that even more true. EIA’s October 2026 Outlook puts WTI at an average of $97.31 for September 2026, after Middle East supply disruptions lifted prices from $60.04 in January. At that oil price, the same -$2.50 gas would cost about 11.2% of the barrel. High oil prices encourage more drilling in exactly the basin where gas has nowhere to go, so the price signal for oil pushes against the price signal for gas.

Real producers rarely sell every molecule at the daily Waha print. Many hold firm capacity on long-haul pipes and sell at Gulf Coast prices; others sell on monthly index prices set before the month begins; and gathering and processing contracts often oblige a processor to take the gas regardless of the hub price. The pain of a negative print falls hardest on uncontracted volumes and on whoever owns gas at Waha that day. A single day at -$6.41 is headline-grabbing; a month of averages near zero is what actually shows up in quarterly results.

The liquids ride along

Permian gas is wet: processing plants strip out ethane, propane, butanes and natural gasoline before the residue gas goes into a pipeline. Those liquids sell on Gulf Coast prices that have nothing to do with Waha. EIA reported in March 2025 that U.S. ethane production reached a record 2.8 million barrels per day in 2024, driven by more ethane recovery in the Permian, and that 63% of all U.S. ethane came from the two refining districts that cover the basin, Texas Inland and New Mexico. For a well owner, the liquids are a second paying product attached to the same gas stream. A negative residue price trims the value of the stream; it does not erase it.

Flaring is a narrow escape valve

If pipes are full and prices are negative, why not burn the gas? Both states that share the basin restrict that. In Texas, the Railroad Commission’s Statewide Rule 32 (16 Texas Administrative Code §3.32) lets operators flare while drilling and for up to 10 days after completion for well testing. Beyond that they need an exception, which commission staff grant for 45 days at a time up to 180 days; longer periods require a Commission Final Order. The commission lists full existing pipelines as one reason flaring may be needed, and says extensions most often go to operators waiting on pipeline construction.

New Mexico is stricter. Its rule, 19.15.27 NMAC, effective May 25, 2021, prohibits venting or flaring that constitutes waste and requires each operator to capture at least 98% of the gas produced from its wells in each of two reporting areas by December 31, 2026, two months from this writing. An operator on the New Mexico side of the Delaware Basin cannot simply flare its way around a full pipe; it has to sell the gas at whatever Waha pays, or cut production.

The volumes show the effect. EIA’s vented-and-flared series for Texas fell from 251,186 million cubic feet in 2019 to 163,512 in 2024, a 34.9% drop, and New Mexico’s fell from 37,294 to 17,026, down 54.3%. Those statewide totals include basins other than the Permian, but the direction matters. In 2019, flaring absorbed part of the surplus. By 2024, with New Mexico’s capture rule phasing in and Texas exceptions capped at 180 days without a Commission order, less of it could be burned, which leaves price as the main way to clear it. Our natural gas flaring by state page has the full state series and rules.

Signals worth watching into 2027

Since the Natural Gas Weekly Update ended, readers who follow the basin have to watch the inputs instead. Four are public and dated:

1. Blackcomb’s start date. A November 2026 start would add 2.5 Bcf/d, more than all of 2026’s other additions combined. A slip into 2027 would leave the basin to absorb another winter of growth with Hugh Brinson Phase I alone.
2. EIA’s monthly Permian gas estimate. The Short-Term Energy Outlook shows Permian marketed gas at 29.5 Bcf/d for 2026 and 32.0 Bcf/d for 2027. Each upward revision to 2027 eats into the room that new pipes create.
3. Pipeline maintenance notices. El Paso, Transwestern, NGPL and the Texas intrastate lines post outages on their bulletin boards. The 2024 and 2025 record shows that a week of major work can push Waha negative even in a year with new capacity.
4. Downstream demand. New Gulf Coast LNG trains and Mexican pipelines are where Permian gas ultimately goes. EIA’s October 2026 Outlook expects U.S. LNG exports to average 17.6 Bcf/d in 2026 and 18.6 Bcf/d in 2027. A delay at an LNG terminal backs gas up through Agua Dulce and Katy to Waha. Our guide to U.S. LNG export terminals tracks those projects.

The record since 2019 suggests a cycle rather than a fix: new pipe opens, Waha recovers, production catches up, and negative prints return until the next line. After Matterhorn, Waha stayed positive from late November 2024 to mid-March 2025, about four months, before the negative prints came back. Hugh Brinson, Blackcomb and Eiger Express together add 8.4 Bcf/d by mid-2028 if they arrive on schedule, which is more than EIA’s forecast production growth for 2026 and 2027 combined. Whether that finally breaks the cycle depends on how fast the gas-oil ratio keeps climbing and on how much new demand inside Texas, from data centers to power plants, shows up to take the gas before it ever reaches Waha.

Data and sources: U.S. Energy Information Administration, Natural Gas Weekly Update, issues from February 2024 to the final issue of January 22, 2026 as dated in the text, including those of February 22, March 21, March 28, April 11, May 2, May 9, July 11, August 15, August 29, September 5, October 3, October 10, October 31, November 7, November 21 and December 5, 2024, and January 30, March 20, October 2, November 6 and December 18, 2025 (weekly archive under eia.gov/naturalgas/weekly/archivenew_ngwu/), read October 31, 2026. EIA Today in Energy: Natural gas pipeline capacity from the Permian Basin is set to increase (September 10, 2024); The Waha Hub natural gas price continues to fall below the Henry Hub price (September 20, 2022); Natural gas pipeline project completions increase takeaway capacity in producing regions (March 17, 2025); U.S. ethane production, consumption, and exports set new records in 2024 (March 20, 2025); Most planned natural gas pipeline capacity additions in 2026 and 2027 originate in Texas (May 26, 2026); Permian natural gas production increased faster than crude oil (June 18, 2026); and U.S. natural gas production reached a record high in July 2026 (October 2, 2026), all read October 31, 2026. EIA, U.S. Natural Gas Pipeline Projects Tracker, release of August 4, 2026, read October 31, 2026. EIA, Short-Term Energy Outlook, October 6, 2026 (text, and spreadsheet tables 2, 4a, 5a), read October 31, 2026. EIA, Heat content of natural gas consumed and vented and flared natural gas for Texas and New Mexico (release of October 30, 2026), read October 31, 2026. Kinder Morgan, Inc., third-quarter 2026 earnings release (Form 8-K Exhibit 99.1, October 21, 2026), read October 31, 2026. Energy Transfer, Hugh Brinson Pipeline project page, and WhiteWater, Blackcomb Pipeline project page, read October 31, 2026. Railroad Commission of Texas, Flaring Regulation FAQs (Statewide Rule 32, 16 TAC §3.32), read October 31, 2026. New Mexico State Records Center and Archives, 19.15.27 NMAC, Venting and Flaring of Natural Gas, read October 31, 2026. Spreads marked as derived, unit conversions, year-by-year growth, gas-oil ratios and the per-barrel illustration are this page’s arithmetic.