New data from the U.S. Energy Information Administration (EIA) shows output rose by about 3 per cent, or 350,000 b/d, compared to 2024. The increase came despite a 5 per cent drop in active rigs and fewer wells drilled, highlighting a structural shift in how U.S. producers are growing supply.

The gains reinforce the United States’ position as the world’s largest oil producer and contribute to expectations of a global supply surplus. Reuters has reported that rising U.S. output is a key factor behind forecasts of an oversupplied global market, with production expected to average roughly 13.6 million b/d in 2025.

Efficiency offsets lower prices

The 2025 production increase came as benchmark West Texas Intermediate (WTI) crude prices fell to about $65 per barrel, down from $77 in 2024. Normally, lower prices would dampen output, but U.S. producers continued to extract more oil from fewer wells.

New wells added 2.9 million b/d of production in 2025, while existing wells accounted for 8.3 million b/d. Industry analysts have increasingly pointed to productivity gains — including longer laterals, improved fracking techniques, and better data analytics — as the main driver of growth.

Bloomberg has similarly reported that U.S. shale producers are pumping more oil per dollar invested, allowing output to rise even as capital spending and rig counts decline.

This decoupling of production from drilling activity marks a significant evolution in the shale sector, where companies have shifted focus from rapid expansion to capital discipline and efficiency.

Permian dominates growth

As in previous years, the Permian Basin remained the engine of U.S. production growth. Output in the region rose by 280,000 b/d in 2025 to reach 6.6 million b/d — nearly half of total U.S. supply.

Low breakeven costs continue to underpin Permian growth. According to the Dallas Fed Energy Survey, operators in the Midland and Delaware basins reported breakeven prices of roughly $61–$62 per barrel in 2025, below the annual average oil price. That cost advantage has allowed producers to sustain output even in a weaker price environment.

By contrast, other major shale regions showed limited growth. Production in the Eagle Ford rose modestly to 1.2 million b/d, while the Bakken saw a slight decline to a similar level.

Together, the Permian, Eagle Ford, and Bakken account for nearly two-thirds of total U.S. crude production.

Offshore projects add supply

Production in the Gulf of America also contributed to overall growth, rising by 111,000 b/d to average 1.9 million b/d in 2025.

Five new offshore projects — Whale, Ballymore, Dover, Shenandoah, and Leon-Castile — came online during the year. Unlike shale operations, offshore developments are less sensitive to short-term price fluctuations due to their long lead times and high upfront capital costs.

This steady pipeline of offshore projects is helping to diversify U.S. supply growth beyond shale basins.

Global implications

The global outlook for oil markets has shifted rapidly in recent weeks. The war in Iran and severe disruptions to shipping through the Strait of Hormuz — which typically carries about one-fifth of global oil — have tightened supply and driven prices sharply higher. With tanker traffic collapsing and infrastructure under attack, the market is moving away from fears of oversupply toward a more constrained and volatile environment.

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Production increased by 5.3 Bcf/d compared with 2024, according to the EIA’s latest Natural Gas Monthly. Three regions — Appalachia, Permian and Haynesville — accounted for 67 per cent of total U.S. marketed gas production and 81 per cent of the growth last year.

Higher natural gas prices helped support drilling activity. The Henry Hub benchmark price rose about 60 per cent in 2025 to US$3.52 per million British thermal units (MMBtu), improving the economics of production across multiple basins.

The Appalachian Basin in the northeastern United States remained the country’s largest natural gas producing region, accounting for 36.6 Bcf/d, or roughly 31 per cent of total U.S. marketed production.

Production growth there has slowed in recent years because of limited pipeline capacity to move gas to markets. However, additional capacity began coming online in 2024 when the Mountain Valley Pipeline was authorized to start operating. Combined with higher gas prices, that helped push Appalachian production up by 1.1 Bcf/d in 2025, compared with only modest growth in 2024.

The Permian Basin in Texas and New Mexico continued to play a major role in U.S. gas growth. Production in the region rose 11 per cent, or 2.7 Bcf/d, reaching an average of 27.7 Bcf/d in 2025.

Much of the natural gas produced in the Permian is associated gas, meaning it is generated as a by-product of oil production. Even though benchmark West Texas Intermediate crude prices declined from US$77 per barrel in 2024 to about US$65 in 2025, prices remained high enough to support oil-directed drilling.

Industry surveys suggest the basin remains economically viable at those levels, with breakeven prices estimated around US$61 per barrel in the Midland Basin and US$62 in the Delaware Basin.

Another factor contributing to higher gas production in the Permian is the region’s rising gas-to-oil ratio, meaning wells are producing more natural gas relative to oil over time.

The Haynesville shale, which spans Louisiana and Texas, also contributed to production growth. Output there averaged 14.9 Bcf/d in 2025, about four per cent higher than in 2024.

Haynesville wells are typically much deeper — between 10,500 and 13,500 feet — than wells in the Appalachian Basin, which generally range from 4,000 to 8,500 feet. The greater depth increases drilling costs, but the basin’s location provides an important advantage.

Haynesville sits close to liquefied natural gas export terminals and large industrial natural gas consumers along the U.S. Gulf Coast, making it an attractive supply source for both domestic and export markets.

The EIA expects U.S. natural gas production to continue growing in the coming years as additional infrastructure and export demand support drilling activity. Expansion of LNG export capacity along the Gulf Coast is expected to play a key role in shaping future natural gas markets.

The United States has been the world’s largest producer of natural gas for more than a decade, largely because of the expansion of shale gas production since the mid-2000s.

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By Troy Cook, Max Ober

Production of associated-dissolved natural gas, or associated natural gas, which is natural gas produced from predominantly oil wells, has nearly tripled since 2018 in the three top-producing tight oil plays in the Permian region.

Associated natural gas from the Wolfcamp, Spraberry, and Bone Spring plays averaged a combined 13.7 billion cubic feet per day (Bcf/d) in the first seven months of 2023, up from an average of 4.7 Bcf/d in 2018, according to data from Enverus DrillingInfo. Associated natural gas production has grown due to increases in both crude oil production and the volume of natural gas per barrel of oil that a well produces, the gas-to-oil ratio (GOR), among the oil wells in these three plays.

Any increase in the GOR in an oil well means more natural gas per barrel of oil is being produced. We define oil wells as those with a GOR of less than or equal to 6.0 thousand cubic feet of natural gas per barrel of oil produced (Mcf/b). We classify wells with a GOR of more than 6.0 Mcf/b as natural gas wells.

The Permian region, which spans parts of western Texas and southeastern New Mexico, produces more crude oil than any other region in the United States, accounting for more than 40 per cent of total U.S. crude oil production. The Permian is the second-largest natural gas-producing region in the country, accounting for about a quarter of total U.S. marketed natural gas production. Most of the natural gas produced in the Permian region is associated natural gas. Consequently, in the Permian region, increased crude oil production has also increased associated natural gas production. Average crude oil production in the first nine months of 2023 increased by 68 per cent in the Permian compared with 2018, while natural gas production in the Permian increased by 104 per cent over the same period, according to our Drilling Productivity Report.

The Spraberry, Wolfcamp, and Bone Spring plays produce most of the associated natural gas within the Permian region. In 2023, these three plays produced 13.2 Bcf/d more associated natural gas than in 2013. Higher crude oil production accounted for 65 per cent of the increase in natural gas production, and 35 per cent of the increase came from a higher GOR, which rose from 2.0 Mcf/b in 2013 to 3.1 Mcf/b in the first seven months of 2023.

As more oil and natural gas are released within a well, the GOR tends to progressively increase, increasing the volume of associated natural gas produced per every barrel of oil. Pressure within the reservoir declines progressively as more oil is brought to the surface, which allows more natural gas to be released from the geologic formation.

We provide a national breakdown of crude oil and natural gas production volumes based on well type classification annually.

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By Naser Ameen, Laia Munoz Cortijo

In 2022, annual production of associated-dissolved natural gas (or associated natural gas) increased 9 per cent to 15.5 billion cubic feet per day (Bcf/d) in the major US onshore crude oil-producing regions, mostly due to an 8 per cent increase in crude oil production. Associated natural gas accounted for more than a third of total natural gas production in the Permian, Bakken, Eagle Ford, Niobrara, and Anadarko regions and 14 per cent of all US natural gas production.

Associated natural gas refers to natural gas that is dissolved in crude oil under the pressure of a geologic formation and is then released when the pressure on the crude oil is relieved by bringing it to the surface.

Increasing crude oil production in the Permian region, which spans parts of western Texas and southeastern New Mexico, is driving the growth in associated natural gas production. Currently more oil is produced in the Permian region, the largest of the five major US crude oil-producing regions, than in the other four regions combined. In 2022, production of crude oil increased in the Permian region by 12 per cent. Associated natural gas production increased by 15 per cent in the Permian region to average 10.2 Bcf/d for the year, and it accounted for 56 per cent of all US associated natural gas production. In recent years, new pipeline takeaway capacity additions have facilitated associated natural gas production growth.

Associated natural gas contains higher ratios of natural gas plant liquids (NGPLs) such as ethane, propane, normal butane, isobutane, and natural gasoline than non-associated natural gas. NGPLs are used as fuel for heating and transportation and as feedstocks to produce plastics, resins, and other petrochemicals. Like associated natural gas production, NGPL production has set several consecutive annual records, rising to an annual average of 5.9 million barrels per day in 2022. The Texas Inland region, which includes much of the Permian region, accounted for 53 per cent of total US ethane production and 49 per cent of total NGPL production in 2022, up from 51 per cent of ethane production and 46 per cent of NGPL production in 2021, according to our Petroleum Supply Monthly.

Information on EIA’s classification of oil and natural gas wells is available in our Drilling Productivity Report Supplement.

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By Martha Pskowski, Inside Climate News & Peter Aldhous

This story was originally published by Inside Climate News and is reproduced by Grist as part of the Climate Desk collaboration.

The prolific oil and gas wells of Texas also generate billions of gallons of salty liquid known as produced water. A lot of this toxic water, just like crude oil, tends to get spilled.

Not just occasionally, but hundreds of times a year. From a large spill of 756,000 gallons into the Delaware River in West Texas that sent chloride levels soaring, to hundreds of small spills in one Permian Basin county, there’s hardly a corner of Texas not impacted. But messy record-keeping and ambiguous rules at the Railroad Commission of Texas, which regulates oil and gas drilling, have long obscured the scope and severity of these spills from the public.

The Railroad Commission has never formally adopted 2009 draft guidelines for reporting and cleaning up produced water spills. The agency delegated the authority to set different reporting thresholds to district offices, in a system that relies on self-reporting by offenders and includes little enforcement to assure accuracy and compliance.

A commission spokesperson said that produced water spills must be reported and that the agency fully investigates and mitigates all spills. But the agency has never adopted official produced water spill guidelines and numerous companies are under the impression they are not required to report spills at all.

Inside Climate News has conducted the first-ever public analysis of produced water spills in Texas, working from data provided in response to open records requests to the Railroad Commission.

Over the decade from 2013 and 2022, the analysis found that oil and gas companies reported more than 10,000 individual spills totaling more than 148 million gallons of produced water. Where possible, companies use vacuum trucks to suck up as much spilled water as they can. But only about 40 percent of the water reported spilled from 2013 to 2022 was recovered.

The spills ranged from small leaks of less than 10 gallons to massive incidents—19 of the reported spills exceeded 500,000 gallons. Although they represented a tiny minority of spills, with about 350 reported in the data, some of the most damaging incidents took place when produced water was spilled directly into streams, rivers or lakes.

Both conventional oil and gas drilling and hydraulic fracturing, or fracking, rely upon large quantities of water, sand and proprietary chemicals, some of which are toxic, to free the oil and gas from geologic formations deep underground. Produced water is the liquid waste that comes back to the surface and contains both the proprietary drilling fluids and naturally occurring hazardous compounds from the earth, including arsenic and organic compounds like benzene, a carcinogen.

The highly saline water can render land barren for years. Residents have filed lawsuits detailing damages from contaminated well water to poisoned cattle.

In East Texas’ Anderson County, cattle rancher Tate Willfong noticed a produced water spill on his property from Vista Energy Consulting’s pipeline in July that killed the grass his cattle graze on. He said he reported the spills to the Railroad Commission but only got help after he went to a local television reporter at KETK in Tyler. Vista Energy Consulting did not respond to a request for comment.

“I ain’t got a beef with the Railroad Commission at this time,” Willfong said. “But I didn’t get a lot out of them in the beginning.”

In Lamesa, the county seat of Dawson County in the high plains where Permian Basin oil production borders cotton farms and towering wind turbines, Doty Huff and Saul Torres filed a lawsuit against an energy firm named Enhanced Midstream, alleging that two leaks from one of the company’s produced water pipelines contaminated their well water and caused a “total loss of fair market value” of their property. Enhanced Midstream did not respond to multiple requests for comment.

In Knox County, North of Abilene, rancher Tim Foote sued after his cattle knocked down a fence around a Texcel Exploration tank where produced water and oil was stored. The livestock came into contact with spilled produced water and 132 cattle died. An appeals court recently upheld a trial court’s decision that the company cannot be held responsible.

“There’s a reason why you salted your enemy’s land in the Bible,” said Sarah Stogner, an oil and gas lawyer in the Permian Basin, who has documented damages from produced water spills. “Nothing grows.”

Spill logs reveal trends

The Railroad Commission records of these spills are not held in a database allowing easy analysis. Instead, they are recorded in chaotically-maintained spreadsheets called “spill logs.” Before running the analysis, Inside Climate News had to diagnose and fix various problems with the data, including inconsistent use of units, incorrectly entered dates, misaligned columns, duplicated entries, misspellings of company names and more.

The totals from the analysis are likely incomplete. Different district offices of the Railroad Commission ask companies to report spills at different thresholds, and the entire system depends on operators self-reporting their mishaps—with little enforcement to ensure that they do so consistently and accurately.

In addition to analyzing the central spill logs provided by the Railroad Commission, Inside Climate News obtained spill logs from its regional offices throughout the state. The analysis of these sprawling records, spread across more than 200 spreadsheet files, gave a similar overall picture, but recorded almost 11 million additional gallons of spilled water.

Further scrutiny of the differences between the central- and district-level records revealed several large spills of produced water recorded at the district level which were not found in the Railroad Commission’s central records. In some cases this was because the corresponding central record had apparently not been updated from an initial entry. Others, including a spill of more than 500,000 gallons in November 2022 from a corroded pipe operated by Occidental Petroleum at a site in Gaines County, seemed to be missing from the central records altogether. Occidental did not respond to a request for comment.

“There have been different systems of tracking spills over time, so there could be differences if you’re comparing different logs,” a Railroad Commission spokesperson said.

Railroad commission leaves produced water spill rules vague

As hydraulic fracturing allowed Texas to rapidly increase oil production, vast amounts of produced water were also generated. But even as fracking transformed the oil and gas industry, the Railroad Commission did not adopt formal rules for reporting and remediation of produced water spills.

A 2022 report calculated that the Permian Basin alone is generating 3.9 billion barrels, or over 168 billion gallons, of produced water a year. That means wastewater must be piped off well pads, stored in tanks and trucked to disposal wells. At each step in the process, the risk for spills is present.

The Railroad Commission currently has 180 oil and gas inspectors statewide. As of July, Texas had over 161,000 oil wells and 86,000 gas wells in production.

The Railroad Commission’s Rule 3.20 requires oil and gas companies to immediately notify a district office after spills of oil or condensate, a low-density hydrocarbon liquid present in natural gas. Those spills are reported on a publicly available Railroad Commission form known as the H-8. Any crude oil spill of over 210 gallons, or five barrels, must be reported. State law prohibits pollution of above-ground or subterranean water.

The H-8 form does not include produced water spills. However, a Railroad Commission spokesperson told Inside Climate News that companies must report produced water spills.

The spokesperson said the Commission issued 116 violations of Rule 3.20 during fiscal year 2022. However, Railroad Commission staff were not able to identify how many of these violations were for produced water spills as opposed to oil spills.

The commission drafted the guidelines for produced water spill cleanup in 2009 that were never formally adopted. The guidelines state that companies are not required to report produced water spills but are “encouraged” to do so, an apparent contradiction of the commission’s statement to Inside Climate News.

This ambiguity has bred confusion. A spokesperson for Apache, a Houston-based oil and gas company operating in the Permian Basin, said the Railroad Commission does not require reporting.

In an email exchange provided to Inside Climate News, a Chevron employee told a Crane County land owner who had complained to the company about a produced water spill on her ranch that the company was not required to report produced water spills. A Chevron spokesperson said the company’s policy is “to follow all RRC requirements for reporting spills, including produced water,” without elaborating.

According to the District 8 office in Midland, which covers the heart of the Permian Basin, companies only must report spills larger than 250 barrels (10,500 gallons) of produced water. But there are many smaller spills on the district spreadsheets, indicating companies may have their own internal standards.

Meanwhile, produced water is included in neighboring New Mexico’s spills rule, which classifies spills of 25 barrels or more as major releases and spills between five to 25 barrels as minor releases. In New Mexico, both major and minor releases are prohibited and must be reported and remediated.

According to the conservation non-profit Center for Western Priorities, during 2022, operators in New Mexico reported 5,085,654 gallons (121,087 barrels) of produced water spills.

Company policies vary

Inside Climate News reached out to the 10 companies with the highest total volume of produced water spills with questions about their internal policies for reporting spills and remediation. Several of the companies have been sold since the spills occurred, in which case the new owners were contacted.

“Texas has robust reporting requirements and cleanup standards for spills that may incidentally occur during oil and gas production,” Permian Basin Petroleum Association President Ben Shepperd said in a statement. “Oil and gas operators in the Permian Basin each have best practices they follow for handling produced water.”

An Apache spokesperson said the company takes “strict measures to store and transport produced water in a manner that reduces the risk of impacts on soil, groundwater and surface water quality.”

The spokesperson said the company reports any spill larger than 100 barrels (4,200 gallons) that “breaches secondary containment or may be deemed sensitive.”

A spokesperson for ExxonMobil, in reference to its subsidiary XTO Energy, said the company complies “with the reporting requirements of the Texas Railroad Commission” but did not elaborate. The spokesperson said remediation depends on salinity and soil type.

Diamondback Energy, which is not on the top 10 list, but in 2019 acquired Energen, which appears on the list, is one of the few companies to include produced water spill data in its annual sustainability reports. According to the Midland-based company’s 2023 report, spills increased 67 percent from 2021 to 2022.

Ashley Watt, the owner of Antina Ranch in Crane County who complained to Chevron about a 2020 spill on her property that she said killed a number of mesquite trees, said oil and gas operators in the Permian Basin often fail to report spills to the Railroad Commission.

“I have never seen an operator self-report anything. Full stop, that’s it,” Watt said. “How many speeding tickets would be written if the only way that you got caught was self-reporting?”

Watt said her property alone has “hundreds of wells” and “hundreds of miles of flow lines,” which transport oil and gas. Watt said landowners, let alone inspectors, are unable to regularly check on every well or pipeline.

“It’s almost just luck when us or anyone catches a spill,” she said.

Watt said a Chevron representative eventually told her that produced water is not included in the Railroad Commission “definition of spills required to give notice” and the company would not be reporting the spill to the Railroad Commission.

A Chevron representative declined to comment on the spill.

Railroad commission spill response protocol

Although the Railroad Commission spokesperson told Inside Climate News that the agency requires remediation of all spills, records and interviews show that the commission only required cleanup after some spills, not all.

Apache reported that a storage tank spilled 77,500 barrels (3,255,000 gallons) of produced water on July 29, 2020 in Reeves County, about 10 miles north of Balmorhea, Texas.

According to documents provided in a records request, Railroad Commission inspectors visited the spill area, which covered approximately one-quarter mile by one-half mile, on July 29, Sept. 8 and Nov. 12, 2020. During each inspection, the RRC noted produced water pooled on the ground, heavy salt crystals and distressed vegetation.

On Nov. 17, the Commission moved to sever Apache’s lease because the spill violated state rules. Apache contacted the Commission to appeal. On Jan. 26, 2021, District 8 Director Jeffery Morgan replied, siding with Apache.

“After further review, no further action will be needed for this site at this time,” Morgan wrote.

Apache kept the lease. The Railroad Commission did not require remediation or issue any penalties.

An Apache spokesperson said regulators and the company agreed that it would be “more harmful” to dig up the soil instead of allowing rainfall to dilute the produced water.

The Commission spokesperson said companies are required to remove as much of the liquid as possible after spills and in some cases remove the contaminated soil. But experts said the agency should take a more holistic approach to remediation.

In the case of the 756,000 gallon spill from a flow line into the Delaware River in West Texas, the Railroad Commission’s Midland District Office was notified immediately on Aug. 1, 2017, but took a back seat to other agencies in monitoring potential pollution.

The event occurred after a Cimarex Energy saltwater disposal unit in Culberson County lost power during a rainstorm. Roughly 18,000 barrels of produced water—or 756,000 gallons, more than enough to fill an Olympic-sized swimming pool—spilled from the flow line into the Delaware River, in addition to 420 gallons of oil. The river is home to the endangered Texas hornshell mussel.

The produced water had chloride levels between 80,000 and 100,000 parts per million. The EPA recommends drinking water not exceed 250 parts per million.

On Aug. 4, a staff member at the Texas Commission on Environmental Quality emailed a colleague after a counterpart in New Mexico had told her about the spill. “Did they notify y’all about this?” she asked. “We obviously have concerns. Do we have anyone checking this out?”

On Aug. 5, the Texas Parks and Wildlife Department documented a fish kill in the Delaware River, including minnows, perch and carp. A Railroad Commission inspector, Glenn Gainey, visited the site on Aug. 7 and district engineering specialist Wade Goode met with company executives two days later.

“I had a meeting with Cimarex representatives to discuss the progress on the remediation, the plan going forward, and to get water sample test results,” Goode wrote in an inspection update. “Cimarex informed me the booms they deployed have not seen any oil sheen.”

The Environmental Protection Agency sent their own inspectors on Aug. 9. By Sept. 21, the company seemed to think remediation was wrapping up.

“We conducted a flyover this past Thursday and since we are not observing any sheening or negative impacts to the river or surrounding shoreline, Cimarex will be discontinuing this operation,” a Cimarex supervisor wrote.

The EPA disagreed. The agency’s Region 6, which covers Texas and New Mexico, eventually issued a consent agreement requiring Cimarex to pay a $13,220 penalty and continue water testing for three years on a 40-mile section of the Delaware River.

Cimarex Energy has since merged with Cabot Oil & Gas to create Coterra Energy, which did not respond to a request for comment.

The involvement of EPA, TCEQ and other agencies in the Cimarex spill was, in many ways, atypical. For most produced water spills, the Railroad Commission acts on its own. A TCEQ spokesperson said while the Railroad Commission has jurisdiction over produced water spills, the TCEQ may initially respond to reports of spills.

A spokesperson for EPA Region 6 said the Railroad Commission is not required to notify federal officials about produced water spills, unlike crude oil spills over a certain size.

The Railroad Commission’s 2009 draft guidelines for cleaning up produced water spills focus on reducing chloride levels in soil and identifying potential groundwater contamination. The guidelines also recommend testing for additional contaminants, including benzene, toluene and metals in some cases.

Stogner, the attorney, said in practice, many companies in the Permian Basin simply remove the soil and replace it with caliche, a sedimentary rock common in the area. She said the remediated areas are unfit for any other productive use like agriculture. Stogner is running against incumbent Railroad Commission Chair Christi Craddick as a member of the Forward Party. In 2022, she unsuccessfully challenged Commissioner Wayne Christian.

John Lacik has used his proprietary soil amendment for produced water spills on sites from North Dakota to Louisiana. He advocates for remediating the soil onsite, instead of trucking in soil or rock. Lacik, who now owns the Texas-based remediation company Gromega LLC, said chloride shouldn’t be the only constituent considered in remediation.

“Treatment types have to be based and determined on each site,” Lacik said. “If there was a cure-all fix, we’d be using it everywhere.”

Experts agreed the problem of salty produced water spills in Texas isn’t going away any time soon. But Lacik said there are solutions for those willing to look for them.

“Maybe I’m just a dreamer on this,” Lacik said. “But the good Lord only made so much land. What is the cost limit to restore land so that it will be productive again?”

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This article was published by the US Energy Information Administration on Jan. 24, 2020.

US oil production from tight formations increased in 2019, accounting for 64 per cent of total U.S. crude oil production. This share grew because of the increasing productivity of new wells that were brought online during 2019.

Since 2007, the average first full month of oil production from new wells in regions tracked by the U.S. Energy Information Administration’s (EIA) Drilling Productivity Report (DPR) has increased.

The growing initial production rates have helped oil production from tight formations to increase despite the slowdowns in drilling activity when oil prices fell between 2015 and 2016. Since 2017, recovering oil prices and more efficient production from new wells have helped producers cover costs of drilling, production, and the development of new technologies.

The average new well in each DPR region produced more oil in 2019 than wells drilled in previous years in those same regions. This trend has persisted for more than 10 consecutive years.

More effective drilling techniques, including the increasing prevalence of hydraulic fracturing and horizontal drilling, have helped to increase these initial production rates. In particular, well productivity was improved because of the injection of more proppant during the hydraulic fracturing process and the ability to drill longer horizontal components (also known as laterals) and perforate more stages.

Increasing well productivity has supported crude oil production even in years such as 2015, when oil prices fell and rig counts dropped. In 2016, rig counts continued to decline sharply, and total U.S. crude oil production decreased for the first time in 10 years. Fewer wells were drilled; however, those that were drilled were drilled more quickly and located in more productive areas, which led to increasing per-well production.

Rig counts have fluctuated throughout 2019 in all DPR regions. The aggregate rig counts declined 16 per cent in the first 11 months of 2019. Despite the decrease in rig count, producers are capable of drilling more efficient wells faster to keep U.S. crude oil production growing.

Oil producers have increasingly targeted the Permian region, which spans parts of western Texas and eastern New Mexico. The geological structure in the Permian region is more complicated than in other regions, and it took producers more time to advance the drilling and completion technology in the region.

However, the Permian region is larger and has more potential for oil production than other regions. Total production and production per new well have increased in the Permian region for 13 consecutive years. In the other four DPR oil regions, oil production fell from 2016 to 2017 because of low oil prices. In Eagle Ford, oil production in 2019 is still lower than its peak in 2015.

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This article was published by the US Energy Information Administration on July 8, 2019.

US crude oil production and lease condensate reached another milestone in April 2019, totalling 12.2 million barrels per day (b/d), according to EIA’s latest Petroleum Supply Monthly.

April 2019 marks the first time that monthly US crude oil production levels surpassed 12 million b/d, and this milestone comes less than a year after U.S. crude oil production surpassed 11 million b/d in August 2018.

Texas and the Federal Offshore Gulf of Mexico (GOM), the two largest crude oil production areas in the United States, both reached record levels of production in April at 4.97 million b/d and 1.98 million b/d, respectively. Oklahoma also reached a record production level of 617,000 b/d.

The U.S. onshore crude oil production increase is driven mainly by developing low permeability (tight) formations using horizontal drilling and hydraulic fracturing. EIA estimates that crude oil production from tight formations in April 2019 reached 7.4 million b/d, or 61 per cent of the US total.

The Permian Basin in western Texas and eastern New Mexico continues to drive record national oil production growth. The Permian’s prolific tight oil plays with multiple layers—including the Bone Spring, Spraberry, and Wolfcamp—make it one of the lower-cost areas to develop.

The Permian Basin accounts for about 63 per cent of Texas and 96 per cent of New Mexico crude oil production. From January 2018 to April 2019, Texas crude oil production increased by 1.1 million b/d (28 per cent) and New Mexico production increased by 345,000 b/d (64 per cent).

Despite pipeline capacity constraints, the Permian region’s month-over-month growth averaged nearly 100,000 b/d for almost all of 2018. Industry efficiencies in pipeline utilization and increased trucking and rail transport in the region have allowed crude oil production to continue to grow.

In the latest Short-Term Energy Outlook, EIA forecasts that Permian production will average 4.4 million b/d in 2019, a 920,000 b/d increase from its 2018 average.

EIA forecasts GOM production to average 1.9 million b/d in 2019, making this region the second-largest contributor to crude oil production growth from 2018 to 2019. The forecasted growth is driven by 14 new fields brought online in 2018 and 9 new fields expected to come online in 2019.

These 23 fields collectively are expected to contribute more than 200,000 b/d of the total 1.9 million b/d of GOM production in 2019.

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Rising Permian oil prices narrow gap with WTI Cushing and Magellan East Houston oil prices

By Jeff Baron

This article was published by the US Energy Information Administration on March 27, 2019.

Crude oil prices in the Permian region have increased since the beginning of the year as two recent pipeline capacity additions reduced some of the takeaway constraints that developed in the middle of 2018. These transportation constraints had forced producers to use more expensive ways to transport crude oil, resulting in lower received prices.

The difference between the West Texas Intermediate-Midland (WTI Midland) crude oil price compared with WTI Cushing and Magellan East Houston crude oil prices began narrowing in September 2018, and they narrowed further in late January 2019.

WTI Midland reflects crude oil prices in the Permian production region of western Texas and eastern New Mexico, and Magellan East Houston and WTI Cushing reflect crude oil prices at aggregation points in Houston, Texas, and Cushing, Oklahoma, respectively.

WTI Midland prices are now similar to WTI Cushing, suggesting the previous pipeline capacity constraints from the Permian region to Cushing have been largely removed. Conversely, WTI Midland prices still trade lower than Houston crude oil prices, suggesting that the region still faces some takeaway constraints in shipping Permian crude oil to the U.S. Gulf Coast. Most recently, the difference has been about $7 per barrel, which is less of a discount than in the middle of 2018.

An extension to the Sunrise Pipeline added an estimated 120,000 barrels per day (b/d) of takeaway capacity from the Permian region in early 2019, which increased pipeline capacity to Cushing.

In addition, the Seminole-Red pipeline, which had previously delivered natural gas liquids from the Permian region to the U.S. Gulf Coast, was repurposed to deliver crude oil. Seminole-Red is expected to be fully operational by April, adding an estimated 200,000 b/d of takeaway capacity.

Although EIA expects that growing Permian production could face takeaway constraints again in the coming months, the recent capacity additions could prevent prices from widening back to the levels reached in the second and third quarters of 2018.

New pipelines scheduled to come online in the third quarter will alleviate the remaining takeaway constraints in the Permian region.

The recent changes in price spreads could also reflect takeaway constraints out of Cushing, Oklahoma, particularly during refinery maintenance season. Because many refineries in the Midwest use the Cushing crude oil storage hub for operating inventories and some refineries have reduced crude oil intake for maintenance, the overall outflow from Cushing has declined. As a result, Cushing crude oil stocks increased by 4 million barrels from the first week in February through March 15. A similar phenomenon also occurred last October.

Growing inventories, reduced refinery runs, and limited pipeline takeaway capacity from Cushing to the U.S. Gulf Coast is likely contributing to a widening of the Brent crude oil price spread with WTI Cushing. The Brent–WTI Cushing spot price spread averaged $9/b in February, the second-widest level for any month in five years.

In the March Short-Term Energy Outlook, EIA forecasts the Brent–WTI crude oil price spread will continue to average $9/b until June 2019. As new pipeline capacity from the Permian region comes online in the third quarter, Permian producers and shippers will have more options to ship crude oil to the U.S. Gulf Coast, which could reduce inflow to Cushing, slow inventory builds, and narrow the Brent–WTI price spread later this year.

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Most methanol plants are located on US Gulf Coast, close to natural gas sources and export facilities

By Naser Ameen, Kristen Tsai

This article was published by the US Energy Information Administration on Feb. 21, 2019.

New methanol plants under development in the United States are increasing natural gas consumption in the industrial sector. Methanol plants are among the most natural gas-intensive industrial end users and require natural gas both as a feedstock and for process heat.

Three new plants expected to come online in 2019 and 2020 have a combined nameplate capacity of about 3.3 million metric tons per year (MMmt/y) and would increase total U.S. methanol capacity to 9.4 MMmt/y, or 25,600 metric tons per day (mt/d)—a 45 per cent increase from the current U.S. capacity.

Methanol has several energy-related applications. Pure methanol can be used directly as an alternative transportation fuel (China, in particular, uses methanol this way) or blended into motor gasoline abroad to increase combustion efficiency and reduce air pollution.

EIA forecasts that new methanol projects will help drive growth in industrial natural gas demand through 2020. Total U.S. industrial natural gas consumption is expected to average 23.1 billion cubic feet per day (Bcf/d) in 2019 and 23.4 Bcf/d in 2020, up from 22.6 Bcf/d in 2018.

Most methanol plants are located in the Gulf Coast region. Existing pipeline infrastructure in the region will allow increasing natural gas production from the Permian Basin in western Texas and eastern New Mexico to reach methanol production facilities along the Gulf Coast. Proximity to the Gulf Coast allows many of these plants to export methanol to China, a major consumer of methanol.

Relatively low natural gas prices in recent years have provided incentives to develop new methanol facilities. Natural gas prices in the Permian region have been especially low relative to the Henry Hub national benchmark.

In 2018, the discount to the Henry Hub averaged 37 per cent, with Permian prices averaging $1.98 per million British thermal unit (MMBtu), compared with Henry Hub prices of $3.15/MMBtu. Permian region natural gas production—especially associated gas produced from oil directed rigs—has increased, helping reduce feedstock and process heat costs for these facilities.

One new methanol plant, the 5,000 mt/d Natgasoline methanol plant in Beaumont, Texas, began operating in June 2018. According to the operating companies (OCI N.V., Consolidated Energy Limited and Natgasoline LLC), the plant has consistently been running above its nameplate capacity.

The new plant is the largest methanol production facility in the country, consuming an estimated 0.15 Bcf/d of natural gas.

During 2019 and 2020, two new methanol plants on the Gulf Coast are expected to begin operating. Big Lake 1, owned by GX2 Energy and Methanol Holdings, Trinidad, is expected to enter service during the third quarter of 2019 in Louisiana. The Big Lake facility will convert dry natural gas into about 3,800 mt/d of methanol, which may then be converted to motor gasoline.

In addition, the Yuhuang’s St. James 1 methanol plant, with a capacity of 4,700 mt/d, is expected to start operating in mid-2020 and would be the second-largest methanol facility in the United States. Phase two, which is currently under consideration, could double its capacity, which would make it the largest methanol production facility in the United States.

In addition to these Gulf Coast methanol plants, Liberty One in West Virginia is expected to produce about 550 mt/d of methanol when it comes online in 2019. Liberty One is a much smaller methanol-producing facility that is relocating from Rio De Janeiro, Brazil. Liberty One’s proximity to the Appalachia Basin ensures natural gas feedstock at a relatively low cost to the plant.

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Wolfcamp play the deepest and thickest stacked shale formations in Permian

By Olga Popova, Chris Peterson, Jason Upchurch and Kyra White

This article was published by the US Energy Information Administration on Nov. 16, 2018.

Increased oil and natural gas development in the Wolfcamp play has helped drive overall crude oil and natural gas production growth in the Permian Basin during the past decade.

Drilling and completion operations within the Wolfcamp play have been responsible for much of the crude oil and natural gas production growth in the Permian Basin since 2007.

As of September 2018, the Wolfcamp accounted for about 1 million barrels of crude oil per day (b/d) and 4 billion cubic feet of natural gas per day (Bcf/d). Crude oil production in the Wolfcamp accounts for nearly one-third of total Permian crude oil production and more than one-third of Permian natural gas production.

Rising productivity in the Wolfcamp, like in other plays in the Permian Basin, has been driven mostly by drilling longer horizontal laterals and optimizing completions.

The length of the horizontal segments, or laterals, in the Wolfcamp increased from an average of 2,500 linear feet in 2005 to more than 8,500 linear feet in 2018.

Well completion efficiency has also improved, primarily by more effectively using sand, or proppant, during the hydraulic fracturing process, as well as by using zipper fracturing—the completion of two or more wells side by side.

The number of producing wells in the Wolfcamp increased from 2,200 in 2005 to 7,750 in mid-2018.

Average initial daily crude oil production per well for the first six months of operation grew from 37 b/d to 515 b/d, and average natural gas production per well for the first six months of operation grew from 0.1 million cubic feet per day (MMcf/d) to 2.0 MMcf/d during the same period.

EIA expects Wolfcamp production to continue to drive production increases in the Permian region, although pipeline capacity constraints in the region are expected to slow the rate of growth through 2019.

 

The Wolfcamp formation extends across the Delaware Basin, Central Basin Platform, and Midland Basin—the three sub-basins that comprise the Permian Basin.

The stacked formation has four intervals, called benches, which are designated from top to bottom as A, B, C, and D. Most of the current drilling activities take place in the Delaware and Midland Basins and target the Upper Wolfcamp (benches A and B), which is more oil-rich, rather than the Lower Wolfcamp (benches C and D), which is more natural gas-rich.

Of the stacked shale formations that comprise the Permian Basin, the Wolfcamp is the deepest and thickest but varies significantly across the formation.

Wolfcamp subsea depth varies in the Delaware Basin from 0 feet in the west to 9,500 feet in the central areas. In the Midland Basin, the subsea depth ranges from 2,000 feet in the east along the Eastern Shelf to 7,000 feet along the basin axis, near the western basin edge.

Wolfcamp thickness ranges from about 800 feet to more than 7,000 feet thick in the Delaware Basin, and thickness ranges from 400 feet to more than 1,600 feet thick in the Midland Basin, varying from 200 feet to 400 feet in the adjacent Central Basin Platform.

More information on crude oil and natural gas production is available in EIA’s Drilling Productivity Report and Monthly Crude Oil and Natural Gas Production Report.

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